98-31671. Onshore Oil and Gas Leasing and Operations

[Federal Register Volume 63, Number 232 (Thursday, December 3, 1998)]
[Proposed Rules]
[Pages 66840-66937]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-31671]

[[Page 66839]]

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Part II

Department of the Interior

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Bureau of Land Management

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43 CFR Part 3100 et al.

Onshore Oil and Gas Leasing and Operations; Proposed Rule

Federal Register / Vol. 63, No. 232 / Thursday, December 3, 1998 /
Proposed Rules

[[Page 66840]]

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DEPARTMENT OF THE INTERIOR

Bureau of Land Management

43 CFR Parts 3100, 3110, 3120, 3130, 3140, 3150, 3160, 3170 and
3180

[WO-310-1310-00-2I-IP]
RIN 1004-AC94

Onshore Oil and Gas Leasing and Operations

AGENCY: Bureau of Land Management, Interior.

ACTION: Proposed rule.

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SUMMARY: The Bureau of Land Management (BLM) is proposing to revise its
Federal oil and gas leasing and operations regulations. This rule uses
performance standards in certain instances in lieu of the current
prescriptive requirements. These proposed regulations cite industry
standards and incorporate them by reference rather than repeat those
standards in the rule itself. Also, BLM's onshore orders and national
notices to lessees would be incorporated into these regulations to
eliminate overlap with existing regulations. This rule would increase
certain minimum bond amounts and would revise and replace BLM's current
unitization regulations with a more flexible unit agreement process.
Finally, this proposed rule would eliminate redundancies, clarify
procedures and regulatory requirements, and streamline processes.

DATES: Comments: Commenters must submit comments by April 5, 1999. BLM
will consider comments received or postmarked on or before this date in
the preparation of the final rule.

ADDRESSES: Comments: If you wish to comment, you may hand-deliver
comments to the Bureau of Land Management Administrative Record, Room
401, 1620 L Street, NW, Washington, D.C., or mail comments to the
Bureau of Land Management, Administrative Record, Room 401LS, 1849 C
Street, NW, Washington, D.C. 20240. Commenters may transmit comments
electronically via the Internet to: WoComment@wo.blm.gov and please
include in your comments the regulation identifier number AC94 and your
name and return address. If you do not receive confirmation from the
system that we have received your Internet message, contact us
directly.

FOR FURTHER INFORMATION CONTACT: Ian Senio at (202) 452-5049 or John
Duletsky at (202) 452-0337 or write to Bureau of Land Management, U.S.
Department of the Interior, 1849 C Street, NW, 401LS, Washington, D.C.
20240.

SUPPLEMENTARY INFORMATION:

I. Public Comment Procedures
II. Background
III. Discussion of Proposed Rule
IV. Procedural Matters

I. Public Comment Procedures

Written Comments

Written comments on the proposed rule should be specific, should be
confined to issues pertinent to the proposed rule, and should explain
the reason for any recommended change. Where possible, comments should
reference the specific section or paragraph of the proposal which the
commenter is addressing. BLM may not necessarily consider or include in
the Administrative Record for the final rule comments which BLM
receives after the close of the comment period (see DATES) or comments
delivered to an address other than those listed above (see ADDRESSES).
You may view an electronic version of this proposed rule at BLM's
Internet home page: www.blm.gov.
Comments, including names, street addresses, and other contact
information of respondents, will be available for public review at this
address during regular business hours (8:00 a.m. to 4:30 p.m.), Monday
through Friday, except Federal holidays. BLM will also post all
comments on its Internet home page (www.blm.gov) at the end of the
comment period. Individual respondents may request confidentiality. If
you wish to request that BLM consider withholding your name, street
address, and other contact information (such as: Internet address, FAX
or phone number) from public review or from disclosure under the
Freedom of Information Act, you must state this prominently at the
beginning of your comment. However, we will not consider anonymous
comments. BLM will honor requests for confidentiality on a case-by-case
basis to the extent allowed by law. BLM will make available for public
inspection in their entirety all submissions from organizations or
businesses, and from individuals identifying themselves as
representatives or officials of organizations or businesses.

II. Background

Oil and gas produced from lands managed by BLM accounted for about
5.7 percent of domestic oil production and about 10.7 percent of
domestic gas production in 1996. BLM has jurisdiction and
responsibility over virtually all aspects of leasing, exploration,
development, and production of oil and gas from onshore Federal oil and
gas and approves and supervises most operations on Indian lands. BLM
administers 52,457 Federal and Indian leases, of which nearly 23,524
are in a producing or producible status. As of December 31, 1996, there
were 70,569 producing or producible wells under BLM's jurisdiction, and
2,347 new wells were drilling during the year. In 1996, more than $6.1
billion of oil and gas and associated products were sold from Federal
and Indian oil and gas leases, which generated $665 million in
royalties.

Mining Law

The Federal Government did not have an oil and gas leasing system
before 1920. However, Federal oil and gas reserves could be developed
under the Mining Law of 1872 (17 Stat. 91, 30 U.S.C. 22 et seq.) after
the applicant located a placer mining claim. If the mining claim was
validated by the location of a valuable discovery, the locator
essentially was entitled to fee title to the lands covered by the
claim. Congress soon realized that the Mining Law was not well suited
for oil and gas development since it resulted in over drilling and
waste of the resources. Congress passed the Mineral Leasing Act of 1920
(41 Stat. 437, 30 U.S.C. 181 et seq.) (MLA) and on February 25, 1920,
the President signed it into law. The MLA still remains the primary
authority under which the Federal Government leases the majority of
Federal onshore oil and gas.

Mineral Leasing Act

There have been several amendments to the MLA that affected the
Federal oil and gas leasing system, but it stayed substantially the
same until the enactment of the Federal Onshore Oil and Gas Leasing
Reform Act of 1987 (Pub. L. 100-203, 101 Stat. 1330-256) (Reform Act).
Before the Reform Act, Federal lands within known geologic structures
(KGS) of producing oil and gas fields were leased competitively to the
highest qualified bidder. Lands not within a KGS were leased ``over the
counter'' basically on a first-come and first-serve basis to qualified
entities.
In 1960, BLM implemented a simultaneous leasing system in order to
address concerns over the potential for fraud in the noncompetitive
leasing system. Under that system, all applications for available
public lands that were received within the time specified in the notice
were considered as received simultaneously. Applications then were
drawn randomly to determine the winner. Only

[[Page 66841]]

a fraction of Federal lands fell into the KGS category and most of the
Federal oil and gas leases that BLM issued were issued noncompetitively
through the lottery. The leasing system operated for many years before
Congress and the public became concerned that BLM's leasing system was
not functioning properly. The primary concern was that the Federal
Government was not receiving fair market value for oil and gas
resources. There was also concern that it was becoming increasingly
difficult for BLM to make KGS determinations, that the leasing system
was subject to fraud and abuse, and that the Bureau was not taking
enough care in protecting the environment affected by development of
Federal oil and gas leases.

The Reform Act

Congress passed the Reform Act on December 22, 1987, to address
concerns over the existing leasing system. The principal change made by
the Reform Act was to require that BLM offer competitively all lands
eligible and available for Federal oil and gas leasing before leasing
noncompetitively. KGS designations were eliminated, environmental
provisions were added, and BLM was required to have Forest Service
consent before leasing oil and gas on Forest Service lands. The Reform
Act also required BLM to post a notice of the lands it proposed to
include in a lease sale. It also required BLM to post a notice of
proposed drilling operations to allow the public and environmental
groups an opportunity to comment before BLM made a final determination.
Congress dealt with fraud and abuse by making it unlawful to be
involved with any plan to defeat the purposes of the Reform Act or its
implementing regulations. The Reform Act also provided for severe
penalties for violating these fraud provisions.
BLM has been leasing Federal oil and gas under the implementing
regulations of the MLA and the Reform Act, with only technical and
clarifying amendments, since the Reform Act regulations were published
in the Federal Register on June 17, 1988 (53 FR 9214, 1988).

FOGRMA

The Federal Oil and Gas Royalty Management Act of 1982 (FOGRMA) (30
U.S.C. 1701 et seq.) made a few changes to the leasing and operations
aspects of BLM's oil and gas program. FOGRMA focuses mainly on royalty
and rental collection but also includes provisions related to on-the-
ground operations. BLM published the implementing regulations for the
operations aspects of FOGRMA on September 21, 1984 (49 FR 37356), and
for the leasing aspects on July 30, 1984 (49 FR 30446). The operational
regulations implementing FOGRMA prescribe standards for lessees and
operators to follow when conducting operations on Federal and Indian
oil and gas leases. The regulations also clarified BLM's
responsibilities for inspecting operations. BLM's leasing regulations
that implement FOGRMA deal mostly with royalty and rental collections
and with lease reinstatement provisions for leases that terminated by
operation of law.

III. Discussion of Proposed Rule

This proposed rule puts the regulations in a more logical sequence,
streamlines some processes, and reduces duplication. It incorporates
most of the existing oil and gas regulations and all of the existing
onshore orders and national notices to lessees to make one complete
document for lessees and operators to reference. Some sections of the
proposed rule contain new language to correct problems, improve
procedures, or clarify existing requirements. This proposal does not
include regulations that deal with oil and gas drainage (see 63 FR
1936, January 13, 1998, for the proposed rule), Combined Hydrocarbon
Leasing (3140), and the Oil and Gas Leasing: National Petroleum
Reserve--Alaska (3130).
These regulations are written in plain language to more effectively
communicate BLM regulatory requirements. Plain language uses a series
of questions and answers in place of the traditional short heading and
regulatory requirements. The question and answer together constitute
the regulatory requirement. The proposed regulation is also
organizationally different from the current regulation and presents
sections in a more logical order that closely tracks leasing and
operations procedures as they might occur chronologically.

Performance Standards

This proposed rule uses performance standards where possible in
lieu of the current prescriptive requirements or design standards. We
believe that performance standards offer operators and BLM increased
flexibility to deal with unique geologic, ecological, and engineering
circumstances, while at the same time protecting the environment and
other Federal and Indian interests. Under the current regulations and
onshore orders, operators are required to meet certain very specific
and often rigid requirements set out in the regulations and orders.
This inflexible ``laundry list'' approach may not always work in the
most efficient or even most desirable manner. BLM currently issues
variances to the regulations to deal with unique geologic, ecological,
and engineering situations. This is an administrative burden that BLM
cannot afford under current and foreseen declining budgets. It is time
consuming and expensive for operators as well.
Under current regulations, BLM ensures that an operator complies
with all of the requirements of a given regulation or Order. With
performance standards, our focus is no longer on a list of requirements
but on the outcome or goal stated in the regulation. This goal-oriented
approach better protects the public interest since operators will be
held to a stated standard rather than just having to comply with a
checklist. This type of regulation is also beneficial to operators
because it gives them flexibility to meet the goal stated in the
regulation. Finally, these performance regulations will remove some of
the administrative burdens and expense caused by having to issue
numerous variances to the current regulations.
We used performance standards in situations where there was little
or no risk to the health of the land or public health or safety. We
were careful to design a meaningful standard that protects the
environment, public health and safety and preserves BLM's ability to
account for Federal and Indian production. Use of performance standards
was limited to specific areas that deal with oil and gas exploration
and production. Please comment specifically on the performance
standards proposed and whether or not there are other sections of these
proposed regulations where performance standards would be appropriate.

Incorporating Industry Standards by Reference

BLM's current onshore orders contain very detailed minimum
standards to regulate oil and gas drilling and production operations.
In the process of incorporating the onshore orders into this proposed
rule, we replaced the many detailed minimum standards with references
to American Petroleum Institute (API) and American Gas Association
(AGA) standards and practices. BLM and industry recognize API and AGA
standards as acceptable operating practices for Federal lands. You can
purchase API and AGA publications cited in this proposed rule directly
from API and AGA. They will also be available for review at all of
BLM's field offices with oil and gas

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responsibilities. We cite specific, dated editions of API and AGA
standards. Any future amendments or updates to the cited standards will
not be incorporated into BLM's regulations until BLM undertakes a
rulemaking to update the reference.

Changes From Existing Regulations

We propose to modify the leasing regulations by--
1. Eliminating the formal nomination process. Current regulations
give BLM's Director the discretion to post a Competitive Nomination
List and require the public to formally nominate lands from that list
for future competitive sales. The Director has never exercised this
discretion and does not plan to do so in the near future;
2. Eliminating presale offers. The intent of the Reform Act was to
emphasize competition for Federal oil and gas resources. Presale offers
were created by regulation and are not required by the Reform Act.
Eliminating presale offers would more closely follow the intent of the
Reform Act. This change would result in a more streamlined leasing
process because it would remove the one-year waiting period that
currently exists for filing offers on lands previously leased. Current
regulations prohibit filing offers for one year from the date of
expiration, termination, or cancellation of former leases;
3. Requiring that parcel integrity be maintained during the 2-year
post sale window. Under this proposal, you would be able to combine
more than one parcel from more than one sale notice in a lease offer.
Under the existing system, an offer must include a legal land
description. This proposal would simplify the filing of 2-year
noncompetitive lease offers since you would be able to use the parcel
number in the notice of competitive lease sale rather than listing the
complete land description. It would also expedite leasing because lease
stipulation revisions would not be necessary for split parcels. Post
sale offers could not exceed 2,560 acres;
4. Eliminating the existing requirement that an offer for public
domain minerals be for at least 640 acres. The proposal would also
allow you to file an offer on lands outside of the current six square
mile limit if you provide BLM a valid reason for exceeding the six
square mile limit. Eliminating the 640-acre rule and amending the six
square mile rule would simplify the leasing process, provide more
flexibility in filing offers and provide consistency in the competitive
and noncompetitive leasing processes;
5. Reducing the number of copies of an offer that you must file
from three to two. This would reduce your administrative burden and
still allow BLM to process your application efficiently;
6. Limiting competitive and noncompetitive leases to 2,560 acres
for the lower 48 states and 5,760 acres for Alaska. Limiting lease
acreage would provide consistency between competitive and
noncompetitive leases and should simplify the leasing system. Under
current regulations, noncompetitive leases may be for 10,240-acres,
while competitive leases are limited to 2,560 acres;
7. Considering the balance of bonus bids timely paid if the payment
is ``postmarked'' (or its equivalent for non-U.S. mail transmittals) on
or before the due date. The balance of the bonus bids is due within 10
business days after the day of the sale. Current regulations require
this balance to be ``submitted.'' We have interpreted this to mean that
BLM must receive the payment on or before that date. Currently, we do
not accept payments we receive after the tenth business day and BLM
will not issue leases if payments for those leases are not made timely.
This proposal would benefit those parties that exercise diligence in
submitting the balance of their bonus bids;
8. Eliminating unit bonds. Unit bonds are unnecessary since unit
operations may be covered under statewide and nationwide bonds. If
existing statewide or nationwide bonds are inadequate, BLM would
request an increase in those bond amounts rather than require a
separate unit bond;
9. Adding a new bond for wells that are inactive for more than one
year. After a well is inactive for one year, operators would be
required to either increase the bond in place by $2.00 per foot of
depth per well, or pay a nonrefundable $100 yearly fee; and
10. Increasing the dollar amount for the different types of bonds
that we currently require. Individual bonds would be increased from
$10,000 to $20,000 and the amount for statewide bonds would be
increased from $25,000 to $75,000. Nationwide bonds would remain at
$150,000. BLM has not increased bond amounts since 1960 and the
increase takes into account inflation and the fact that current bonding
levels do not cover the costs associated with plugging, reclamation,
and royalties.
This bond increase would not be immediate. It would be phased in as
follows:
a. Parties filing new Applications for Permit to Drill and Changes
of Operator subsequent to the effective date of the final rule would be
required to meet the increased amounts.
b. Existing bonds with no new activity would remain at their
current bond amount for two years at which time the principal must
increase the bond amount. During this 2-year period, BLM could request
bond increases for other reasons.
This proposal would also add a provision to allow you to apply for
a reduction in the bond amount under certain circumstances;
11. Changing BLM's current policy of terminating the period of
liability of bonds. BLM would cancel bonds after determining that you
have met lease obligations, including proper plugging and abandonment
of wells and surface reclamation. The Federal Oil and Gas Royalty
Simplification and Fairness Act of 1996 allows the Minerals Management
Service (MMS) seven years to complete royalty audits. Since bonds cover
royalty obligations, cancellation would be subject to concurrence from
MMS that there are no outstanding royalty obligations;
12. Eliminating the need for holders of overriding royalties,
production payments or similar interests, to file notice of those
interests with BLM. Current regulations require you to file these
documents with BLM. BLM does not currently verify these outstanding
royalty interests and frequently the official lease file does not
contain all outstanding transfers. Therefore, it is not an accurate
record for determining outstanding interests. Eliminating the need to
file these documents would save the $25 filing fee currently required
for each affected lease. If a lessee requested a royalty reduction
because the lease cannot be successfully operated, BLM would then
require the lessee to report the amount of outstanding overriding
royalties. This is not a new requirement;
13. Eliminating the semiannual reporting of lease interests you
hold under option. BLM would still request a statement of acreage you
hold under option when we conduct audits of acreage holdings. This
would reduce your administrative burden and still allow BLM to monitor
acreage holdings;
14. Allowing a Class I reinstatement when you pay a nominal
deficiency late. Current regulations state that if a rental payment is
nominally deficient, the lease will not terminate if the deficiency is
paid to the MMS within the specified time. The proposed change would
provide flexibility in qualifying for a Class I reinstatement. Under
existing regulations, such a lessee is required to

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petition for a Class II reinstatement at a higher rental and royalty
rate. This does not seem equitable since rental deficiencies could
simply be a result of an acreage miscalculation. This rulemaking also
clarifies rental payment requirements for fractional acreage amounts;
and
15. Providing an increase in the percentage and dollar amount for
nominal deficiencies of rental payments. Current regulations provide
that a lease will not terminate if the rental deficiency is 5 percent
or $100, whichever is less. We are proposing to change that amount to
10 percent or $200, whichever is less. This is consistent with the
deficiency percentage and amount allowed when filing a noncompetitive
offer.
We propose to modify the drilling, production, and enforcement
regulations by--
1. Referencing published industry standards and practices instead
of listing minimum standards;
2. Simplifying the procedure to calculate average daily oil
production for leases with sliding and step-scale royalty rates;
3. Eliminating the provision to charge the full value of gas vented
or flared that would have begun one year after BLM ordered you to
capture the gas;
4. Exempting Federal oil wells that produce less than 10 Mcf per
day from the obligation to obtain prior BLM approval to vent or flare;
5. Allowing bypasses around oil and gas meters under certain
circumstances if sealing requirements are followed;
6. Not requiring site facility diagrams for single oil or
condensate tank facilities that service a single well. This is in
addition to the current facility diagram exemption for facilities
processing dry gas;
7. Exempting gas wells producing 100 Mcf of gas per day or less
from requirements for inspection frequency of the meter tube,
determination of flowing gas temperature, calibration frequency, and
tracking of static pens. These exemptions are in addition to the
measurement exemptions that currently exist for low volume wells with
respect to beta ratio range and differential pen tracking;
8. Requiring semiannual proving of positive displacement metering
(e.g., Lease Automatic Custody Transfer) systems measuring 10,000
barrels of oil per month or less;
9. Assessing operators up to $250 per day for each day a violation
remains uncorrected after a specified abatement period. This proposal
would also remove the categories of ``major'' and ``minor'' violations
of existing regulations. BLM believes this approach will simplify the
enforcement process and make it more consistent, while still providing
reasonable monetary incentive for operators to comply. BLM would
prescribe shorter abatement periods for more serious violations;
10. Changing the system of immediate assessments for serious
violations from a $500 per day per violation assessment to a
substantially increased one-time amount per violation assessment. This
change would simplify the enforcement process and would be more of a
deterrent for offenders;
11. Expanding the list of serious violations subject to immediate
assessments to include surface disturbance without approval, habitual
violation, and commingling of production without approval. These
violations would be added because of the potential harm to the
environment, production accountability, or public health and safety;
12. Simplifying the language for BLM's civil penalty regulations to
more closely follow the provisions of the Federal Oil and Gas Royalty
Management Act;
13. Revising BLM's existing oil and gas unitization regulations
with a more flexible unit agreement format. The primary change to the
unitization process would be an emphasis on up-front negotiation among
the various interest owners and BLM. The agreement format would be
flexible as long as it addressed the unit area, initial unit
obligations and continuing development obligations, productivity
criteria, and participating area size; and
14. Requiring a fair market value user fee for geophysical
exploration on BLM lands. The user fee would not, however, be charged
for geophysical exploration under a Federal oil and gas lease.

Section-by-Section Discussion

In many instances, this proposed rule does not change the policy or
procedure of the current regulations and consists only of a translation
from current regulatory language into plainer language. The section-by-
section analysis for the proposed leasing regulations mostly describes
significant changes from current BLM regulatory policy or procedure.
Certain sections also describe areas where we have clarified existing
procedures or policies. The section-by-section analysis for the
operating regulations is more detailed because the proposed changes to
the operating regulations are more complex than the proposed leasing
changes. The operating regulations' discussion also provides tables
that cross reference the proposed sections with existing requirements.
The discussion of the proposed regulatory text is generally a
discussion of changes from current policy or procedure.
The regulations would provide the operational requirements for the
exploration, development and production of oil or gas on both Federal
and Indian lands. These regulations also apply to the leasing of
Federal lands for oil or gas. However, they do not apply to the leasing
of Indian lands. Also, we propose that the operating regulations would
apply to oil and gas leases on lands the Federal government may acquire
in the future, to the extent that they are not inconsistent with the
rights granted in the original lease. The authority under which we
would regulate such leases is the Federal Land Policy and Management
Act of 1976 (43 U.S.C. 1701 et seq.).
Part 3100--Onshore Oil and Gas Leasing and Operations: General
Subparts 3101--General, 3102--Recordkeeping, 3103--Reports,
Submissions, and Notifications, and 3104--Environment and Safety
Definitions Section 3101.5 would consolidate and incorporate the
definitions included in the current 3000.0-5, 3100.0-5, 3150.0-5,
3160.0-5, 3180.0-5, 3190.0-5 for easier reference and to eliminate
redundancy. The definitions section would also include terms found in
current onshore orders. Some of the definitions that appear in existing
sections would be moved to a general definitions section proposed under
the Definitions rulemaking published on November 19, 1996 (61 FR
58843).
One particularly important definition is the term ``interest,''
which is used frequently in the rule. It is proposed that the term
means only record title interest or operating rights interest (also
known as working interest). Other interests such as overriding royalty
interests would not be included in this definition.
Section 3101.8 would contain a chart which references those
sections of these regulations where we cite and incorporate industry
standards.
Subparts 3101 through 3104 would lay out general requirements and
explanations of the proposed 3100 regulations. These general
requirements would include--
1. Principles that underlie the regulation of Federal oil and gas
leasing and operations.
2. The need for operators, lessees, and sublessees to comply with
the lease terms, stipulations, conditions of approval, notices to
lessees, and written or oral orders.

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3. An explanation of the process for waiver, exception, and
modification of stipulations and variances to the requirements imposed
by these regulations.
4. A description of the surface use rights under a lease and your
reporting and recordkeeping requirements.
Subpart 3101 would include a chart referencing other regulations
that affect leasing or operations on Federal land and Subpart 3102
would include a list of the types of records BLM requires an operator
or lessee to keep. Subpart 3103 would identify reports, submissions,
and notifications BLM requires and the forms which must be used. It
would also include a cross reference to the pertinent section of the
regulation to which the record pertains.
Sections 3101.11 through 3101.13 would clarify the liability of
various interest owners when there are many parties with an interest in
a single lease. This section would state that each record title holder,
each operating rights owner, the operator and the bonded parties are
each fully responsible for the performance of all lease obligations (in
the case of an operating rights owner just for the area or depth
subject to its rights), unless provided otherwise in a particular
regulation. The rule makes express what is the case under standard
contract law: When two or more parties promise the same performance to
the same promisee, each is bound for the whole performance thereof.
Restatement of the Law of Contracts, Second Sec. 289(1). Furthermore,
when an oil and gas lessee assigns an undivided interest in his lease
to another, each of them is jointly and severally liable for the
performance of lease covenants. See Hafeman v. Gem Oil Co., 80 N.W.
139, 163 (Nebr. 1956). BLM bonding policy since 1988 has allowed a
single interest holder in a lease to provide a bond on behalf of all
lessees and record title holders, reflecting BLM's understanding that
by covering one such interest holder the surety has agreed to indemnify
BLM for full performance of the lease obligations, up to the amount of
the bond. BLM has never been authorized to agree to assume any portion
of the cost of reclamation or other lessee duties, just because one
interest holder is insolvent or cannot be found. The Bureau Oil and Gas
National Performance Review Report dated April 27, 1995, recommended
that BLM amend its regulations to make this ``joint and several''
liability more explicit. This regulation would be superseded where a
statute or regulation concerning a particular category of obligations
limits the liability of a co-lessee to its proportionate interest in
the lease, such as the Royalty Fairness and Simplification Act provides
with respect to payment obligations.
Section 3101.18 would explain that lessors are responsible for
drainage and would cross reference a proposed rule on oil and gas
drainage that was published in the Federal Register on January 13, 1998
(63 FR 1936). This final rule would incorporate the drainage rule and
cross reference it in this section.
Subpart 3104--Environment and Safety
Subpart 3104 would contain an explanation of what an operator must
do to protect the environment when conducting operations. This subpart
is not meant to describe in detail all of the environmental protection
aspects of leasing. It is only an overview of the issues that are
involved. The details of environmental protection are considered in
several other sections of these regulations and in lease terms and
conditions as well as orders and notices BLM may issue.
Subpart 3105--Lessee Qualifications
Subpart 3105 would contain requirements for lessee qualifications
including when persons who are not United States citizens or who are
minors may hold lease interests. This subpart would also include the
maximum acreage limitations for public domain and acquired minerals
that may be held by an entity which also applies to options for leases.
How BLM computes chargeable acreage would be explained as well as what
you must do if you exceed the acreage limitations. However, this
subpart would eliminate the existing requirement that option agreements
be filed with BLM. Acreage held under option remains chargeable. BLM
would request outstanding option agreements for acreage audit purposes.
Subpart 3106--Fees, Rentals, and Royalties
Subpart 3106 would contain general information regarding fees,
rentals, royalties and minimum royalties, acceptable forms of payment,
and where to submit payments. The proposal includes charts identifying
the types of payments, rental, royalty and minimum royalty rates for
competitive, noncompetitive, renewal, exchange and right-of-way leases,
and leases issued in lieu of unpatented oil placer mining claims. The
subpart would also include provisions on waivers, suspensions, and
reductions of rental and royalty.
Royalty Rates on Oil Sliding and Step-Scale Leases
Proposed regulations on determining oil royalty rates for sliding
and step-scale leases are in sections 3106.50 through 3106.54. These
sections would establish a new procedure to calculate average daily
production. Sliding and step-scale leases have royalty rates that
increase as the average daily production increases.

------------------------------------------------------------------------
Existing
Proposed regulation regulation
------------------------------------------------------------------------
3106.50.................................................... 3162.7-4.
3106.51
3106.52
3106.53
3106.54
------------------------------------------------------------------------

Sections 3106.50 through Section 3106.54 would describe a new
procedure for calculating average daily oil production for the purpose
of determining the correct royalty rate for a sliding-scale or step-
scale lease.
The existing procedure to determine average daily production
involves a complex system of identifying ``countable'' wells based on
the number of days a well was produced, whether a well was initially or
previously produced, and whether a well was shut-in for conservation
purposes. Generally, the average daily production is determined by
dividing the gross oil production for the month by the number of
countable wells multiplied by the number of days in the month,
regardless of how many days the wells actually produced. However, some
leases require the gross production to be divided by actual days
produced to arrive at the average production rate. You then use the
resulting average daily production per well to find the corresponding
royalty rate from the royalty provisions of the lease. For these types
of leases, the royalty rate increases on a scale from 12\1/2\ percent
to 25 percent as the average daily production per well increases.
The complex nature of the well count procedure has caused many
errors by both industry and BLM in calculating or verifying the average
daily production per well. The propensity for errors in the well count
procedure in turn results in incorrect royalty payments, which require
detailed, time consuming, and expensive audits to correct. Errors are
not readily identified by either BLM or MMS because all of the
information needed to verify the average production rate or royalty is
not found on the monthly report of operations, Form MMS-3160.

[[Page 66845]]

These regulations would simplify the procedure to determine the
average daily oil production. Under this proposal, gross production
from a lease or agreement would be divided by the total number of days
``eligible'' wells are produced or used for production. Any paying well
that produces oil is an eligible well, as is any injection well used to
recover oil. Wells shut-in for any reason would not have a bearing on
the average daily production rate. All of the information necessary to
make the computation of average daily production is found on Form MMS-
3160. The proposed procedure should not substantially impact royalty
payments. The proposed procedure would be implemented as of the
effective date of the final rule.
Stripper Oil Property Royalty Reduction
Proposed regulations on determining royalty reductions for stripper
oil properties would explain the procedures on how to determine if you
have a stripper oil property and, if so, how to apply to receive a
royalty reduction. They would also set the reduced royalty rates for
eligible production rates, provide for further royalty reductions as
production declines, and allow BLM to terminate the stripper oil
property royalty reduction program with proper notice.

------------------------------------------------------------------------
Proposed regulation Existing regulation
------------------------------------------------------------------------
3106.60................................ 3103.4-2(a)(1).
3106.61................................ 3103.4-2(a)(2) through (4).
3106.62................................ 3103.4-2(b)(2).
3106.63................................ 3103.4-2(b)(3)(i)(B).
3106.64................................ 3103.4-2(b)(3)(ii).
3106.65................................ 3103.4-2(a)(1), (b)(2),
(b)(3)(i) and (b)(3)(ii).
3106.66................................ 3103.4-2(b)(3)(ii).
3106.67................................ 3103.4-2(b)(3)(ii), (iii)(B),
and (v), and 3103.4-
2(b)(3)(ii), (b)(6), and
(b)(7).
3106.68................................ 3103.4-2(b)(3)(ii).
3106.69................................ 3103.4-2(b)(3)(ii), (iii)(B),
and (iii)(C).
3106.70................................ 3103.4-2(b)(3)(iii)(A) and (B).
3106.71 ...............................
3106.72................................ 3103.4-2(b)(3)(iii)(C) and
(b)(8).
3106.73................................ 3103.4-2(b)(3)(vi).
3106.74 ...............................
------------------------------------------------------------------------

The requirements of this proposal are similar to those in existing
regulations. One minor change would be in section 3106.63. That section
would clarify what oil you must use when calculating your average daily
production rate. It establishes what liquid hydrocarbons are considered
``oil'', and therefore eligible for royalty reduction, and what is
considered ``condensate'', which is not eligible.
Subpart 3107--Lease, Surety, and Personal Bonds
Subpart 3107 would contain general bonding information regarding
who must post a bond, bond amounts, the types of acceptable bonds, and
procedures for bond increases, collections, and cancellations. This
subpart would generally contain existing regulatory requirements with
the following exceptions.
Section 3107.14 would increase amounts for bonds. Individual bonds
would increase from $10,000 to $20,000. The amount for a statewide bond
would increase from $25,000 to $75,000. The nationwide bond amount
would remain at $150,000. BLM believes the increases are justified
because the costs to plug a well, restore the surface, remove related
facilities, reclaim roads, rights-of-ways, etc., in many cases far
exceeds the present bond amounts. In addition, BLM has not increased
minimum bond amounts since 1960. Applying an inflation factor to the
individual and statewide bond amounts since 1960, would increase them
to $50,000 and $135,000 respectively. For these reasons, BLM has
concluded that the increase in bond amounts for individual and
statewide bonds is reasonable and justified. In BLM's experience,
entities that hold nationwide bonds do not pose an unacceptable risk.
Therefore, we are not proposing to increase nationwide bonding.
Section 3107.50 would allow you to apply to BLM for a decrease in
your bond amount. Your application must include your justification for
a decrease in the bond amount. BLM would approve a decrease in your
bond amount if we determine that the potential liabilities on your
lease are less than the existing bond amount. Please specifically
comment on the standards BLM should use to determine whether we will
approve a decrease in the bond amount.
Section 3107.52 would require additional bonding for inactive
wells. A significant source of orphan wells is temporarily abandoned
wells. In 1995, there were more than 6,500 temporarily abandoned wells
on BLM-managed lands. This is a major source of potential future
liability. The $2.00 per foot or $100 per well fees would complement
the proposed increase in individual and statewide bonds and partially
cover the potential liability.
Section 3107.70 would change BLM's current policy of terminating
only the period of liability of bonds. Under this proposal, BLM would
cancel bonds after determining that you met lease obligations,
including proper plugging and abandonment of wells, and surface
reclamation. The Federal Oil and Gas Royalty Simplification and
Fairness Act of 1996 allows MMS seven years to complete royalty audits.
Since bonds cover royalty obligations, cancellation would be subject to
concurrence from MMS that there are no outstanding royalty obligations.
Current section 3104.4, Unit Operator's bond, provides that a unit
operator's bond may be filed in lieu of an individual, statewide or
nationwide bond. This proposal would eliminate any provision for an
operator of a unit to file a unit bond. This is an unnecessary
requirement since BLM allows unit operations to be covered under
statewide and nationwide bonds. If existing statewide or nationwide
bonds are inadequate, BLM would request an increase in those bond
amounts rather than require a separate unit bond.
Subpart 3108 would contain bonding information for geophysical
exploration operations. This includes the types of bonds, amount of
bond, bond increases, terminations, and action to be taken for
nonperformance.
Part 3110--Oil and Gas Geophysical Exploration
Subparts 3110, 3112, and 3113 would contain the requirements for
conducting geophysical exploration operations on Federal lands.

Subpart 3110--Onshore Oil and Gas Geophysical Exploration General
Provisions
This subpart would contain requirements similar to existing
regulations with one exception. Section 3110.13 would require you to
pay a fair market value fee (FMV) for the use of the public lands for
each Notice of Intent to Conduct Oil and Gas Geophysical Exploration
Operations. The Federal Land Policy and Management Act of 1976 (43
U.S.C. 1701 et seq.) (FLPMA) requires that ``the United States receive
the fair market value of the use of the public land and

[[Page 66846]]

its resources unless otherwise provided for by statute.'' In addition,
a May 1992 audit report by the U.S. Department of the Interior, Office
of Inspector General (OIG), recommended that BLM establish and
implement procedures to charge FMV for geophysical exploration. In
order to comply with the requirements of FLPMA and the OIG
recommendation, we propose to adopt a FMV for geophysical exploration.
The FMV would be based on the size of the area physically affected by
each individual geophysical exploration project. You would not be
required to pay the FMV for a geophysical exploration project, or a
portion of a project, that is conducted under a Federal oil and gas
lease.
Subpart 3112--Geophysical Exploration Outside of Alaska
Sections 3112.10 through 3112.12 and 3112.20 and 3112.21 would
describe the procedures you must follow to obtain authorization for
geophysical exploration operations outside of Alaska. It would also
implement a new provision that establishes when you must submit a
notice of intent (NOI) to BLM. Under this proposal, you would submit an
NOI ahead of your anticipated starting date. This time period should
allow BLM time to process your NOI before the day you plan to start
your geophysical exploration project. This section would describe the
actions BLM would take after we receive your application. It would
include a provision for a BLM field inspection to review the
geophysical exploration operations proposal, would describe how and
when to notify BLM that you completed operations, and explain how BLM
will act on your notice.
A new requirement would be added to make sure BLM receives
information to accurately determine the extent of the area affected by
your geophysical exploration project and whether you are conducting any
part of the project under a Federal oil and gas lease. BLM needs this
information to calculate FMV. BLM would not authorize your NOI until
you paid the required FMV.

Subpart 3113--Geophysical Exploration in Alaska

This subpart would contain the existing regulatory requirements
with the following exceptions.
Section 3113.10 would describe what you must include in your
application for an oil and gas geophysical exploration permit. This
proposal replaces the detailed, who, what, and where type of
information in current section 3152.1, with a general standard for
permit application requirements. This standard would provide more
flexibility to deal with on-site conditions and individual geophysical
exploration plans that may dictate different filing requirements.
This proposal would add a new requirement for determining FMV. This
requirement would ensure BLM receives information to accurately
determine the extent of the area affected by your geophysical
exploration project and whether any part of the project is being
conducted under a Federal oil and gas lease. BLM would not approve your
permit until you paid the required FMV.
Section 3113.40 would describe what you must submit to BLM after
you complete geophysical exploration operations, when you need to
submit a completion report, and what action BLM takes after we receive
a completion report. These sections would not include the detailed what
and where type of information that is in current section 3152.7.
Rather, section 3113.40 would replace the list of required information
with a standard for completion reports. A standard is appropriate in
this case because the information BLM needs in a completion report
depends on the application filed, the terms of the permit BLM issued,
and the results of your on-site activities. BLM proposes this standard
because the specific requirements in a completion report are often
worked out between the applicant and BLM before we issue a permit. This
information may also be included in the terms of the permit.
Part 3120--Oil and Gas Leasing
Subpart 3120--Leasing
Subpart 3120 would contain requirements for competitive and
noncompetitive leasing and would describe lands that are available for
leasing. It would contain charts outlining the terms of different types
of leases, and how to describe lands in a letter of nomination. This
subpart also would include procedures for renewal and exchange leases
and right-of-way leasing and would generally contain existing
regulatory requirements with the following exceptions.
This proposal would eliminate presale noncompetitive lease offers.
The intent of the Reform Act was to emphasize competition for Federal
oil and gas resources. Presale offers were created by regulation and
are not required by the Reform Act. Eliminating presale offers would
expedite leasing because it would remove the existing one-year waiting
period that prohibits the filing of offers for one year from the date
of expiration, termination, or cancellation of a former lease. This
would result in a streamlined leasing process, reduce confusion
regarding which lands are available for leasing, result in a cost
savings for unnecessary filing fees accompanying offers identifying
unavailable lands, and encourage competitive leasing.
This proposal would also eliminate the formal nomination procedures
in existing section 3120.3. This section gives BLM's Director the
discretion to post a Competitive Nomination List and requires the
public to formally nominate lands from that list for future competitive
sale. The Director has never exercised his discretion to implement
these regulations and does not plan to do so in the near future. We
therefore believe it would be appropriate to eliminate the requirements
of this section.
Section 3122.21 would allow BLM to accept a late payment of bonus
bid balances if you provide evidence showing the late payment was
postmarked by the U.S. Postal Service, or dated as received by a
courier or other delivery service, on or before the tenth business day
following the day of the sale. Currently, BLM will not accept payments
of bonus bid balances after the tenth business day after the sale.
Sections 3123.30 and 3123.31 would limit the acreage in
noncompetitive lease offers to 2,560 acres in the lower 48 States and
5,760 acres in Alaska. Under current regulations, the 10,240-acre
limitation for noncompetitive parcels exceeds the 2,560-acre limitation
for competitive parcels. As a result, BLM must reconfigure parcels in
order to offer the lands for competitive leasing. Limiting the acreage
will provide consistency between competitive and noncompetitive leases
and will simplify the leasing system.
Those sections would also require you to describe the lands in two-
year noncompetitive lease offers by the parcel number indicated in the
Notice(s) of Competitive Oil and Gas Lease Sale. Under the proposed
rule, you would be able to combine more than one parcel from more than
one sale notice in a lease offer. If you combined more than one parcel
into an offer, the lands would be required to be within six square
miles, unless you show BLM that a larger area is necessary. BLM will
consider larger areas if we determine that is in the interest of
conservation of resources. The current regulations require that lands
be within six square miles. Allowing you to come in with a larger area
would give you added flexibility to deal with geologic conditions.

[[Page 66847]]

These proposed changes would simplify the filing of two-year
noncompetitive lease offers since you would not be required to use
legal land descriptions in your offer, but only the parcel number. It
would also expedite leasing because lease stipulation revisions would
not be necessary for split parcels. The current regulations require
that noncompetitive offers for public domain minerals must be a minimum
of 640 acres unless the lands are isolated, i.e., there are no
contiguous lands. This regulation has resulted in confusion, the loss
of filing fees, loss of priority of offers, and is not required by
statute. This proposal would eliminate the 640-acre filing requirement.
Section 3123.40 would reduce the number of copies of noncompetitive
lease offers you must file. Two copies of a noncompetitive lease offer
would be required rather than the current three copies.
Sections 3124.40 through 3124.42 would clarify current provisions
that 20-year leases issued under Section 14 of the Act are in effect so
long as oil or gas is produced in paying quantities.
Section 3124.44 would require you to file applications for renewal
at least 90 calendar days before the lease expiration date. Existing
regulations require filing at least 90 calendar days, but not more than
six months, from the expiration of the lease term.
Subpart 3129--Record Title, Operating Rights, and Estate Transfers,
Name Changes, and Mergers
Subpart 3129 would cover requirements for transfers of record title
and operating rights interests in leases. This subpart would generally
contain existing regulatory requirements with the following exceptions.
Section 3129.11 would implement a change in policy and procedure.
This proposal would eliminate the requirements of current section
3106.4-2 (Transfers of other interests, including royalty interests and
production payments) that requires you to file overriding royalty
assignments, net profit and production payments with BLM. BLM does not
check the accuracy of these transfers and does not verify outstanding
royalty interests. BLM only places these documents in the lease file
for record purposes. Frequently, the official lease file at BLM does
not contain all outstanding transfers and is therefore not an accurate
record for determining the outstanding interests. Eliminating the
filing of these documents would save you the $25 filing fee currently
required for such transfers. Under these proposed regulations, if you
requested a royalty reduction under section 3106.40, BLM would still
require you to document the amount of outstanding overriding royalties.
Sections 3129.20 and 3129.21 would define mass transfers and would
describe a change from current procedure. BLM would no longer require
three originally-signed copies of mass transfers with one photocopy for
each of the additional leases the transfer affects. This procedure was
adopted under the 1988 regulations and is confusing to some. Under this
proposed rule, you would be required to file three originals of the
record title assignment and operating rights transfer forms for each
affected lease. BLM would not accept photocopies of the signed
documents for each additional lease the transfer affects.
Part 3130--Oil and Gas Agreements
Subpart 3130--Reservoir Management
This subpart would contain requirements for well spacing,
communitization agreements, subsurface storage agreements, development
contracts, compensatory royalty agreements and unit agreements. Also,
the unitization subpart would change current policy and procedure and
is discussed in greater detail in that subpart discussion. This
proposal contains additional types of agreements that are not covered
in existing regulations. These agreements would be added to identify
all types of agreements acceptable under current BLM policy.

------------------------------------------------------------------------
Proposed regulation Existing regulation
------------------------------------------------------------------------
3130.10...................... 3162.3-1(a) and (b).
3130.11...................... 3162.3-1(a).
3130.12...................... 3162.5-2(b).
3130.13...................... 3162.2(b).
3132.10...................... 3161.2.
3132.11...................... New section.
3132.12...................... 3105.2-2, 3105.5-4,
and 3107.
3132.13 and 3132.14.......... New sections.
3133.10...................... 3105.2-2.
3133.11...................... 3105.2-3(a).
3133.12...................... 3105.2-3(b).
3133.13 through 3133.15...... 3105.2-3(c).
3133.16 through 3133.18...... New sections.
3134.10...................... 3105.5-2.
3134.11...................... 3105.5-3.
3134.12...................... 3105.5-2.
3135.10...................... New section.
3135.11...................... 3105.3 and internal BLM guidance (WO IM
Number 95-146 and The Oil and Gas
Development Contract Task Force Report,
March 1988) on the application and use
of development contracts.
3135.12...................... 3105.3-2.
3135.13...................... 3105.3.
3135.14 through 3135.19...... New sections.
3136.10...................... New section.
3136.11...................... 3100.2-1.
------------------------------------------------------------------------

[[Page 66848]]

Well Spacing
Subpart 3130 would contain requirements substantially similar to
those in existing regulations.
Subpart 3132--Oil and Gas Agreements: General
Subpart 3132 would contain requirements substantially similar to
existing requirements with the following exceptions.
Section 3132.10 would set out the types of agreements which require
BLM approval. The language in this section consolidates general
provisions that are stated in many places throughout Federal mineral
leasing laws and BLM's existing regulations.
Section 3132.12 would state the benefits you receive for fulfilling
the requirements of an approved oil and gas agreement. This is a new
section. However, it contains no new requirements or policy issues.
Section 3132.13 would describe when you would be required to obtain
rights-of-stway for roads, facilities, or other surface uses for
Federal lands excluded from an agreement by contraction or termination.
This is a new section. However, it contains no new requirements or
policy issues.
Section 3132.14 would state that you may include State, Indian, or
private mineral interests with Federal interests in a Federal
agreement. This is a new section. However, it contains no new
requirements or policy issues.
Subpart 3133--Communitization Agreements
Communitization agreements are currently covered in subpart 3105.
This proposal would cover the application process and how BLM would set
the terms and conditions of the agreement. The subpart would contain
current regulatory requirements and implements existing policy with the
following exceptions.
Section 3133.11 would detail what you must submit to BLM in your
application. This section would eliminate the existing requirement that
the communitization agreement be signed by or on behalf of all
necessary parties. Instead, this section would require you to certify,
as applicant, that all necessary parties have committed their interests
to the agreement. This change was made as a result of a recommendation
of BLM's Onshore Oil and Gas Performance Review to streamline the
communitization process. Please specifically comment on alternative
ways to submit the required information.
Section 3133.13 would require BLM to notify the operator when we
make a decision on your request to communitize. It also would require
the operator to notify all necessary parties of BLM's decision within
30 calendar days. This new section would clarify current administrative
processes.
Subpart 3134--Subsurface Storage Agreements
This subpart contains current regulatory requirements and
implements existing policy. It does contain more detail than existing
regulations on subsurface storage agreements. However, it does not
implement new policy or procedure.
Subpart 3135--Development Contracts
This subpart contains current regulatory requirements and
implements existing policy. It does contain more detail than existing
regulations on development contracts. However, it does not implement
new policy or procedure.
Subpart 3136--Drainage Agreements
This subpart contains current regulatory requirements and
implements existing policy. It does contain more detail than existing
regulations on drainage agreements however, it does not implement new
policy or procedure. One section in this subpart would cross reference
another proposed rule. Proposed section 3136.10 cross references
regulatory requirements in a proposed rule on oil and gas drainage that
was published in the Federal Register on January 13, 1998 (63 FR 1936).
This final rule would incorporate the drainage rule and cross reference
it in this section.
Subpart 3137-- Unit Agreements
BLM developed this subpart of the proposal to respond to industry
concerns identified by the Bureau Oil and Gas Performance Review and
reinventing government initiatives. The public commented that the
existing unitization process was inflexible and that was a limitation
on increased development. Secretary Babbitt issued Secretarial Order
3199 on April 4, 1996, directing BLM to ``reengineer Federal oil and
gas unitization into a more efficient and flexible process.'' On
September 39, 1998, the Secretary renewed the order until the unit
regulations go into effect or September 30, 1999, whichever occurs
first. BLM drafted these regulations to focus the unitization process
more on what is to be accomplished rather than on how regulated
entities would achieve their objectives. BLM identified the following
as limitations on the effectiveness of the current unitization
process--
1. The process is unnecessarily complicated and is a barrier to
innovative and creative exploration and development;
2. Paying well determinations based solely on economics cause
delays;
3. Allocation of unitized production is often delayed because
paying well determinations cannot be made in a timely manner. This
necessitates extensive corrections to production and royalty reporting;
4. The unit designation process adds unnecessary complexity to the
application process; and
5. The existing model unit form (see 43 CFR 3186) contains many
terms unnecessary to the Secretary's decision whether to approve a unit
agreement or not.
These proposed regulations attempt to eliminate or minimize these
barriers, while still meeting the intent of the Mineral Leasing Act of
1920.
These regulations would increase the flexibility of the unitization
process by allowing operators and BLM to negotiate exploration and
development terms before entering into a unit agreement. The focus of
this new process would be to protect the public interest rather than to
rely on the existing model unit agreement. This regulation would not
change the terms and conditions of existing unit agreements or the way
BLM administers existing agreements.

[[Page 66849]]

3137.21 and 3137.22.......... New sections.
3137.30...................... 3186.1, sec. 3.
3137.31 through 3137.34...... New sections.
3137.40...................... 3181.2.
3137.50 through 3137.52...... 3186.1, sec. 9.
3137.53...................... New section.
3137.54...................... 3186.1, sections 9 and 20.
3137.55 through 3137.59...... New sections.
3137.61 through 3137.66...... 3186.1, sec. 11.
3137.67...................... 3181.4 and 3181.5.
3137.68...................... 3101.3-1.
3137.69...................... 3186.1, sec. 11.
3137.70 through 3137.73...... 3186.1, sec. 11.
3137.74...................... New section.
3137.80 and 3137.81.......... 3186.1, sec. 8.
3137.82...................... 3186.1, sec. 5 and 3186.3.
3137.83...................... 3186.1, sec. 4.
3137.84...................... 3181.5 and 3186.1, sec. 17.
3137.90...................... 3186.1, sec. 25.
3137.91...................... 3186.1, sec. 9.
3137.100..................... 3186.1, sec. 20(b) and 20(d).
3137.101..................... 3183.4(b).
3137.102..................... New section.
3137.110..................... 3186.1, sec 14.
3137.111..................... 3181.5 and 3186.1, sec 17(b).
3137.112 through 3137.114.... 3186.1, sec 14.
3137.120 and 3137.130........ New sections.
------------------------------------------------------------------------

The primary change to the unitization process would be an emphasis
on up-front negotiation among the various interest owners and BLM.
Operators would be able to use any agreement format in their unit
agreement as long as it addressed the following four basic issues: (1)
Unit area; (2) Initial and continuing development obligations; (3)
Productivity criteria and participating areas; and (4) BLM's ability to
set or modify the quantity, rate and location of development and
production.
The unit operator and BLM would base the negotiation of unit
agreement terms on many factors. These factors may include the history
of the area, the environment, economics, the number and depth of wells
previously drilled in the area, the size of the area and the cost of
the proposed operations.
Under these proposed regulations, BLM would accept only a limited
number of additional unit agreement terms beyond the mandatory terms.
If the unit agreement does not specifically address modifications, they
would not be permitted unless all of the original parties or their
successors to the agreement agree. The unit agreement would be
considered to include all producing intervals unless the unit agreement
specifies producing interval(s).
Another change from current procedure involves the creation and
size of initial participating areas and additions to existing
participating areas. The amount of land to be included in any
participating area revision would be specified in the unit agreement
whereas currently it is not. Under existing procedure, participating
areas include only specific producing intervals. An addition to an
existing participating area occurs when a new well that meets the
productivity criteria defined in the unit agreement is drilled outside
of that participating area.
The current obligation to drill an exploratory well and subsequent
wells under a plan of operations would be replaced with initial and
continuing development obligations. Under this proposal, you and BLM
would negotiate the initial and continuing development obligations and
would include those terms in the unit agreement. These terms would
define the number and frequency of wells you plan to drill or
operations that would establish new unitized production. Under this
proposal, the unit would automatically contract to the existing
participating area(s) when you do not meet a continuing development
obligation. Existing regulations allow five years for drilling and
development of the unitized area before automatic elimination would
occur for lands not in a participating area. This proposal would
eliminate the 5-year initial drilling and development period of current
regulations. BLM believes this new requirement would increase the
potential for oil and gas development by encouraging operators to
follow a continuous development program or risk contraction of the unit
area to the participating area(s).
Paying well determinations would be replaced with well productivity
criteria. This would allow the unit operator to negotiate criteria that
are not tied strictly to well economics. Currently, production must
cover the drilling and operating costs attributed to that well. Under
this proposal, costs for that well would be considered as part of unit
costs and not be required to be covered by production from that well
alone. Productivity criteria must be adequate to indicate a well has
established future production potential to pay for the cost of
drilling, completing and operating.
Another change to the current system concerns development
requirements. After unitization, operators would know the effect of
development on participating areas and royalty distribution
immediately, without having to wait extended periods for BLM approvals.
This is because the criteria for deciding whether wells qualify to be
included in a participating area would be clearly spelled out in the
agreement.
Under existing regulations, operators are limited to a set time to
develop the entire unit. Under the proposed regulations, the unit would
not contract as long as development continued at the rate set out in
the agreement. Once you meet the initial development obligations, all
leases committed to a unit would continue to receive the benefits of
unitization as long as the unit is productive.
Under this proposal, BLM could grant suspensions and extensions of
time to

[[Page 66850]]

carry out the initial and continuing development obligations. In those
instances, the unit operator would be required to prove to BLM that the
obligations cannot be carried out due to circumstances beyond the
control of the operator, despite the exercise of due care and
diligence. Existing regulations contain similar provisions.
This subpart for the most part discusses new procedures and policy
or new regulatory requirements. Where a given section is substantially
similar to existing policy, procedure or regulatory requirement, it is
not discussed.
Application
Section 3137.10 would describe the types of unit agreements the
subpart covers. Up to now, BLM's regulations have not distinguished
between exploratory and enhanced recovery unit agreements. Since
enhanced recovery operations differ from exploratory operations, their
unit obligations should differ.
Sections 3137.11 and 3137.12 would require you to negotiate with
BLM on the terms of exploratory and enhanced recovery unit agreements
before you apply and explains that BLM will accept any unit agreement
format. Currently, BLM's regulations require that you use the unit
agreement form in section 3186.1.
Section 3137.13 would explain what you must include in your
unitization application.
Section 3137.14 would describe what the unit operator must certify
in the unitization application. This is a new requirement. Currently,
BLM requires the operator to submit signatures of all parties committed
to the unit. The certification would replace the signatures which will
reduce paperwork for you and BLM.
Section 3137.15 would make it clear that you are not required to
file with BLM evidence that all leases have actually committed to the
unit. However, BLM will require you to keep copies of the invitations
to join the unit, including written reasons why parties did not join
the unit.
Section 3137.16 would change existing policy and procedure. Under
existing regulations, BLM approves a unit agreement effective the date
of approval. If the unit does not meet the public interest requirement,
the unit is void ab initio. Under the proposal, BLM would provisionally
approve units and final approval would be given once you meet the
public interest requirement, retroactive to the date of the provisional
approval. One effect of this change would be that when a lease that is
partly in and partly out of a unit area is segregated into two leases,
the provisional approval would not give the lease that is outside of
the unit any benefits of unitization, including an extension, until
final unit approval. Final unit approval would be given when the unit
meets the public interest requirement by meeting the initial unit
obligations.
Section 3137.17 would require BLM to notify the unit operator in
writing when we approve the agreement. This section would also require
the unit operator to notify all parties to the agreement after it
receives BLM notice.
Section 3137.18 would explain that BLM will reject a unit agreement
application if it does not meet the requirements of this subpart.
Mandatory Topics
Section 3137.20 would define the mandatory terms of exploratory and
enhanced recovery unit agreements. Existing unit agreements contain
terms that deal with the relationship between the parties committed to
the unit agreement and not BLM. This proposal would also reduce the
number of permissible unit agreement terms to only those that deal with
the relationship between BLM and the parties committed to the unit.
Section 3137.21 would describe only mandatory terms in enhanced
recovery unit agreements and exploratory unit agreements. The area you
want to include in an enhanced recovery unit agreement must be fully
developed at the time you make the proposal. This section also explains
that ``fully developed'' means that you have drilled to reasonably
delineate the boundaries of the reservoir. Therefore, you would not be
required to include terms for initial unit obligation, participating
areas, productivity criteria and unit contraction. Instead, you would
be required to define enhancement obligations in an enhanced recovery
unit agreement.
Section 3137.22 would prohibit terms in unit agreements other than
those contained in the listed sections of the proposal. Parties to the
unit could set out other terms under private agreements.
Optional Provisions
Section 3137.30 would explain that you may include optional
provisions in the agreement for limiting the agreement to certain
producing intervals, authorizing multiple unit operators, and providing
means for unit agreement modifications. If those provisions are not
included in the agreement, the agreement applies to all intervals,
contemplates a single unit operator and requires unanimous consent for
modification. BLM would approve those optional provisions if you
demonstrate that they promote additional development or enhance
production potential. These optional provisions are not in existing
regulations. However, BLM does allow for these optional provisions if
operators apply and circumstances warrant that they be included. BLM
would add these provisions to the regulations to clarify existing
policy and procedure.
Sections 3137.31, 3137.32 and 3137.33 would set out the
requirements for having multiple unit operators, the circumstances
under which you may modify the terms of the unit agreement and what you
must submit to BLM if you modify a unit area, or change the commitment
status of a lease.
Section 3137.34 would make it clear that other agreements do not
affect the terms and conditions of a Federal unit agreement.
Size and Shape
Section 3137.40 would require that the unit area consist of tracts
that are contiguous at least at one point. It would explain that areas
of noncommitted tracts totally within the exterior boundary of the unit
are allowed and that BLM may limit the size and shape of the unit area.
BLM currently has policies and procedures to deal with the size and
shape of units that are similar to this section.
Development
Section 3137.50 would define initial unit obligations for
exploratory unit agreements. Existing regulations require you to drill
at least one well to explore for unitized substances for your initial
unit obligation. As a matter of policy, one well will hold up to about
30,000 acres, depending on geology, economics and other factors. This
proposal would require that you negotiate with BLM and define the
number of wells necessary to determine the existence of oil and gas in
the area of the unit. This proposal would also require that the unit
agreement define the primary target for each well and the time between
drilling those wells. This would also be subject to negotiation.
Existing regulations only require you to define the primary target for
the initial well and the time between drilling the well depends on
whether it is a producing well or not. BLM believes that negotiation of
the provisions for development would allow operators flexibility and
ensures that the resources will be diligently developed.
Section 3137.51 would define what you must do to meet initial unit
obligations and fulfill the public interest

[[Page 66851]]

requirement for an exploratory unit agreement. Before the time set out
in the agreement, you must drill at least one well that establishes
unit production, drill a test well to the primary target, or convince
BLM that drilling the initial well(s) or future wells is unwarranted or
impracticable.
Section 3137.52 would define the enhancement obligations for
enhanced recovery unit agreements. The unit agreement would define that
amount, type and timing of enhanced recovery operations.
Section 3137.53 would define what you must do to meet enhancement
obligations and fulfill the public interest requirement for enhanced
recovery unit agreements. You would be required to fulfill the
provisions of section 3137.52, or prove to BLM either that enhanced
recovery operations have actually increased reservoir performance or
that further enhancement operations are unwarranted, impracticable or
uneconomical.
Section 3137.54 would state that if you do not meet initial unit
obligations or enhancement obligations, BLM's approval of the agreement
is invalid and BLM will not extend the term of any lease in the unit.
Section 3137.55 would define continuing development obligations.
This section would require that your program of exploration or
development exceed the pace of non-unitized operations in the area near
the unit. The exploration program must also represent an investment
commensurate with the size of the unit agreement. BLM believes that
these standards for a continuing development obligation would ensure
that the resources will be diligently developed.
Section 3137.56 would describe how to define continuing development
obligations in the unit agreement. Continuing development obligations
occur after you complete initial development obligations, but do not
include work you performed prior to unitization. This differs from
existing policy in that this new provision would be negotiated up front
and defined in the agreement. Currently, continuing development
obligations are not defined at the outset, but are laid out after an
initial discovery, in a plan of development.
Section 3137.57 would explain that continuing development may occur
within or outside a participating area. Currently, starting five years
after a participating area is established, you are required to drill
outside established participating areas to continue the unit. This
proposal would provide flexibility for operators and still encourage
additional exploratory drilling by allowing them to negotiate for
additional drilling within established participating areas.
Section 3137.58 would require a unit to contract if you do not meet
a continuing development obligation. Under existing regulations, if you
have not drilled outside of a participating area after five years from
the date the first participating area was established, the unit
contracts to existing participating areas.
Section 3137.59 would require you to submit certain information to
BLM after you meet continuing development obligations. You would be
required to submit documentation that supports your certification. If
you establish production in a well that does not meet the productivity
criteria, you would be required to operate, produce, and report the
well on a lease basis. This section is substantially similar to
existing requirements. BLM does not currently require a certification,
however, the information required would be substantially similar to the
information in the current application to establish or expand a
participating area.
Productivity Criteria and Participating Area
Section 3137.60 would require that productivity criteria be defined
in the unit agreement. This section would require that the productivity
criteria indicate future production potential sufficient to pay for the
costs of drilling, completing and operating the well on a unit basis.
This section would also require that the productivity criteria warrant
continued production of the individual well itself and that the well
must be ready to produce unitized substances. This section would
explain that BLM will enlarge participating areas when you drill a well
that meets the productivity criteria outside of an existing
participating area. Paying well determinations would be replaced with
well productivity criteria. This would allow the unit operator to
negotiate criteria that are not tied strictly to well economics.
Currently, production must cover the drilling and operating costs
attributed to that well. Under this proposal, costs for that well would
be considered as part of unit costs and not be required to be covered
by the production from that well alone. Productivity criteria must be
adequate to indicate a well has established future production potential
to pay for the cost of drilling, completing and operating.
Section 3137.61 would describe the function or purpose of
participating areas. The unit agreement allocates production to
committed leases within the participating areas in proportion to the
leased surface acreage relative to the total acreage of the
participating area. This is similar to existing policy and procedure.
Section 3137.62 would explain that the first well you drill after
unitization that meets the productivity criteria establishes a
participating area. Existing regulations use the term ``production in
paying quantities'' as the sole acceptable productivity criteria. This
section would further explain that when you establish the first
participating area, lands which contain previously existing wells that
meet the productivity criteria will either be added to the initial
participating area or become a new participating area.
Section 3137.64 would require you to submit to BLM certification
that you established unitized production, a map of the participating
area, and a schedule that establishes the allocation to each interest
owner in the participating area. This section is substantially similar
to existing requirements. BLM does not currently require a
certification. However, the information used to make that certification
would be substantially similar to the information in the current
application to establish or expand a participating area.
Section 3137.65 would require the size of participating area
additions to be approximately the same size as the initial
participating area for that interval. Currently, BLM does not require
them to be the same size. Requiring the participating area additions to
be the same or similar in size would simplify expansion of unit
participating areas.
Unit Operations
The sections covered under the heading ``Unit Operations'' are
substantially similar to existing regulatory requirements.
Suspensions and Extensions of Development
The sections covered under the heading ``Suspensions and Extensions
of Development'' are substantially similar to existing regulatory
requirements.
Unit Termination
The sections covered under the heading ``Unit Termination'' are
substantially similar to existing regulatory requirements.
Royalties
The sections covered under the heading ``Royalties'' are
substantially similar to existing regulatory requirements.

[[Page 66852]]

Leases and Contracts Conformed and Extended
The sections covered under the heading ``Leases and Contracts
Conformed and Extended'' are substantially similar to existing
regulatory requirements.
Change in Ownership
The section covered under the heading ``Change in Ownership'' is
substantially similar to existing regulatory requirements.
Part 3140--Oil and Gas Lease Administration
Subpart 3140--Extensions
Subpart 3140 would contain provisions for drilling extensions,
continuation of leases by production, unit production and segregations,
elimination of leases from unit and communitization agreements, leases
segregated by assignments, and compensatory royalty and lease payments
for subsurface storage of oil or gas. This subpart would not change
requirements of existing regulations, with the exception of
segregations as they relate to provisional unit approval described
earlier in the discussion of proposed section 3137.16.
Subpart 3141--Suspensions
Subpart 3141 would contain requirements for obtaining suspensions
of operations, suspensions of production or suspensions of operations
and production. Filing requirements for approval of a suspension of
operations or production would be outlined. This subpart would describe
the effects of a suspension on the terms of a lease and also
requirements for the suspension or waiver of lease rights during
pending legal proceedings. This subpart would not change requirements
of existing regulations.
Subpart 3142--Lease Terminations and Reinstatements
Subpart 3142 would contain requirements for obtaining Class I and
Class II reinstatements for leases that terminate for nonpayment or
late payment of rental. This subpart would also include Class III
provisions for converting unpatented oil placer mining claims to
noncompetitive oil and gas leases. This subpart proposes two changes
from existing requirements. One change allows a Class I reinstatement
for the late payment of a nominal deficiency (see section 3142.20). The
other change increases the nominal deficiency amount from 5 percent or
$100, to the lesser of 10 percent or $200, which provides consistency
with the nominal deficiency amount allowed for noncompetitive offers
(see section 3142.11).
Subpart 3143--Relinquishments
Subpart 3143 would generally contain existing regulatory
requirements and clarifications of existing requirements pertaining to
relinquishments.
Subpart 3144--Cancellations
Subpart 3144 would contain provisions for cancellations and would
not change existing regulatory requirements. It would also contain
existing regulatory requirements regarding bona fide purchasers.
Part 3145--Oil and Gas Drilling
Subpart 3145--Drilling and Additional Well Operations
This subpart would incorporate the requirements from existing and
proposed regulations dealing with drilling and additional well
operations. The Onshore Orders referenced in this preamble that relate
to the conduct of operations and appear in the charts and proposed
operations regulations that follow are: Onshore Order Number 1, which
was published on October 21, 1983, (48 FR 48916); Proposed Onshore
Order Number 1, which was published on July 23, 1992, (57 FR 32756);
Onshore Order Number 2, which was published on October 18, 1988, (53 FR
46798) (Revised on December 9, 1988, (53 FR 49661), September 27, 1989
(54 FR 39528), and January 27, 1992, (57 FR 3023)); Onshore Order
Number 3, which was published on February 24, 1989, (54 FR 8056)
(Revised on September 27, 1989, (54 FR 39528)); Onshore Order Number 4,
which was published on February 24, 1989, (54 FR 8086); Proposed
Onshore Order Number 4, which was published on March 9, 1994, (59 FR
11019); Onshore Order Number 5, which was published on February 24,
1989, (54 FR 8100) (Revised on September 27, 1989, (54 FR 39527));
Proposed Onshore Order Number 5, which was published on January 6,
1994, (59 FR 718); Onshore Order Number 6, which was published on
November 23, 1990, (55 FR 48958) (Revised on January 17, 1992, (57 FR
2039 and 2136) and on February 12, 1992, (57 FR 5211)); Onshore Order
Number 7, which was published on September 8, 1993, (58 FR 47354)
(Revised on November 2, 1993, (58 FR 58505)); and Proposed Onshore
Order Number 8, which was published on May 6, 1991, (56 FR 20568). This
proposal also references Notice to Lessees (NTL) Number 3A, which was
published on January 10, 1979, (44 FR 2204) and NTL Number 4A which was
published on December 27, 1979 (44 FR 76600). The following is a
crosswalk for this subpart.

------------------------------------------------------------------------
Existing
Proposed regulation regulation Onshore order
------------------------------------------------------------------------
Application for Permit to Drill or Reenter (APD)
------------------------------------------------------------------------
3145.5........................ 3162.1 and 3162.3-
3
3145.10....................... 3162.3-1(c), (d) Order Number 1,
and (g). III.D.; Order Number
2, parts of I., II.,
III.G. and D.5.; and
Proposed Order
Number 1, II.B.,
III.B., III.C.,
III.E. and IV.
3145.11....................... 3162.3-1(h), Order Number 1,
3164.3(b) and III.G.4.; and
(c). Proposed Order
Number 1, III.C.2.
3145.12 and 3145.13........... 3162.3-1(d)(1)-(4 Order Number 1,
), (e) and (f). III.C., III.G.; and
Proposed Order
Number 1., III.A.,
III.C., and III.F.3.
3145.14....................... ................. Order Number 1,
VII.A.; and Proposed
Order Number 1,
parts of section IV.
3145.15....................... ................. Order Number 1,
VII.B.; and Proposed
Order Number 1, V.
3145.16....................... 3162.3-1(e) and Order Number 1,
(f). Introduction and
III.G.4.
3145.17 and 3145.18........... ................. Order Number 1,
III.B.1.; and
Proposed Order
Number 1, III.D.
3145.19....................... 3162.3-1(g) and Order Number 1,
(h). III.B. and III.C.;
and Proposed Order
Number 1, III.E.,
III.F.
3145.20....................... ................. Proposed Order Number
1, III.E.
3145.21....................... ................. Proposed Order Number
1, I.D
3145.22....................... 3162.4-2......... Order Number 1, VIII
------------------------------------------------------------------------

[[Page 66853]]

Technical Drilling Standards
------------------------------------------------------------------------
3145.30....................... 3162.5-2(a)...... Order Number 2,
III.A.
3145.31....................... 3162.5-2(a)...... Order Number 2,
III.E.
3145.32....................... 3162.5-2(a)...... Order Number 2,
3162.5-3 III.B., III.C. and
III.E.; and Order
Number 6, III.C.4.c.
3145.33....................... 3162.5-2(c)...... Order Number 2,
III.B.
3145.34....................... ................. Order Number 2,
III.D.
------------------------------------------------------------------------
Drilling Operations in a Hydrogen Sulfide Environment
------------------------------------------------------------------------
3145.40....................... 3162.5-3......... Order Number 2,
III.C.6.b; and Order
Number 6, III.A.,
III.B., and IIIC.
3145.41....................... 3162.5-1(d)...... Order Number 6, I.C.,
III.A., III.B., and
IIIC.
3145.42....................... 3162.5-3......... Order Number 6, II.S.
3145.43....................... 3162.5-3......... Order Number 6,
III.C.1.c.
3145.44....................... 3162.5-3......... Order Number 6,
III.C.3.a., C.3.b.
------------------------------------------------------------------------
Additional Well Operations
------------------------------------------------------------------------
3145.50....................... 3162.3-2(a) and Order Number 1, parts
3162.3-3. of IV.A., IV.B., and
IV.C.; Proposed
Order Number 1, part
of VI.; Order Number
7, III.E.1.f., and
III.F.; and Proposed
Order Number 8,
parts of III.A.
through III.D.
3145.51....................... 3162.3-2(a) and Order Number 1, IV.A,
3162.3-3. IV.B., and V.;
Proposed Order
Number 1, VI, Order
Number 7, III.A.;
and Proposed Order
Number 8, parts of
III.A. through
III.D.
3145.52....................... 3162.3-2(b) and Order Number 1, IV.A.
(c) and 3162.3-3. and C.; and Proposed
Order Number 1,
parts of VI.
3145.53....................... 3162.3-2(a)...... Order Number 1,
IV.B.; Proposed
Order Number 1, VI.;
and Order Number 7,
III.A.
3145.54....................... 3162.3-2......... Order Number 1, IV.A.
and IV.B.; and
Proposed Order
Number 1, VI.;
Proposed Order
Number 8, parts of
A., B. and C.
3145.55....................... 3162.5-1(b)...... Proposed Order Number
1, VII.A.; and
Proposed Order
Number 8, parts of
III.A.
------------------------------------------------------------------------

Application for Permit to Drill or Reenter
Regulations for Application for Permit to Drill or Reenter (APD)
would include filing, processing, and surface and drilling operating
requirements. Generally, the sections discussed in this subpart contain
changes from existing policy or procedure.
Section 3145.5 would make it clear that you must conduct all
operations on Federal and Indian leases, including those that do not
require BLM approval, according to the surface use and drilling
standards of this subpart. BLM currently applies similar standards to
workovers and additional well operations via conditions of approval.
This regulation would clarify that existing policy.
Section 3145.10 would require you to submit an Application for
Permit to Drill or Reenter (Form 3160-3) to BLM for review and approval
before you disturb the surface or begin any drilling operations for a
new well or reentry of an abandoned well. Under this section, you would
be required to have a BLM-approved APD before you start any
construction activity or any operation to develop a Federal or Indian
lease, including activity on private surface necessary to operations on
a Federal or Indian lease. This would include the need to obtain BLM
approval for horizontal or directional wells that develop any portion
of a Federal or Indian lease, even if the well site is located on State
or private surface.
The Reform Act requires that BLM post a public notice of Federal
well proposals for 30 calendar days before we are authorized to approve
it. Therefore, you should submit your well proposals to BLM at least 31
calendar days before you plan to begin drilling operations to give BLM
enough time to post it. This time period would allow BLM time to
process your APD before the day you plan to start drilling your well.
This period also matches the filing requirement that you should follow
if you are requesting a suspension of operations or production in
connection with drilling a new well or reentering an abandoned well
(section 3141.12 of these proposed regulations).
The Forest Service (FS) approves surface use plans on National
Forest System lands (NFS). Surface use plan submittal time frames on
NFS lands are longer because the FS must comply with the Reform Act and
timeframes established by Section 322 of the Department of the Interior
and Related Agencies Appropriation Act for Fiscal Year 1993 (P.L. 102-
381, 106 Stat. 1419, 16 U.S.C. 1612 note.). The FS needs time for the
public notice period mandated by the Reform Act, a public comment
period for review of environmental assessments completed for well
proposals, and an appeal period. The minimum time the FS requires to
process surface use plans is 120 calendar days.
Section 3145.11 would state the authority and general involvement
of the FS and other Federal or State agencies in processing APD's you
propose on a Federal or Indian lease where the surface is not managed
by BLM or a private landowner. This section addresses BLM's limited
responsibility for managing oil and gas operations on lands managed by
the FS. The Reform Act limited BLM's responsibility on NFS lands to
development or operational proposals involving subsurface activity,
related impacts, and any appeals regarding the same. Surface use plans
on NFS lands require only FS approval, and all appeals related to the
surface use plan are appeals of the FS decision. Unlike existing
regulations, the proposal would not require you to submit a surface use
plan of operations with your APD, if the proposed drilling location is
on NFS lands. Agency responsibilities under this rule and the Reform
Act are determined on the basis of subsurface

[[Page 66854]]

(BLM) and surface (FS) authority for oil and gas operations on NFS
lands.
BLM also shares responsibility for approving surface use plans on
National Wildlife Refuge lands in Alaska. If your proposal involved
these types of lands, the U.S. Fish and Wildlife Service would be
responsible for approving surface use plans for APD's on land it
manages.
Sections 3145.12 and 3145.13 would describe what information you
must submit to BLM for a complete APD and what requirements you must
comply with during operations. This section would require you to submit
a drilling and surface use plan and also would establish standards for
conducting Federal and Indian lease operations. This section would not
require the prescriptive 8-point drilling plan and 13-point surface use
plan of operations required by Order Number 1. Instead, it would
require your plan to describe how your proposal will affect, protect,
or mitigate impacts to surface and subsurface resources. This section
would identify the resource concerns that BLM expects you to address in
your plan and operations. This is in contrast to the approach of Order
Number 1, which places more emphasis on specific information that you
must submit to BLM.
The term useable water would be used in these sections and other
places in section 3145.32. We defined this term as water containing
less than 10,000 parts per million (ppm) of total dissolved solids.
This definition is consistent with the regulations of the Environmental
Protection Agency (EPA) at 40 CFR 144.3 and 146.3, for an underground
source of drinking water. This is also consistent with the existing
definition in Onshore Oil and Gas Order Number 2. This section would
require you to submit Form 3160-3 for each new well that you propose to
drill, or abandoned well you propose to reenter.
Section 3145.14 would provide for additional APD submission
requirements when your well has a proposed surface location on
privately-owned surface. It also would discuss conditions under which
BLM may approve an APD if you are unable to reach agreement with the
surface owner for access or occupancy. BLM's responsibilities under the
National Environmental Policy Act (42 U.S.C. 4321 et seq.), Endangered
Species Act (16 U.S.C. 1531), and the National Historic Preservation
Act (16 U.S.C. 470 et seq.), are essentially the same for Federal or
Indian surface and split-estate lands. BLM will seek full cooperation
of the private surface owner. However, the surface owner may not veto
Federal statutory requirements. Consequently, surface use agreements
with private landowners must satisfy the private surface owner and meet
BLM's requirements for environmental protection and mitigation. This
proposed rule would also apply to horizontal or directional wells that
are located on State or private surface, if the well ultimately
develops Federal or Indian leases.
Section 3145.15 would provide for additional APD requirements when
your proposed well is located on an Indian oil and gas lease or on
surface held in trust for an Indian tribe or an individual Indian. It
also describes circumstances where a surface-use agreement is not
necessary.
Section 3145.16 would allow you to submit either a single APD
package for each well or a field-wide APD package for several wells in
a field or area of geologic or environmental similarity. You would be
able to develop a field-wide plan for the drilling plan, the surface
use plan, or both. If you developed a field-wide plan, it would allow
you to reference already approved material when you propose future well
sites. This would reduce the amount of paperwork that you would be
required to submit for each APD. If your drilling or surface use plan
were nearly identical to a previously approved field-wide plan, you
would be required to submit information to BLM only on the items that
deviate from your approved field-wide plan.
Sections 3145.17 and 3145.18 would allow you to submit a Notice of
Staking (NOS) to notify BLM that you have selected a drilling location.
You would submit a NOS before an APD to provide BLM the basic
information on the type and location of the well you propose to drill.
You would submit a NOS only if you actually intended to file an APD at
a later date. Section 3145.18 would list the basic information required
in a NOS application and surveying requirements that you must complete
before BLM conducts a predrill inspection under a NOS.
Section 3145.19 would describe general actions BLM will take to
process your APD. Order Number 1 and current regulations at sections
3162.3-1(h) and 3162.5-1 require BLM to complete processing of
applications in specified timeframes. Order Number 1 also includes
specific timeframes for BLM to conduct predrill inspections and to
notify operators that additional information is needed. The only
processing time frames included in this subpart are the 30-day public
notice period required by the Reform Act and the 120-day period for
surface use plan proposals on NFS lands. The other processing time
frames of current regulations are not statutory and would be eliminated
by this proposal. BLM will continue to process complete applications in
a timely manner.
Section 3145.20 would allow up to two extensions of 12 months for
APD's. Existing regulations do not address extensions of APD's.
However, current practice in many BLM offices is to grant APD
extensions when justified.
Section 3145.23 would require you, within 30 calendar days after a
well becomes inactive, to put the well into production or service,
submit to BLM plans to conduct well work to restore production or
service, submit plans to plug and abandon the well or comply with the
requirements of section 3107.53. These would be new requirements. BLM
has found that inactive wells often become orphan wells that BLM would
eventually have to plug and abandon. This section would require
operators to take action to put inactive wells back into service, plug
and abandon them or provide additional bonding or pay into a fund to
help mitigate costs of orphan wells. BLM believes that this is
necessary to encourage operators to fulfill their lease obligations as
they pertain to inactive wells.
Technical Drilling Standards
Technical drilling standards are BLM's requirements for designing
and drilling wells on Federal and Indian leases. Areas covered by these
sections would include well control, air drilling, well design and
construction, well integrity testing, and drill stem testing.
Section 3145.30 would list the general well control requirements
that you must comply with when you design and drill a well. This
section would contain performance standards that would replace certain
prescriptive requirements of Order Number 2. This section would also
incorporate by reference the applicable American Petroleum Institute's
(API) publication on well control systems. Many of the existing
requirements in BLM's regulations on well control mirror the
requirements in the cited API publication. This section also contains
specific well control provisions that BLM believes are essential to
protect surface and downhole resources and public health and safety.
Section 3145.31 would require you to follow the standards contained
in the referenced API document when drilling with gas, air or mist. As
noted above, many requirements in BLM's existing orders contain
requirements similar to the cited API publication.

[[Page 66855]]

Section 3145.32 would state the performance standards for designing
and drilling your well. As with the well control section, this section
would require certain specific measures that BLM believes critical to
resource protection and public health and safety. You must address all
of the applicable requirements of this section in your APD and conduct
your drilling operations accordingly. These performance standards would
replace the prescriptive requirements of Order Number 2.
Section 3145.33 would require you to pressure-test all casing
strings below the conductor pipe before you set the next string of
casing. You also must perform a mud weight equivalency test for all
exploratory wells and any part of a well approved to use a 5000 pounds
per square inch blowout prevention equipment system (BOP). The proposed
requirement differs from the existing Order Number 2 requirements in
that it does not specify minimum test pressures or standards for a
successful test. Under this proposal, testing would be performed in any
manner that demonstrates that the casing or formation can withstand the
maximum pressure it is likely to be subject to throughout its useful
life. BLM would determine the adequacy of your testing program before
approving your APD.
Drilling Operations in a Hydrogen Sulfide (H2S) Environment
Section 3145.44 would require you to train all personnel working at
the wellsite about H2S drilling and contingency procedures
according to standards contained in the referenced API publication.
This section would require that training be completed at least three
business days before drilling into, or before reaching a depth of 500
feet above, known or probable H2S zones. The training
frequency contained in the referenced API publication would replace the
existing Order 6 requirement to have weekly H2S and well
control drills. The API standard would allow you and BLM to agree upon
a training frequency commensurate with the H2S potential.
This section also states who must have appropriate personal protective
breathing devices at your wellsite and requires such equipment to
comply with the standards contained in the referenced API document.
Additional Well Operations
Regulations for additional well operations would address general
filing, processing and operating requirements for well operation
activities that generally occur after you drill a well, including
reclamation requirements. More specific information is included for
some of these activities in separate subparts of this proposed rule
(e.g., subpart 3155 for disposal of produced water and subpart 3159 for
temporary and permanent abandonment).
Section 3145.50 would include filing requirements and a reference
to the form (Sundry Notice, Form 3160-5) that you must use when
applying for additional well operations that require BLM approval. The
filing requirements and operating standards would parallel requirements
in this subpart for drilling a new well or reentering an abandoned
well.
Section 3145.51 would list additional well operations that BLM must
approve before you begin them. These operations would require BLM
approval, although there would be some exceptions described in other
sections of this proposed rule. For example, section 3155.12 describes
cases when an approval for disposal of produced water is not necessary.
This section also includes standards to determine when other additional
well operations, which are not specifically listed in this section,
would require BLM approval. Some of these activities may be fully
addressed in your approved APD. If this is the case, a Sundry Notice
and a separate approval would not be necessary, unless you plan to
change proposals that were part of your approved APD.
Existing regulations allow BLM to grant oral approval for plugging
and abandonment of newly drilled dry holes, drilling failures and in
emergency situations. This proposal would allow BLM to grant oral
approvals for additional well operations that require BLM written
approval. We propose this change because many of these operations are
repetitive in terms of technical design, equipment use, the time it
takes to complete the operation, and surface use.
Section 3145.52 would identify when additional well operations
would not require BLM approval. See the definition of ``routine well
maintenance'' in section 3101.5 of this proposal to accurately apply
these standards. This section would also contain a requirement that you
notify BLM within 48-hours of actions taken to correct or contain an
emergency.
Section 3145.54 would require you to submit reports, well logs,
test data, and other information that may be required by a condition of
approval within 30 calendar days after you complete additional well
operations. A well completion report would also be necessary within 30
calendar days if a well completion occurs in a new formation.
This section would require you to submit a subsequent report on
Sundry Notice, Form 3160-5, within 30 calendar days after you complete
additional well operations, if you alter the existing wellbore
configuration. A subsequent report would also be required if BLM
requested it.
Section 3145.55 would include reclamation standards that you must
follow during drilling and lease operations. Current regulations
require you to submit a plan that explains how you will reclaim the
disturbed area. This section would set out performance standards for
recontouring, seedbed preparation and revegetation. The details of
these standards would be laid out in your APD or Sundry Notice for
additional lease operations and approved by BLM.
Part 3150--Oil and Gas Measurement and Operations
Subpart 3151--Production Storage and Measurement--General and
Production Operations With Hydrogen Sulfide
This subpart would contain regulations on the production, storage,
and measurement activities that require BLM approval. This subpart
would contain requirements substantially similar to existing
requirements with some exceptions.

------------------------------------------------------------------------
Existing
Proposed regulation regulation Existing order or NTL
------------------------------------------------------------------------
3151.10....................... 3162.3-2......... Order Number 4
section III.E. and
F.;
3162.7-2......... Order Number 5
section III.D.; and
3162.7-3......... Notice to Lessees
(NTL)-4A.
3151.11....................... 3162.7-2......... Order Number 4
section III.E. and
F.;
3162.7-2......... Order Number 5
section III.D., NTL-
4A; and
3162.7-3......... BLM Manuals and
Instructional
Memorandums.
3151.12....................... 3162.7-1(a) and
(b).
................. Order Number 7
section III.A.3
3151.13....................... 3162.7-1(e)......

[[Page 66856]]

3151.14....................... 3162.7-1(d)...... Order Number 4
section II.O.3. and
section III.B.;
3151.15....................... ................. NTL-4A sections I and
II; and BLM
Instructional
Memoranda.
3151.16....................... ................. NTL-4A section III.
------------------------------------------------------------------------

Production, Storage, and Measurement--General
Section 3151.16 would list instances where you would be able to
vent or flare gas royalty-free without prior BLM approval. Under this
proposal you would be able to vent or flare 10,000 cubic feet or less
of associated gas per well, provided the gas is produced as part of
normal oil production operations and is vented or flared in a safe
manner according to applicable laws, regulations and accepted industry
practice. This would be a new regulatory requirement that implements
existing policy.
Production Operations With Hydrogen Sulfide
Proposed regulations on production operations with H2S
would require you to test your wells and facilities to identify the
potential for H2S and take the necessary steps to protect
public health and safety and the environment.

Section 3151.22 lists the public protection requirements that would
apply to storage tanks that meet the criteria in proposed section
3151.21. Many types of signs and fences satisfy the requirements to
warn of danger and restrict access. The proposed section leaves out
much of the existing regulatory detail regarding the visual appearance
of danger signs and the type of fencing required. The proposed rule
would allow BLM the flexibility to accept practices appropriate for a
particular area as long as they could achieve the stated performance
standard of alerting the public of the potential H2S hazard
and restricting access to production facilities.
Section 3151.23 lists the public protection requirements that would
apply to completed wells and production facilities when the
H2S concentration in the gas stream is 100 ppm or more. As
with proposed section 3151.22, a standard for signs and fences is
proposed that would eliminate the regulatory detail that presently
exists in Order Number 6. The section would require that your facility
be designed and constructed in accordance with the referenced API
publication and would require you to calculate the 100 and 500 ppm
radii of exposure. You would also be required to implement the
contingency planning procedures of the referenced API publication when
the identified standards are exceeded.
Section 3151.24 would require you to take specific actions to
reduce ambient air concentrations of H2S and sulphur dioxide
if the specified thresholds for sustained ambient air concentrations
are exceeded.
Subpart 3152--Site Security
This subpart would contain regulations on site security to provide
for production accountability through sealing requirements, site
security plans, facility diagrams, well and facility identification,
recordkeeping and theft reporting.

------------------------------------------------------------------------
Existing
Proposed regulation regulation Existing orders
------------------------------------------------------------------------
3152.10....................... 3161.1(b)........ Onshore Order Number
3 section I.B., I.C.
3152.20....................... 3162.7-5(a) and Order Number 3
(b) (1), (2), section III.A.1 and
(4), and (5). 2.
3152.21....................... ................. Order Number 3
section III.A.1.b
and g; and Order
Number 3 section
III.A.2.a.
3152.30....................... 3162.7-5(b) (2) Order Number 3
and (3). section III.B. and
D.
3152.40....................... 3163............. Order Number 3
section IV.
3152.50....................... 3162.7-5......... Order Number 3
section III.F. and
H.
3152.51....................... 3162.7-5(d)...... Order Number 3
3152.52....................... section III.I.
3152.60....................... 3162.6...........
3152.70....................... 3162.7-1(c) (1) Order Number 4
through (4). section III.E.
3152.80....................... 3162.7-5(b)(8)... Order Number 3
section III.E.
------------------------------------------------------------------------

Site Security--General
Section 3152.10 would set site security standards for Federal and
Indian oil and gas lease facilities and those facilities that store
allocable production.
Storage and Sales Facilities--Seals
Section 3152.20 would contain a performance standard for when a
particular valve is subject to seal requirements. The performance
standard would describe the characteristics of valves you must seal.
This differs from Order Number 3, which lists specific valves that are
either subject to, or exempt from, sealing requirements. This standard
should give operators the flexibility to take into account local
conditions or practices that may affect the need to seal a valve. This
section would eliminate the list in Order Number 3 section

[[Page 66857]]

III.A.1.c through f and section III.A.2.a., of specific valves that
need to either be sealed, or are exempt from, seal requirements.
This section also establishes the standard for how to seal valves
and how to seal sealable measurement system components. This part of
the section does not change existing requirements.
Section 3152.21 would describe when you must seal the valves that
meet the standards in section 3152.20.
Oil and Gas Meters
Section 3152.30 would state BLM's site security requirements for
oil or gas metering systems. This section describes the characteristics
of components of a Lease Automatic Custody Transfer (LACT) unit you
must seal. This differs from the Order Number 3 approach of listing the
specific components subject to sealing. This proposal would also
require BLM approval for any bypass. We recognize that meters may be
used in an operation for check purposes and not for determining royalty
volumes.
Federal Seals
Section 3152.40 addresses how and when BLM would seal a valve that
is in violation of these regulations. The proposed rule would not
change BLM's current procedure on Federal seals.
Plans and Facility Diagrams
Section 3152.50 would state what you must include in your site
security plan and would require you to follow your plan for Federal
facilities. As with existing Order Number 3, you would not be required
to send in your site security plan unless BLM requests it.
Sections 3152.51 and 3152.52 would address what you must include in
your site facility diagram and for which facilities you must prepare a
diagram. This section would except the requirement for a site facility
diagram where a single tank is used for collecting small volumes of oil
and condensate produced from a single well. In these circumstances, the
design of the facility is so simple that a diagram is unnecessary.
Also, the volumes these wells produce are low and the risk for
significant royalty loss is minimal. The time frame for submitting the
site facility diagram is covered in the general recordkeeping section
3103.10 of this proposed rule and is not repeated here.
Well and Facility Identification
Section 3152.60 would require you to identify wells and facilities
with signs that show basic information. This is a change from existing
requirements in that it would eliminate the detailed requirements of
existing regulations and replace them with a standard. The standard for
well and facility identification would require the sign to identify the
wells and facilities so that anyone visiting the site will know the
``who'' (operator), ``what'' (lease or agreement number), and ``where''
(legal description) of the site.
Transporter Documentation
The section on transporter documentation contains requirements
similar to existing requirements.
Theft
Section 3152.80 would address when and how you must report
incidents of oil or condensate theft from your lease. BLM and the
person reporting the theft would determine the level of detail needed
to document the incident. Existing regulations require you to use a
form to report a theft. This section would not.
Subpart 3153--Oil Measurement
This subpart on oil measurement would identify the types of
measurement systems and procedures that must be used to accurately
measure the quantity and quality of oil you produce.

------------------------------------------------------------------------
Existing
Proposed regulation regulation Existing order
------------------------------------------------------------------------
3153.10....................... 3162.7-2.........
3153.20....................... ................. Order Number 4
section III.C.
3153.30....................... ................. Order Number 4
3153.31 section III.D.1 and
2.
3153.32....................... ................. Order Number 4
section III.D.3.c.;
and Proposed Order
Number 4 section
III.D.4.
3153.33....................... ................. Order Number 4
section III.D.3.a(1)
and (2); and
Proposed Order
Number 4 section
III.D.3.a.(2).
3153.34....................... ................. Order Number 4
section III.D.3.b.
3153.35....................... ................. Order Number 4
3153.36 section III.D.3.c(4)
and section III.D.4
Proposed Order
Number 4 section
III.D.4.
3153.37....................... ................. Order Number 4
section III.D.5.
3153.38....................... ................. Order Number 4
section III.D.4.
3153.40....................... ................. Order Number 3
section III.C.1.a
and b.
------------------------------------------------------------------------

Oil Measurement--General
Section 3153.10 would establish how you must measure oil produced
from or allocated to a Federal or Indian lease. The proposed section
requires oil to be measured by tank gauging, positive displacement
metering system, or a method that you can demonstrate to BLM is
equivalent in accuracy and accountability to tank gauging or a positive
displacement metering system.
Tank Gauging
Section 3153.20 would contain a table that lists activities which
affect volume and quality determinations if you use tank gauging to
measure oil. For each of the listed activities, the table also lists
the API standards and practices that you must follow to ensure proper
oil measurement. API standards are equivalent to the minimum standards
that presently exist in Order Number 4 for tank gauging.
Lease Automatic Custody Transfer (LACT)
Sections 3153.30 and 3153.31 would specify how you must install,
operate, and maintain a LACT system to measure oil. The section
identifies the API specifications and standards that would become the
regulatory requirements for LACT systems. It also lists specific
components that you must use in a LACT system, even though components
are considered optional in the referenced API documents. You would not
be required to retrofit LACT systems installed before the effective
date of the rule to meet the requirements of the listed API references.
Section 3153.31 would require that oil gravity, sediment, and water be
determined in the same manner as you would for tank gauging.
Incorporating the API publications by reference should be equivalent to
the minimum standards that presently exist in Order Number 4 for LACT
systems.

[[Page 66858]]

Sections 3153.32 through 3153.38 would specify: (1) how and when
you must determine the composite meter factor for a LACT meter; (2)
requirements for meter provers used to determine meter factors; (3) the
acceptable tolerance for composite meter factors; (4) corrective action
in the event of an out-of-range meter factor; (5) reporting
requirements for LACT systems; and (6) how you must correct volumes if
your meter factor changes between provings. These sections incorporate
by reference the appropriate API references for proving a LACT.
Accuracy and repeatability standards for prover meters, the meter
proving process, and the LACT's meter factor are not specified in the
referenced API documents. However, BLM believes these are important to
volume accuracy. Therefore, the repeatability tolerances of existing
Order Number 4 (five consecutive proving runs within 0.05 percent) and
the tolerance for deviation of the composite meter factor
(0.0025 between provings) would continue to be required.
The range for initial and repaired meter factors (0.9950 to 1.0050)
presently in Order Number 4 has been deleted in the proposed rule.
There is no evidence to support repair or replacement of a meter that
does not fall within 0.9950 and 1.0050 upon installation as long as the
repeatability and meter factor deviation requirements are met.
Section 3153.40 states how you would document the sale of oil from
your production facility. To be consistent with API publications, the
proposed section uses the term ``measurement ticket'' as a new standard
term to refer to ``run ticket'' and ``receipt and delivery ticket''
which are terms customarily used in the oil industry to mean the same
thing. This proposed section would apply to documentation of sale or
removal of oil regardless of the measurement system you use.
Subpart 3154--Gas Measurement
The subpart on gas measurement would establish the performance
standards for measurement systems used to measure and report Federal
and Indian gas. This subpart would also include requirements on
installation, operation, and maintenance requirements for orifice
metering systems. Other areas covered in this subpart would include
metering systems other than orifice meters, reportable volume
corrections, and gas quality measurements.
Subpart 3154 would incorporate by reference certain API standards
relating to gas measurement. These standards are recognized by both BLM
and industry as sound operating practices and BLM believes the cited
API standards are appropriate. However, BLM is specifically seeking
comment on the applicability of such industry standards as they relate
to the measurement, sampling, quality determination, and frequency of
meter calibration for gas produced from or allocated to Federal and
Indian lands. Please also comment on the point of measurement for
reporting such production for royalty purposes.

------------------------------------------------------------------------
Existing
Proposed regulation regulation Existing order
------------------------------------------------------------------------
3154.10....................... 3162.7-3
3154.20....................... ................. Order Number 5
section III.C.1-3,
and 6-11.
3154.21....................... ................. Order Number 5
section III.C.21.
3154.30....................... ................. Order Number 5
section III.C.5.
3154.31....................... ................. Proposed Order Number
5, section III.D.11.
3154.32....................... ................. Order Number 5,
section III.C.12-16.
3154.33....................... ................. Order Number 5,
section III.C.17.
3154.40....................... ................. Order Number 5,
sections III.B. and
III.C.1 and 6; and
Proposed Order
Number 5, section
III.C.1, 2, and 6.
3154.50....................... ................. Order Number 5,
section III.D.
3154.60....................... ................. Order Number 5,
section III.C.19 and
20; and Proposed
Order Number 5,
section III.D.8.
3154.70....................... ................. Order Number 5,
section III.E.4.
------------------------------------------------------------------------

Gas Measurement--General
Section 3154.10 would establish the standards that would apply to
all measurement systems that are used to measure gas from Federal and
Indian lands. Any measurement system meeting these standards could be
installed and used without prior BLM approval. Currently, you are
required to obtain BLM approval before using anything other than an
orifice meter system. BLM believes that measurement systems that meet
the standards of this section would accurately measure gas to ensure
proper royalty payments. Measurement systems not meeting these
standards must either be approved by BLM before they are used or be
modified to meet the performance standards. This section also states
the base temperature and pressure at which you must report gas volumes
to MMS and references MMS reporting regulations for Federal and Indian
gas. Finally, the section would list the acceptable methods to
determine the volume of gas you use for beneficial purposes.
Orifice Meters--Primary Element
Section 3154.20 would identify the API standard that you must
follow to install, operate, and maintain an orifice meter. This section
would also supplement the API standard with additional requirements
that BLM believes are essential to ensure your orifice meter measures
accurately. The additional requirement that sets a 6-year meter tube
inspection frequency is new and is based on recommended industry
practice found in API Manual of Petroleum Measurement Standards,
Chapter 20.1, ``Allocation Measurement.'' This section would exclude
the additional standards for meters measuring less than 100 Mcf since
the cost of compliance for meters measuring lower volumes would likely
exceed the value of any additional Federal or Indian royalty that might
result. This section would also allow orifice meters installed before
the effective date of the final rule to comply with an earlier API
standard. This ``grandfathering'' of older orifice metering systems
would apply for as long as the existing system is in operation or until
the system is completely replaced, whichever comes first.
Section 3154.21 would require you to make volume determinations
through your orifice meter using the flow equations found in the
referenced API document. BLM currently requires you to use the same
equations to measure gas volumes. However, we do not currently
reference the API document containing those equations.

[[Page 66859]]

Orifice Meters--Secondary Element
Section 3154.30 would set the required tracking range for static
and differential pressures on your chart recorder. This section would
modify the existing requirement of Order Number 5, Section III.C.4, by
increasing the allowable range for differential pressures from the
upper 66.7 percent (i.e., 2/3rds) of the chart to the upper 80 percent.
(In regards to inverted charts, where the zero position is at the outer
limits of the chart, the accuracy of the differential element depends
on the physical distance of the pen from ``zero,'' regardless of the
type of chart you use.) BLM concluded that expanding the tracking range
would not significantly decrease overall meter accuracy because the
required range would still be well above the minimum differential
pressure range of a given meter. This change would better accommodate
wells with declining production.
This section would apply only to meters measuring more than 100 Mcf
of gas per day and would exempt meters where operating conditions such
as erratic flow patterns preclude tracking in the required range. The
latter exemption is not presently in Order Number 5 and was added as
result of BLM's experience with variance requests for meters servicing
wells with erratic flow patterns.
Section 3154.31 would establish additional requirements if your
secondary element uses an electronic flow computer (EFC). EFC's are not
addressed in existing Order Number 5 or other BLM regulations. However,
this section implements current policy. EFC requirements would be no
more stringent than those for chart recorders. The current static
pressure, differential pressure, and temperature would have to be
displayed on a continuous basis, and the EFC would be required to have
a back-up power source capable of retaining collected data for a
minimum of 35 calendar days. To meet the requirement to continuously
display parameters, EFC's may have either a scrolling display or a
toggle switch that allows the display to be activated.
Section 3154.32 would require you to calibrate your orifice meter
by following the recommended API practices for on-site calibrations.
Because it is not addressed in the referenced API standard, this
section would retain the requirement of Order Number 5, section
III.C.15, to test the linearity of differential and static pens at 100
percent of the element's range. This section would also require you to
document calibrations of your meter.
Section 3154.33 would establish how frequently you must calibrate
the secondary element of your orifice meter. Quarterly calibrations
would be required only for orifice meters that measure more than an
average of 100 Mcf or less per day on a monthly basis.
Orifice Meters--Low Volume Exemptions
Section 3154.40 requires orifice meters that measure an average of
100 Mcf or less per day on a monthly basis to comply with all the
requirements of this subpart except for the listed items. We believe
the cost for you to comply with these standards for low volume
production could exceed the value of the gain in measured gas from the
incremental increase in accuracy.
Some of the alternatives listed in this section are carryovers from
Order Number 5. New alternatives include--
(1) Waiving the six-year inspection requirement for the meter tube.
We believe that a six-year frequency of meter tube inspections for low
volume meters is not needed to ensure accurate gas measurement;
(2) Allowing the use of a temperature that reasonably represents
the average flowing temperature of the gas stream to calculate volumes.
As long as you use a temperature that reasonably represents flowing gas
temperature, you would no longer be required to submit a variance to
BLM for approval to use something other than a continuous temperature
recorder or an indicating thermometer, as you currently do under
existing Order Number 5;
(3) Calibrating your meter at least annually rather than quarterly.
BLM would pay particular attention to implementation of this exemption
to ensure that less frequent calibration of low volume meters does not
have an adverse impact on Federal and Indian royalty income; and
(4) Inspecting your orifice plate at least annually rather than
semiannually. As with annual calibrations, BLM would monitor the impact
of this requirement on measurement accuracy and royalty income.
Other Metering Systems
Section 3154.50 would deal with other metering systems and is
substantially similar to existing regulatory requirements.
Volume Corrections
Section 3154.60 would deal with volume corrections and is
substantially similar to existing regulatory requirements. However, the
proposed rule would drop the existing requirement from Order Number 5
that volumes are to be corrected only if the volume error is more than
2 percent. This gives BLM and MMS the flexibility to require volume
corrections when it is in the public interest.
Gas Quality Measurements
Section 3154.70 would require you to determine the quality of the
gas you produce at least annually, or more frequently, if BLM requires
it. This section would also identify--
(1) Where you must collect your sample;
(2) The industry standard you must follow to collect and handle
samples; and
(3) How you must determine the specific gravity and heating value
of the gas sample.
This section would cite API standards for collecting and handling
natural gas samples and would specify where samples are to be
collected. Existing regulations do not address this issue. Implementing
this section would ensure that sample collections are uniform in
determining the quality and liquid content of the gas.
Subpart 3155--Produced Water Disposal
This subpart would require you to obtain BLM approval before you
dispose of produced water. These sections would also require certain
construction and operating practices to ensure proper disposal of
produced water from Federal and Indian lands.

------------------------------------------------------------------------
Existing
Proposed regulation regulation Onshore order
------------------------------------------------------------------------
3155.10....................... 3162.5-1(b)...... Order Number 7,
3162.5-3 III.A., III.B.2.
3155.11 and 3155.12........... Order Number 7, I.C.
and requirement 1 of
III.F.
3155.13....................... Order Number 7,
III.A., III.B.1.,
III.B.2., III.C. and
III.G.
3155.14....................... Order Number 7,
III.B.1, III.B.2,
III.C., III.B.1.a.,
III.B.1.b.,
III.B.2a, and
III.B.2.b.

[[Page 66860]]

3155.15 and 3155.16........... Order Number 7,
II.D.1., III.D.2,
III.E. and
requirements 4
through 9 of III.F.
3155.17....................... Order Number 7,
requirement 11 of
III.F.
3155.18....................... Order Number 7,
III.G.1.F.
3155.19....................... Order Number 7, Part
III.A.
------------------------------------------------------------------------

Section 3155.10 would describe the reasons you must have BLM
approval to dispose of produced water from a Federal or Indian well, or
from a communitized or unitized private or State well for disposal into
a Federal disposal facility within the same communitized or unitized
area.
Sections 3155.11 and 3155.12 would describe when you need BLM
approval to dispose of produced water. This proposal would add two
instances to those in existing regulations that would not require BLM
approval for disposal of produced water. Under this proposal, BLM would
not require approval for the disposal of produced water if simultaneous
injection or disposal of produced water into the same formation occurs
in a producing well. This section would also eliminate the need for BLM
approval for disposal of produced water if it is injected into an
approved disposal well on the same Federal or Indian lease.
Section 3155.13 would describe the type of water disposal BLM
allows. This section includes the requirements from III.A., Order
Number 7, that lists how you must dispose of produced water from
Federal and Indian leases. This section would include additional
examples of disposal methods not in Order Number 7. We included these
examples to show other methods available to dispose of produced water
that could ultimately provide water for beneficial uses.
Section 3155.14 would describe the forms or permits you must submit
to construct and operate disposal facilities, and to obtain approval
for disposing of produced water. It also cites those regulations you
must follow that dictate the type of information that you must submit
with these forms. This section would list the BLM forms required under
different surface ownership, lease status, and disposal methods.
This section would require you to submit a Sundry Notice, Form
3160-5, or other acceptable filing instrument (letter) for water
disposal, unless you are drilling a Federal or Indian injection or
disposal well on-lease as part of your produced water disposal plan.
In addition to BLM approval, you must have an Underground Injection
Control (UIC) permit issued by the EPA, State, or Indian Tribe,
according to 40 CFR parts 144 and 146, before drilling an injection
well or converting an existing well to an injection well. The EPA,
State or Indian Tribe also require permitting for National Pollution
Discharge Elimination System permit (NPDES) facilities and the State or
Indian Tribe may require permitting for constructing and operating an
earthen pit. This section would provide the option to either submit a
copy of these permits from other agencies to BLM, or include a
reference to the location and permit name or number to BLM.
The proposed rule would also allow you to submit to BLM the same
information you use to obtain a UIC permit, earthen pit or NPDES
permit, if you are planning to construct or convert a Federal or Indian
facility into a water disposal facility.
This section includes the conditions that would require a BLM
right-of-way (R/W) or similar permit from other agencies, individuals,
or Indian tribes for constructing or operating disposal facilities,
roads, and pipelines. It also provides a reference to BLM's R/W
regulations.
This section would require that your Sundry Notice for disposal of
produced water include plans for construction of roads or pipelines on-
lease if they are part of your overall disposal plan.
Sections 3155.15 and 3155.16 would describe the requirements you
must follow to dispose of produced water into lined and unlined pits.
These sections would incorporate the requirements of parts III.D.1. and
2., III.E., and requirements 4 through 9 of III.F. of Order Number 7.
These sections would replace the extensive list of requirements found
in Order Number 7 with performance standards. The performance standards
would provide the flexibility to deal with different ecological and
geographical conditions, changing technology, specific proposals, and
local knowledge about specific design measures that are best suited to
local conditions.
Order Number 7 requires you to submit a water quality analysis that
tests specific parameters and also provides exceptions from this
requirement. The proposed rule would allow the same water quality
submittal exceptions found in Order Number 7, but the specific
requirements would be changed. This proposal would require that you
provide the information on the ``quality of the produced water'' with
your application for disposal of produced water into a pit. BLM has
determined that flexibility is needed to require testing when
necessary, but only for parameters that are unknown and needed to
process an application for the disposal of produced water.
This section would eliminate the detailed construction and design
provisions in Order Number 7. The detailed provisions in Order Number 7
would be replaced with standards that would allow you to design and
obtain permits for facilities without time consuming variance requests.
Section 3155.17 would require you to submit to BLM an amended
proposal to dispose of produced water if the quantity or quality of
produced water changes.
Section 3155.18 would describe what you must submit to BLM to
surface discharge produced water under a NPDES. This section would
incorporate the requirements of Order Number 7, III.G.1.F, with the
following change: This section would require you to submit information
you use to obtain an NPDES permit, if BLM requested it. This provision
would streamline the permitting process in situations where existing
applications for other agency permits already include information
required by this section (water quality analysis, description of site
facilities or surface use plans).
Section 3155.19 would explain that BLM would terminate your water
disposal permit if the EPA, State, or Indian tribe cancels or suspends
your disposal facility permit. This would require you to propose
another disposal method to BLM.
Subpart 3156--Spills and Accidents
This subpart would require you to report spills and accidents to
BLM. The term, ``Spills and Accidents'' would be used instead of the
currently used term, ``Undesirable Events.''
BLM determines if hydrocarbons are avoidably or unavoidably lost
even though oil and gas lessees must report this information to MMS (30
CFR, part 216, subpart B). Existing NTL-3A and this proposal do not
require you to file reports with BLM of spills or discharges

[[Page 66861]]

in nonsensitive areas involving less than 10 barrels of liquid or 50
Mcf of gas. BLM is able to monitor spills involving less than 10
barrels of oil by tracking MMS required reports. We still would require
that you report spills on all volumes of more than 10 barrels of liquid
or more than 50 Mcf of gas lost. These larger losses are cases that
could involve avoidably lost hydrocarbons and BLM will continue to make
avoidable and unavoidable determinations to ensure production
accountability.

------------------------------------------------------------------------
Existing Onshore order or
Proposed regulation regulation notice to lessees
------------------------------------------------------------------------
3156.10....................... 3162.5-1(c)
3156.11....................... ................. NTL-3A section I; and
Order Number 7,
III.H.
3156.12....................... ................. NTL-3A section II.,
Section III.; and
Order Number 7,
III.H.
3156.13....................... ................. NTL-3A section II.,
section IV.; and
Order Number 7,
III.A.3.
3156.14....................... ................. NTL-3A section II.
------------------------------------------------------------------------

Section 3156.10 would describe the actions you must take after an
accident or spill that involves Federal or Indian oil or gas. These
actions include corrective measures to mitigate the spill or accident,
reporting to BLM the spill or accident, and BLM's approval and
monitoring of your reclamation and remediation plans.
Section 3156.11 would describe the type of spills and accidents
that you must report to BLM within 24 hours of an event. In addition,
this section would implement several changes to the current
requirements.
The proposal would require you to report the release of hazardous
substances. Reporting this information to BLM would not relieve you of
any other reporting required by any State or other Federal regulations.
This proposal would eliminate the existing exception to 24 hour
reporting of spills of 100 barrels of liquids or more if they are
contained within the firewall. This quantity of oil or water in a
confined area could migrate deeper than a spill in an unconfined area
and affect shallow groundwater. In addition, a confined spill would
more likely attract birds and wildlife. BLM believes it is necessary to
report these types of spills within 24 hours to minimize contamination
and threats to wildlife.
Existing NTL-3A states that these types of spills or accidents
should be reported immediately and also states that reports must be
furnished, ``as soon as practical, but within a maximum of 24 hours.''
This section would require reports within 24 hours of the event. This
proposal would change the deadline for reporting major and life
threatening injuries. Existing NTL-3A requires reporting for these
types of injuries within 15 days of the event. BLM believes that a
major or life threatening injury is important information and should be
reported within 24 hours.
Section 3156.12 would describe the type of spills and accidents
that you are not required to report within 24 hours of an event and
when you would be required to submit initial written reports.
This section would not include an existing requirement to submit
two copies of a written report within 15 days following all spills and
accidents. Instead, this section would require a written report within
10 business days after a spill or accident occurs for specific events
listed, and all events that require you to notify BLM within 24 hours.
Section 3156.13 would describe what you must include in written and
oral reports. These standards would contain more guidelines than NTL-3A
and would require information that is directly related to the purpose
of requiring reports of spills and accidents. This would help BLM
determine if loss of oil or gas is avoidable or unavoidable, if sites
need to be inspected, if an approval is needed for spill remediation or
reclamation, and if corrective orders or contingency plans are needed
to address future events.
Section 3156.14 would describe when you must submit more than one
written report of a spill or accident to BLM. Under existing
regulations intermediate reports are required when BLM requests them.
This proposal would require intermediate reports to allow BLM to more
effectively monitor spill clean up.
Subpart 3159--Well Abandonment
This subpart would incorporate requirements from existing
regulations and some proposals from proposed regulations. Proposed and
existing regulations on well abandonment require you to submit a plan
to BLM for approval before a well is temporarily abandoned for more
than 30 calendar days and before a well is permanently abandoned. This
subpart also explains how to obtain BLM approval for abandonment and
sets the performance standards that you must meet when you plug a well.
This subpart generally contains existing requirements with a few
exceptions.

------------------------------------------------------------------------
Existing
Proposed section regulation Existing orders
------------------------------------------------------------------------
3159.10....................... 3162.3-4(c)...... Proposed Order Number
3159.11 8 section III.C.1.
and 2.
3159.20....................... 3162.3-4(a)
3159.21....................... 3162.3-4(a)...... Order Number 2
section III.G.
3159.22....................... ................. Proposed Order Number
8 section III.D and
Order Number 2
section III.G.
3159.23....................... ................. Proposed Order Number
8 section III.D and
Order Number 2
section III.G.
3159.24....................... 3162.3-4(b) .....................
3159.25....................... 3162.3-4......... Proposed Order Number
8 section III.D.3.b.
3159.26....................... 3161.2........... Proposed Order Number
8 section III.D.1.
------------------------------------------------------------------------

Temporary Abandonment
Section 3159.11 would set out the basic performance goals for
temporary abandonment operations. This section would implement existing
policy that you temporarily abandon a well so that it does not prevent
proper permanent abandonment, the well bore is secured

[[Page 66862]]

to prevent fluid migration and the wellhead is secure at the surface.
Permanent Abandonment
Section 3159.20 would identify when you must permanently plug and
abandon a well. This section also allows you to delay the permanent
abandonment of your well if BLM approves it. Each approved delay may be
for up to 12 months. BLM is concerned with the liability associated
with temporarily abandoned wells, and therefore this proposal would
impose additional bonding as a condition of approval (see sections
3107.54 and 3107.55).
Section 3159.21 would describe how to obtain BLM approval to
permanently abandon a well. It would require you to submit a ``Notice
of Intent to Abandon'' along with information on abandonment and
reclamation procedures. This section would allow BLM to issue oral
approvals for permanent abandonment for newly drilled dry holes,
drilling failures, and in emergency situations, provided you submit a
written application within five business days of BLM's oral approval.
This section also explains that the FS has the authority to approve
plans to reclaim the surface on lands it manages.
Section 3159.22 would set standards and incorporate by reference
the minimum standards from the API's Bulletin E3 for well abandonment
practices. Permanent abandonment is the final opportunity to ensure
proper protection of surface and down hole resources. As such, this
section would not institute a performance-based approach and it would
retain the details of existing abandonment regulations.
Section 3159.26 would require you to submit a ``Subsequent Report
of Abandonment'' (SRA) on Form 3160-5, within 30 calendar days after
you complete permanent well plugging operations, including any changes
that BLM approved orally. This section would also allow you to
eliminate the additional notification if the SRA contains the estimated
timetable for completing recontouring and reclamation procedures. If
you chose not to submit the timetable for recontouring and reclamation,
a ``Final Abandonment Notice'' (FAN), Form 3160-5, would be required to
notify BLM that the site is ready for final inspection. BLM would
approve the SRA or FAN after it determines that you have complied with
all conditions of your abandonment and that vegetation has been
established to the satisfaction of BLM or the surface management
agency.
Part 3160--Oil and Gas Inspection and Enforcement
Subpart 3161--Inspections
This subpart would explain the general purposes of BLM's inspection
of lease operations. The proposal would require you to allow authorized
inspectors to conduct inspections of your operations. These regulations
would implement provisions of FOGRMA that allow inspection of motor
vehicles that transport Federal and Indian oil. This subpart contains
existing regulatory requirements.

------------------------------------------------------------------------
Proposed section Existing regulations
------------------------------------------------------------------------
3161.10.......................... 3161.2.
3161.11.......................... 3162.1(b) and (c).
3161.12.......................... 3162.7-1(c)(3) and (4).
------------------------------------------------------------------------

Subpart 3162--Enforcement
This subpart would explain the enforcement actions BLM will take
after we discover a violation. Enforcement actions include notifying
you of violations in writing and providing a reasonable time to correct
violations. Also, if necessary to gain compliance, BLM may order you to
shut down your operations. This subpart contains existing regulatory
requirements.

Subpart 3163--Assessments
Under this subpart, BLM would charge you a monetary assessment if
you fail to correct a violation within the time set out in BLM's
notice. This subpart would also include provisions for immediate
assessments for certain serious violations. Under this proposal BLM
would also be able to enter your lease to correct violations at your
expense and would charge you for actual loss or damage due to your
noncompliance. This subpart would contain existing regulatory
requirements with some exceptions.

Section 3163.10 would allow BLM to assess a monetary assessment up
to $250 per day for each day a violation continues beyond the abatement
period. This section states that you will also be liable for civil
penalties under proposed subpart 3164.
This section would eliminate existing regulatory provisions which
classify violations into ``major'' and ``minor'' categories and the
corresponding assessment amounts of $500 per day for major violations
and a one-time $250 for minor violations. This section would also
eliminate existing provisions which cap assessments for major
violations at $1,000 per day per lease and minor violations at $500 per
lease per inspection. There would be no caps on either the amount of
assessments per day per lease or the total assessment amount that could
accumulate per violation.
Section 3163.11 would contain a table that lists serious violations
and a corresponding assessment amount BLM would charge you immediately
when the violation is discovered. The table was compiled from the
specific violations listed in existing 43 CFR 3163.1(b) (1) through (3)
and adds new violations subject to immediate assessments for--
1. Conducting surface disturbance without an approved BLM permit
for a Federal or Indian well, regardless of surface ownership. This
would deter operators from building access roads and locations or
disturbing the surface without BLM approval. This section would also
add an assessment for surface disturbance on surface managed by another
Federal agency or on State or privately owned surface;
2. Repeat Offenders. The ``repeat offender'' violation would be
added in response to problem operators who, after BLM notifies them of
a violation, continue to repeat that violation. This section is aimed
at repeat offenders who correct a violation within the time BLM gives
them to correct it, thus avoiding an assessment. However, the operator
often repeats the violation and corrects it only when they are notified
again by BLM of a new violation. Operators engaging in this activity
often repeat a violation many times. This pattern of compliance results
in excessive and unnecessary administrative cost to BLM. The proposed
assessment of $500 would be to deter those repeat violators who comply
just enough to avoid assessment. The repeat offender assessment would
be triggered when BLM cites you for the same type of violation four
times on the same lease within a 12-month period;
3. Commingling production without BLM approval from different
formations, leases, communitized areas,

[[Page 66863]]

units, or unit participating areas. This violation would be added
because commingling without approval is a serious impediment to BLM's
ability to ensure production accountability; and
4. Failure to notify BLM of H2S concentrations as
required by these proposed regulations. This violation would be added
because of the serious health and safety risks hydrogen sulfide poses
to both the general public and BLM inspection personnel.
In addition to expanding the list of violations that will earn an
immediate assessment, BLM proposes to charge an increased, one-time
assessment for any violation on the list. This would simplify the
approach in current regulations which applies an assessment amount per
violation per day up to a maximum amount per incident. The size of the
proposed one-time assessment is set at an amount BLM believes is
necessary to emphasize the seriousness of the listed violations. BLM
may charge up to the proposed amounts to deal with specific
circumstances.
Section 3163.12 would allow BLM to reduce or waive an assessment
that you receive. You must provide your reasons in writing why BLM
should reduce or waive the assessment within 30 calendar days after you
receive your notice of assessment.
Section 3163.13 would authorize BLM to occupy your lease to perform
necessary work to correct a violation, at your risk and expense,
whenever you fail to perform the work BLM directed you to perform. If
BLM performs the work to correct a violation, you would be charged for
the actual cost to perform the work plus an additional 25 percent for
administrative costs. This is not a change from current requirements.
Section 3163.14 would allow BLM to charge you for any loss or
damage to Federal resources that result from your noncompliance. This
is not a change from current requirements.
Subpart 3164--Civil Penalties
Under this subpart, you would be subject to civil penalties for
violations of any statute, regulation, order, notice to lessee, lease,
or permit relating to your obligations under this part. This subpart
would describe the amounts of civil penalties, when you become liable
for civil penalties, and notices you will receive from BLM. There are
provisions for BLM to charge you immediate civil penalties for certain
serious violations. BLM would also initiate cancellation of your lease
if the noncompliance continues.

------------------------------------------------------------------------
Proposed section Existing regulation
------------------------------------------------------------------------
3164.10............................. 3163.2(a) and (b).
3164.11
3164.12............................. 3163.2 (a) and (b).
3164.13............................. 3163.2(d) through (f).
3164.14............................. 3163.1(a)(5)
and 3163.2(k).
3164.15............................. 3163.2(h).
3164.16............................. 3165.3(c)
and 3165.4(b)(2).
3164.17............................. 3165(e)(2).
3164.18............................. 3165.4(b)(1).
3164.19............................. 3165.4(f).
3164.20............................. 3163.4 and
3163.5(a) and (b).
3164.21
3164.22............................. 3163.2(a),
(b), and (i).
3164.30............................. 3163.3.
------------------------------------------------------------------------

Section 3164.10 would explain that BLM may assess civil penalties
under FOGRMA, as provided in existing regulations.
Section 3164.11 would describe when BLM will assess civil penalties
and would explain the requirements for service of Notices of Incidents
of Noncompliance (INC). These requirements are similar to existing
regulations.
Section 3164.12 would explain the actions you must take after
receiving an INC for civil penalties. If you receive an INC for civil
penalties, you must correct the violation within 20 calendar days or
you are liable for a penalty of up to $500 per day per violation for
each day the violation continues beyond the date you received the INC.
If you did not correct the violation within 40 calendar days of the
initial INC, you would be liable for up to $5,000 per violation for
each day the violation continues beyond the date you received the INC.
This section would also explain that you would be able to request a
hearing on the record on the INC if you did not correct the violation
within 20 calendar days of your receiving the INC. Of course, you are
risking an assessment of penalties if you do not correct the
violations. If you did correct the violation within 20 calendar days of
receiving the INC to avoid a penalty assessment, you would not have the
option of requesting a ``hearing on the record.'' However, you would be
able to appeal the INC under the appeals provisions of this part if you
thought BLM issued the INC erroneously.
Section 3164.13 would explain that BLM would issue INC's for
serious violations. This section lists several serious violations that
are set out in FOGRMA and lists their corresponding penalty amounts
(see 30 U.S.C. 1719). Existing regulations cap the maximum total
penalty amount per violation. However, this proposal would not dictate,
nor does FOGRMA impose, a cap on the total civil penalty amount.
Section 3164.14 would explain the action BLM would take if you do
not correct a violation listed in section 3164.13. The actions BLM
could take would include lease cancellation for the violations listed
in sections (b) through (f) of section 3164.13. These requirements are
similar to existing regulations.
Section 3164.15 would explain that you may request BLM to waive or
reduce civil penalties within 30 calendar days after you receive notice
of the proposed civil penalty. These requirements are similar to
existing regulations.
Section 3164.16 would explain that you may request a hearing on the
record for serious violations within 20 calendar days of receiving the
INC. Existing regulations are similar to this provision.
Section 3164.17 would explain that penalties accrue each day until
you correct the violation. Under this proposal, BLM may suspend the
requirement that you correct the violations pending completion of the
hearings provided for in this subpart. Existing procedure and
regulations are similar to this proposal.
Section 3164.18 would explain that you may appeal a decision of the
Administrative Law Judge to the Interior Board of Land Appeals. This is
the same as existing regulations.
Section 3164.19 would explain that you may appeal a final order to
the U.S. District Court with jurisdiction over the lands where the
violation took place. This is the same as existing regulations.
Payment of Assessments and Civil Penalties
Section 3164.20 would require you to pay assessments within 30
calendar days after BLM gives you written notice and civil penalties
within 30 calendar days after either a final BLM decision or a final
order of a court or other legal body. This section would also provide
for any civil penalties you pay to be deducted from any monies the
United States owes you.
Section 3164.21 would state that BLM would charge you interest on
assessment amounts that you have not paid or underpaid.
Section 3164.22 would allow BLM to deduct any assessments you have
paid from any civil penalties you are required to pay under this
subpart. Assessments and penalties charged to you under this part would
be in addition to any assessment or penalty

[[Page 66864]]

you are charged for your noncompliance under other provisions of law.
Section 3164.30 would inform you that you may be liable for both
civil and criminal penalties for violating these regulations. This is
not a change from existing regulations.

IV. Procedural Matters

Regulatory Planning and Review

In accordance with the criteria in Executive Order 12866, BLM has
determined that this rule is not a significant regulatory action. The
Office of Management and Budget (OMB) makes the final determination
under Executive Order 12866. BLM has determined that the rule does not
meet any of the criteria for a significant regulatory action, as
discussed below and in the Economic Analysis.
a. The proposed rule will not have an annual effect on the economy
of $100 million or more or adversely affect in a material way the
economy, a sector of the economy, productivity, competition, jobs, the
environment, public health or safety, or State, local, or tribal
governments or communities. An economic analysis has been completed and
is attached (see Economic Analysis).
b. This rule will not create inconsistencies with other agencies'
actions. This rule does not change the relationships of the oil and gas
program with other agencies' actions. These relationships are all
encompassed in agreements and memorandums of understanding that will
not change with this proposed rule.
c. This rule will not materially affect entitlements, grants, loan
programs, or the rights and obligations of their recipients. However,
this rule proposes to add a fair market value user fee (FMV) for the
use of the public lands for geophysical exploration for each Notice of
Intent to Conduct Oil and Gas Geophysical Exploration Operations. The
Federal Land Policy and Management Act of 1976 (43 U.S.C. 1701 et seq.)
(FLPMA) requires that ``the United States receive the FMV for the use
of the public land and its resources unless otherwise provided for by
statute.'' In addition, a May 1992 audit report by the U.S. Department
of the Interior, Office of Inspector General (OIG), recommended that
BLM establish and implement procedures to charge FMV for geophysical
exploration. In order to comply with the requirements of FLPMA and the
OIG recommendation, we propose to adopt a FMV for geophysical
exploration. The FMV would be based on the size of the area physically
affected by each individual geophysical exploration project. You would
not be required to pay the FMV for a geophysical exploration project,
or a portion of a project, that is conducted under a Federal oil and
gas lease. BLM will determine the amount of the user fee in a future
action.
d. This rule will not raise novel legal or policy issues. Some of
the proposed rules may be controversial (bonding increases, agreement
rules, immediate assessments, and automatic assessments for repeated
noncompliance), but they are not novel. Some have been tried in the
past and others have been used by some States.

Regulatory Flexibility Act

This rule will not have a significant economic effect on a
substantial number of small entities as defined under the Regulatory
Flexibility Act (5 U.S.C. 601 et seq.). A final Regulatory Flexibility
Analysis is not required. Accordingly, a Small Entity Compliance Guide
is not required.
For the purposes of this section a ``small entity'' is considered
to be an individual, limited partnership, or small company, considered
to be at ``arm's length'' from the control of any parent companies,
with fewer than 500 employees or less than $5 million in revenue. Mid-
sized and large corporations and partnerships under their direct
control have access to lines of credit and internal corporate cash
flows that are not available to the ``small entity.'' Many of the
operators we work with in the oil and gas program would be considered
small entities.
The only proposed change that may have the potential to affect a
significant number of small entities is the increased bonding
requirements. As discussed in the Economic Analysis, the costs would be
negligible. The two basic changes in bonding are increases in minimum
State and lease bonds, and specific fees and bond increases for shut-in
and temporarily abandoned wells. Lease and well specific bonding
increases are already authorized by the existing regulations. The
proposed rule better enables BLM and the operator to predict what these
costs will be when the operator is planning future actions. The
additional bond requirements would provide an incentive to these
operators to acquire the additional resources or sell their wells to
other operators that can meet the obligations before BLM notifies the
operator that his bond requirements have increased. Operators consider
reductions of uncertainty to be a major benefit. Another benefit for
many small entities is that operators with low liabilities could
qualify for a bond reduction.
While the increased minimum State and lease bonding may affect a
large number of small entities, at an average of $43 per well per year,
the impact on each entity will be small (see Economic Analysis). For
example, for a stripper oil well producing only five barrels per day at
a profit of $2 per barrel, the additional bonding cost would be covered
by the profit from three weeks of production. Thus, there would not be
a significant impact on a substantial number of small entities under
the Regulatory Flexibility Act (5 U.S.C. 601 et seq.).

Small Business Regulatory Enforcement Fairness Act

This rule is not a major rule under 5 U.S.C. 804(2), the Small
Business Regulatory Enforcement Fairness Act. This rule:
a. Does not have an annual effect on the economy of $100 million or
more, as demonstrated in the Economic Analysis.
b. Will not cause a major increase in costs or prices for
consumers, individual industries, Federal, State, or local government
agencies, or geographic regions. The increase in bonding requirements
will be offset by a reduction in orphan wells, thereby reducing the
costs to the public of reclaiming those wells. The amount of the
proposed FMV user fee for geophysical exploration is not known at this
time. The amount will be determined in a separate action and the
estimated economic impact will be discussed at that time. BLM plans to
determine the FMV fee before the final rule is published and the
economic impacts will be discussed in the final rule.
c. Does not have significant adverse effects on competition,
employment, investment, productivity, innovation, or the ability of
U.S.-based enterprises to compete with foreign-based enterprises. The
shift to performance standards in the operating regulations should
increase innovation and productivity and thereby increase the ability
of the domestic oil and gas industry to compete in the global
marketplace.

Unfunded Mandates Reform Act

In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501
et seq.):
a. This rule will not ``significantly or uniquely'' affect small
governments. A Small Government Agency Plan is not required. This
proposed rule does not change the relationship of between BLM's oil and
gas program and small governments.

[[Page 66865]]

b. This rule will not produce a Federal mandate of $100 million or
greater in any year, i.e., it is not a ``significant regulatory
action'' under the Unfunded Mandates Reform Act (see Economic
Analysis).

Takings

In accordance with Executive Order 12630, the rule does not have
significant takings implications. A takings implication assessment is
not required. The proposed rule would not take away or restrict an
operator's right to develop an oil and gas lease in accordance with the
lease terms.

Federalism

In accordance with Executive Order 12612, the rule does not have
significant Federalism effects. A Federalism assessment is not
required. The proposed rule does not change the role or
responsibilities among Federal, State, and local governmental entities.
The rule does not relate to the structure and role of States and will
not have direct, substantive, or significant effects on States.

Civil Justice Reform

In accordance with Executive Order 12988, the Office of the
Solicitor has determined that the rule does not unduly burden the
judicial system and meets the requirements of sections 3(a) and 3(b)(2)
of the Order. BLM drafted this rule in ``Plain-English'' to provide
clear standards and to ensure that the rule is clearly written. BLM
consulted with the Department of the Interior's Office of the Solicitor
throughout the rule drafting process for the same reasons.

National Environmental Policy Act

BLM has prepared an environmental assessment (EA), and has made a
tentative finding that the proposed rule would not constitute a major
Federal action significantly affecting the quality of the human
environment under section 102(2)(C) of NEPA, 42 U.S.C. 4332(2)(C). BLM
anticipates making a Finding of No Significant Impact for the final
rule in accordance with BLM's procedures under NEPA. BLM has placed the
EA on file in BLM Administrative Record at the address specified
previously (see ADDRESSES). BLM will complete an EA on the final rule
and make a finding on the significance of any resulting impacts prior
to promulgation of the final rule.
The proposed action would have no major impact on the human
environment, either positive or negative. The revised regulations may
provide some environmental benefits.
The proposed action would cause some impacts on the environment,
although most of the requirements in the proposed action would cause no
changes to the environment. Most of the proposed changes would not
differ substantially from the existing regulations, such as the
portions which are being written in plain English, or the plan to
remove unnecessary procedural requirements and actions which need
approval from BLM. For example, the proposal would exempt operators of
Federal oil wells that produce less than 10 Mcf/day from having to
obtain approval to vent or flare gas. This provision includes a
performance standard that would in effect negate this exemption if the
gas is economic to capture or if it cannot be vented or flared safely
and according to applicable laws and regulations. The environmental
impact of this provision is identical to the no action alternative
because BLM almost always approves venting or flaring applications for
these small gas volumes and the only reason an application would not be
approved under the existing regulations would be if BLM determines that
the gas is economic to capture. BLM would retain the authority to issue
an order to capture gas under the provisions of the proposed action.
Under current regulations, an operator that follows all of the
terms of a given regulation, theoretically, could be in compliance
regardless of whether their operations meet the overriding objectives
of BLM's management of the oil and gas program. By contrast, with
performance standards the focus would shift from describing specific
actions that dictate how operations must be conducted, to the
regulation's desired outcome or goal. This goal-oriented approach would
better protect the public interest and the environment because
operators would be held to a sensible, stated regulatory standard. This
type of regulation would also provide oil and gas operators the
flexibility they seek to determine how a stated objective could be
achieved, depending on specific proposals, local conditions, the
operating environment and changing technology.
The substantive changes contained in this rule do not directly
pertain to environmental protection measures or BLM's responsibility to
comply with existing environmental laws and regulation. However, they
are more likely to enhance BLM's role as a steward of the public lands
than undermine it. In addition, the proposed action would only include
performance standards if they would not jeopardize BLM's ability to
fulfill its responsibility to protect public health and safety and the
environment. Therefore, BLM's use of performance standards, to the
extent that they depart from the existing system, would not have an
impact on the environment.
Changing many of the minimum standards contained in the onshore
orders to references to the API standards would have no impact on the
environment. Incorporating industry standards by reference does not
represent a profound change, because the onshore orders currently
paraphrase many of these same standards. Incorporating the standards by
reference directly into the regulations simplifies how the standards
are organized. Since the same standards would be used, this should not
result in any impacts to the environment.
BLM's proposal to limit competitive and noncompetitive lease
acreage to 2,560 acres outside Alaska and 5,760 acres in Alaska should
not impact the environment. This measure would lower the acreage limit
for noncompetitive leases to make it consistent with competitive
leasing. The remainder of changes to the leasing regulations, with the
exception of the changes to bond provisions, affect only administrative
activities and would not impact the environment.
Other substantive changes would more likely result in a positive
benefit to the environment, although the extent of any benefits is
presently too speculative to assess. For example, raising the bonds
required would not only increase an operator's incentive to prevent
adverse environmental impacts, but would also provide BLM a source of
funds to clean up or correct any negative impacts caused by oil and gas
operations. This would reduce the BLM's and the public's exposure to
future liabilities associated with plugging wells and reclaiming well
sites. Raising the dollar amounts and expanding the number of types of
penalties for noncompliance and removing assessment and civil penalty
caps would offer additional incentives for operators to meet all
environmental standards.
These and the impacts discussed in the economic analysis are the
only foreseeable impacts of the proposed action. BLM recognizes that
slight changes to complex regulatory schemes can have unintended
downstream effects. However, whether such ``ripples'' would themselves
lead to environmental impacts is something that cannot be meaningfully
assessed at this time. Furthermore, because the program consists of
leasing Federal land and permitting resource development of

[[Page 66866]]

Federal and Indian oil and gas, the individual actions taken under this
program are themselves subject to further NEPA analysis. When actions
are proposed under the oil and gas leasing and operations program, BLM
will prepare all required NEPA documents.
Because the proposed action would not substantially change BLM's
overall management objectives or environmental compliance requirements,
the proposed rule would have no impact, or will only marginally
benefit, the following critical elements of the human environment as
defined in Appendix 5 of the BLM National Environmental Policy Act
Handbook (H-1790-1): air quality, areas of critical environmental
concern, cultural resources, Native American religion concerns,
threatened or endangered species, hazardous or solid waste, water
quality, prime and unique farmlands, wetlands, riparian zones, wild and
scenic rivers, environmental justice and wilderness.

Government-to-Government Relationship With Tribes

In accordance with the President's memorandum of April 29, 1994,
``Government-to-Government Relations with Native American Tribal
Governments'' (59 FR 22951) and 512 DM 2, we have identified potential
effects on Indian trust resources and they are not yet addressed in
this rule. BLM has consulted with the Bureau of Indian Affairs in the
process of this rulemaking and plans to consult with affected tribes
prior to final rulemaking. Furthermore, BLM will consider tribal views
in the final rulemaking. Accordingly:
a. We have not yet consulted with the affected tribe(s).
b. We have not yet treated and consulted with tribes on a
government-to-government basis. However, we plan to before final
rulemaking and the consultations will be open and candid so that the
affected tribe(s) could fully evaluate the potential impact of the rule
on trust resources.
c. We will fully consider tribal views in the final rulemaking.
d. We have consulted with the appropriate bureaus and offices of
the Department about the potential effects of this rule on Indian
tribes. We have consulted with the Bureau of Indian Affairs and the
Division of Indian Affairs, Office of the Solicitor.
Economic Analysis
These regulations would increase the amount of lease and statewide
performance bonds. Presently, operations are covered by lease,
statewide, or nationwide bonds with some collective bonds on units. The
increased bond requirements will take effect in two years. The rule
clarifies BLM's authority to increase the required bonding level for
existing bonds where an operator has been delinquent in meeting his
obligations to the government or where the potential costs of plugging
and reclaiming the site exceed the bonds covering those operations.
Increasing the penalties for noncompliance is also proposed. Both of
these proposals will have minimal effects on the economy or the costs
of producing oil and gas on Federal lands. The primary impact will be
to avoid potential problems by:
Increasing the probability that operators have sufficient
financial capability to meet their lease obligations (i.e., if the
operator can meet the higher bonding requirement, then he is more
likely to have the financial means to meet his other operational
requirements),
Provide a greater incentive to the operator to properly
reclaim his lease so that he can recover his bond collateral, and
Increase the funds available to the land owner/manager if
the operator defaults on his obligations.
Small operators with only a few shallow wells, where the
reclamation cost is much less than the standard bond coverage, would be
able to apply for a reduction in the required bond coverage. The
operator must demonstrate that the costs would be less than the bond
coverage in order to receive approval for a reduction in the bond
requirement. The impact of this change would be to help small operators
by relieving them of unnecessary bond requirements.
The purchase of manuals describing the industry standards
referenced in the regulations is another cost to operators and lessees,
but it is not expected to be a significant cost.
There would be no discernible economic impact on prospective and
existing operations due to compliance with the standards found in this
proposed rulemaking. In most cases, the cost of complying with the
standards would be indistinguishable from those in the existing
regulations. The use of performance standards and published industry
standards in many places in these proposed rules may even reduce the
cost of compliance in some cases. Overall, however, these benefits will
be local in nature and be almost indistinguishable from the existing
regulations.
The benefits attributable to these rules are not predictable in the
usual strict benefit-cost analysis sense. Discernible changes in the
ease of using and understanding the proposed regulations, as well as
the elimination of duplication and confusion, will certainly benefit
lessees, operators and the BLM. The reduction in the length and number
of the existing regulations will also have some benefit. How much of a
benefit these changes will actually have is not quantifiable.
The overall effect of the proposed rule will not create an adverse
effect upon the ability of the oil and gas industry to compete in the
world marketplace, nor will the proposal adversely affect investment or
employment factors locally.

Discussion of Potential Impacts

Referencing Published Industry Standards

The most obvious impact associated with this change would be the
cost of acquiring the publications that the rule would incorporate by
reference. This cost would be borne by both industry and BLM. The total
cost to acquire all 26 API publications referenced in the proposed rule
would be less than $1,500. A typical operator on a Federal lease would
not need to acquire all 26 referenced publications, but only those
publications that they do not already have and that directly apply to
the particular activities that it conducts. We anticipate that many
smaller producers would not purchase any referenced publications at all
and depend on other sources to inform them of required industry
standards. All BLM field offices with oil and gas responsibilities will
have copies of the API publications available for review. For
evaluation purposes, we will assume the average operator will spend
$300 on referenced publications.
BLM's Automated Inspection Records System (AIRS) data base lists
6,610 operators on Federal leases/agreements. This total overstates the
actual number of operators due to differences in how one operator's
name may be entered in the database (i.e., XYZ, Inc. and XYZ,
Incorporated are counted as two different operators). Alternately,
larger producers operating across multiple BLM inspection offices may
acquire multiple sets of the API publications. For simplicity sake, the
operator total from AIRS will be used without adjustment, making the
projected cost to industry to acquire referenced documents to be
$1,983,000 (i.e., 6610 operators @ $300/operator).

[[Page 66867]]

We will also assume that the 38 BLM offices (combined total of
field and state offices) with responsibilities for oil and gas
operations would need to acquire a complete set of the publications
referenced in the proposed rule. Many BLM offices already have a
majority of the API publications as in-house reference documents.
Again, for simplicity's sake we will assume the entire suite of
publications would be acquired by each of the 38 BLM offices for a
projected cost to the Federal Government of approximately $57,000.
BLM believes that the initial cost to industry in acquiring the API
publications would be offset by the long term intangible benefits
associated with incorporating API standards and practices into
regulation. These intangible benefits are the value of consistency,
clarity, and flexibility derived from citing widely accepted industry
standards rather than the present approach of regulations that are
intended to interpret those same standards. In general, adoption of
industry standards results in efficiency gains by operators performing
activities consistently. This same simplification will likely result in
lower supply costs in the long term. Consequently, BLM believes that
referencing published industry standards in regulation will have a net
positive impact on industry. There are also benefits to BLM from
greater compliance by industry. More consistency and compliance by
industry reduces the costs of inspection and enforcement. These reduced
costs would help offset the costs that BLM would incur by acquiring API
publications since greater compliance by operators equates to less
administrative cost to BLM.

Reduce Paperwork for Communitization Agreements

Industry contacts estimate the cost to prepare and submit a
proposal to communitize Federal minerals costs an average of $1,000 per
application. BLM estimates that it expends about 20 hours to process
each application at a cost of $460. In fiscal year (FY) 95, BLM
received 166 applications to communitize with a projected cost to
industry of $166,000 and a projected cost to BLM of $92,000. The
proposed rule would reduce the amount of paperwork that industry has to
submit to BLM in order to communitize Federal mineral interests. Less
paperwork would reduce the administrative costs both for industry and
for BLM.

Simplify Procedure to Determine Average Daily Production per Well for
Variable Royalty Rate Leases

For variable royalty rate leases, the average daily production per
well determines what royalty rate to apply to production. Preliminary
calculations using the proposed method to determine average daily
production per well show it to be royalty ``neutral'', that is, it
should not result in any more or any less royalty being paid to the
United States. Hence, the only impact associated with the proposed
change would be in administrative costs associated with using the
proposed method versus the existing method. Although we do not have any
specific estimates of how many work-hours are expended to determine the
average daily production per well under either method, the proposed
method, without question, would involve less time than the existing
method. Less time translates to less labor costs. Reduced labor cost is
a positive impact. In addition, simpler procedures are less likely to
result in different interpretations. Thus, the time and effort involved
in resolving disputes over interpretation of the regulations will be
reduced. Both industry and BLM would benefit from the savings in labor
costs.

Regulatory Exemptions for Meters Measuring 100 Mcfgpd or Less

Under the proposed rule, operators of metering facilities that are
measuring 100 thousand cubic feet of gas per day (Mcfgpd) or less would
not be required to:
Perform an inspection of the meter tube every six years;
Install a continuous temperature recorder to record
flowing gas temperature;
Calibrate the meter on a quarterly basis;
Have the meter's static pen track within specific areas of
a gas chart; or
Maintain an overall meter uncertainty within 3
percent if the meter uses an electronic flow computer.
The exemptions should have a positive impact on industry by
reducing the capital and operating expenses of low volume metering
facilities. A reduction in operating expenses would proportionately
raise the economic limit of low volume gas wells and allow for
increased recovery of in-place reserves. These exemptions would also
have a positive impact on the Federal Government by increasing the
ultimate amount of royalty it would receive. Positive impacts specific
to BLM would be a reduction in the number of variances that it would
have to process and a reduction in its costs to inspect for and enforce
these standards.

Require an Annual Determination for Specific Gravity

Existing regulations call for the heating value (i.e. BTU content)
of marketed gas to be determined annually, but do not specify a
frequency for specific gravity determination. The proposed rule would
require operators to determine specific gravity of gas at least on an
annual basis. BLM assumes that most laboratories also determine the
specific gravity of gas when calculating the BTU content of a gas
sample. Accordingly, requiring an annual specific gravity determination
for leases and agreements producing gas would not cause any increase in
operating cost for producers. In that values for BTU content and
specific gravity are important in determining the volume of gas
produced and its quality for royalty purposes, the proposed change
would have a positive impact on production accountability.

Eliminating Major/Minor Classification of Violations and Simplifying
Assessment Structure

Existing regulations classify violations into two categories: major
violations, which, if left uncorrected, could cause immediate,
substantial, and adverse impacts to public health and safety,
production accountability, or the environment; and minor violations,
those violations which do not rise to the level of a major violation.
For major violations, operators were liable for an assessment of up to
$500 per day if left uncorrected within a time frame specified by BLM.
For minor violations, operators were liable for a one-time $250
assessment for violations left uncorrected. The proposed rule would
eliminate the major and minor classification for violations and impose
a $250 per day assessment for uncorrected violations.
This proposed change should have no impact on industry as a whole.
Over the last four fiscal years, BLM had issued an average of 2,735
citations for major violations per year and 13,752 citations for minor
violations per year. We estimate that less than 7 percent of the major
violations and less than 1 percent of the minor violations have
resulted in an assessment being issued to operators. The small number
of violations that ever get to the assessment stage suggest that
changing the fee structure of assessments will have a negligible impact
on industry.
The potential for an assessment encourages compliance. We do not
believe that changing the fee structure

[[Page 66868]]

for assessments will reduce the compliance rate that is observed under
the existing regulations, especially with elimination of the cap on
assessments and civil penalties. If anything, we believe that the
proposed rule's increased assessment for those violations that are
presently classified as minor violations might actually reduce the
number of these kinds of violations. For this reason, the proposed rule
assessment structure is likely to have a positive impact on the public.
That is, fewer violations means a reduction in the potential for
environmental problems.
The proposed changes to the assessment structure would have a
positive impact on the Federal Government. Eliminating the
classification of violations would eliminate the subjectiveness that
exists with the existing system in determining whether a violation is
major or minor. The proposed single daily assessment amount would be
easier to administer. A simpler, more consistent approach to violation
classification and assessment structure translates to reduced
administrative costs to the Government.

Remove all Caps for Assessments and Civil Penalties

Per day assessments and civil penalties are currently limited to
some maximum amount, limiting the incentive to the operator to correct
the violation quickly. It is expected that exceeding the current caps
will happen rarely, but elimination of the cap should encourage faster
correction of violations. Thus, there is negligible impact on industry
with some positive impact on the public and the government.

Increased, One-time Assessment for Serious Violations

Under existing regulations, certain serious violations (i.e.,
drilling without approval, causing surface disturbance without
approval, and failure to install a blowout preventer) earned an
operator an immediate assessment of $500 per day up to a set maximum
amount. In addition to the aforementioned violations, plugging a well
without approval resulted in a one time $500 assessment. The proposed
rule eliminates the amount per day assessment structure for serious
violations and replaces it with increased, one-time amounts.
Due to the limited number of immediate assessments issued by the
BLM in any given year, we project the impact to industry of this
proposed change would be negligible. Since we believe the increased
assessments would represent an even greater deterrent to serious
violations, the proposed change would have a positive impact on the
public. Fewer serious violations would mean less potential harm to
public health and safety and the environment. Again, a simplified
assessment structure would reduce the Government's administrative
costs, a positive impact.

Expand List of Violations That Receive an Immediate Assessment

For the reasons mentioned in the previous section, the proposal to
expand the list of serious violations that would receive an immediate
assessment should have a negligible impact to industry, a positive
impact on the public, and a positive impact on the Federal Government.

Streamlined Process to set up Unit Agreements

Industry contacts estimate the cost to prepare and submit a
proposal for a Federal exploratory unit agreement costs an average of
$20,000 per application. BLM estimates that it expends about 40 hours
to process each application at a cost of $1280. In FY 95, BLM received
52 applications to unitize with a projected cost to industry of
$1,040,000 and a projected cost to BLM of $42,000. The proposed rule
would reduce the amount of paperwork that industry has to submit to BLM
in order to unitize Federal mineral interests. Less paperwork would
reduce the administrative costs both for industry and for BLM. However,
the existing standardized terms would be replaced with the requirement
to negotiate terms with BLM. Initially, there will be a learning curve
for both BLM and operators, and the time to prepare and approve units
will be longer and more expensive. However, we believe that the added
expense of negotiations will be offset by the flexibility of the
process whereby operators would negotiate key development terms. We
also believe that over time, negotiations will be less lengthy as BLM
and operators become familiar with the process.
The proposed rule stipulates that production allocations for
enhanced recovery units or exploratory units with existing production
will be determined at the time the agreement is made, rather than after
substantial drilling is completed. While the allocations may not be as
precise as under the current regulation, the predictability will enable
the operators to make better economic decisions regarding the
development of the unit. Some other benefits of the new process are:
It will expedite paying well determinations since they
will no longer be based on economics;
The agreement will establish the size of initial
participating areas and additions to existing participating areas. This
would benefit operators by establishing participating area size without
elaborate subsurface projections; and
Paying well determinations would be replaced with
productivity criteria. This would allow the operator to negotiate
criteria that are not tied strictly to well economics. The use of well
productivity criteria would allow the costs for that well to be
considered as part of unit costs and not be required to be covered by
production from that well alone.

Increased Bonding/Bond Reduction for Low Liability Operations

The proposed rule increases minimum individual lease bonds from
$10,000 to $20,000 and statewide bonds from $25,000 to $75,000.
Nationwide bonds are unchanged. The rule also clarifies BLM's authority
to increase bonds on existing wells and leases for a variety of
reasons, most having to do with unsatisfied or insufficiently bonded
liabilities. BLM already has the authority to increase lease bond
requirements in specific situations, but the amount has been left to
BLM to determine on a case-by-case basis. With the proposed rule, both
BLM and the operator can better anticipate what the additional cost
will be. For instance, increasing the bond is one of the options for
inactive wells (wells with no activity for 12 consecutive months).
Within 30 days of a well becoming inactive, the operator must do one of
the following:
Submit additional bonding of $2.00 per foot of total or
plugged-back total depth for each well;
Pay a non-refundable annual fee of $100 per inactive well
(this is only an option for the first six years a well is inactive);
Put the well in production or service;
Submit plans to conduct well work to restore production or
service; or
Submit plans to plug and abandon the well and perform
reclamation.
Increased bonds or fees are necessary due to the significant
unfunded liability that has fallen and continues to fall on the public
in general and BLM and other land management agencies in particular.
This liability is in the form of orphan oil and gas wells. Unplugged or
inadequately plugged wells and unreclaimed sites on Federal lands with
no responsible person or company found are left to the government to
clean

[[Page 66869]]

up. Even if a bond is available for the well, it is frequently
insufficient to cover the costs of plugging and reclamation.
Furthermore, one bond may represent many wells. The Bureau Performance
Review of the Oil and Gas Program included a review of bonding and
unfunded liability. The March 1995 report concluded that the public was
assuming too much of the risk from orphan wells. The existing
regulations provided the authority to increase bonds, but did not
provide guidelines on how much to increase the bond requirements.
Furthermore, the operator may appeal the amount of the bond increase,
adding to the costs for both BLM and the operator. The proposed rule
reduces the number of situations where the operator may appeal bond
increases. The bond increases in the proposed rule are based on the
recommendations from that review. The goal is not to make the bonds
high enough to cover all potential costs. While most wells can be
plugged and abandoned for between $10,000 and $20,000, an individual
lease bond may cover many wells. However, we expect that the higher
bonding will provide an incentive to industry to be more diligent in
reclamation. The increase in the minimum State and lease bond
requirements is less than the rate of inflation since the current
amounts were set in 1960. However, the increase may still be an
unjustified burden for small operators with only a few shallow wells.
The cost of plugging these wells and reclaiming the land may be less
than the $20,000 lease minimum, or even less than the current $10,000
lease minimum. The option for the operator to apply for a reduction in
the bonding requirement helps to reduce the impact of increasing the
bonding requirement on small operators and may even reduce the
requirement on some leases below the current $10,000 requirement. This
will allow for the bonding requirement increase to only be applied to
leases on which the potential liabilities correspond to the higher bond
amounts. The following discusses bonding costs in more detail.
What does a bond cost industry? Bond premiums may be as low as 1
percent per year, but often require some collateral such as
certificates of deposit (CD's) or other security in addition to the
fee. Large, low risk companies may just pay a low premium with no
additional security. Requirements will be higher for higher risk
companies. Operators may post CD's or other security with the
government in lieu of a surety bond (approximately half of all
operators on Federal lands use this option). While this costs more than
the premium on a surety bond, it is less expensive than pledging
security and paying a bond premium. Essentially, the cost of pledging
this security is the cost of capital (as the resources could be used
for other investment) minus the interest the operator receives on the
security. Using the assumption that this cost difference is 3 percent
and that it is applied to all existing bonds, the increased cost to
industry is shown in the following table. For this estimate we assume
that about 500 leases would qualify for a reduced bond and that the
average required bond for them would be the current $10,000
requirement.

----------------------------------------------------------------------------------------------------------------
Number of Increased cost
Type of bonds Bonds\1\ Increased amt. \2\
----------------------------------------------------------------------------------------------------------------
3171 $951,300
Individual...................................................... -500 -150,000
---------------- ---------------
$10,000
=2671 =801,300
Statewide....................................................... 2348 50,000 3,516,000
Nationwide...................................................... 807 0 0
Collective...................................................... 139 0 0
-----------------------------------------------
Total....................................................... 6465 .............. $4,317,300
----------------------------------------------------------------------------------------------------------------
\1\ From Bonding Review Report, 3/95, based on AIRS data, 10/94.
\2\ Number of bonds x increased bond amt. x 0.03.

This averages to about $43 for each well on Federal lands. A
stripper oil well averaging 10 barrels of oil per day and selling oil
at $15 per barrel would gross $54,750 per year and pay royalty of
$6,850. The marginal cost of production may be about $2 per barrel, or
about $7,300 per year. An additional $43 per year is not significant.
Thus, the increased bond requirements do not impose a significant new
cost on industry.
This rule defines specific costs for inactive wells, which
represent the greatest risk for becoming orphan wells, by increasing
the bonding by $2.00 per foot of depth for inactive wells or charging
$100 annually per inactive well (only an option for the first six
years). While this fee is equivalent to the 1 percent fee on the
$10,000 additional bonding required for a 5000-foot well, the operator
would not have to pledge additional collateral that may be required to
obtain the bond. By basing the increased bond requirement on the depth,
it better reflects the plugging costs for the well. This targeted
increased bonding may be more significant than the across the board
increase. For example, the Bonding Review estimated there were about
300 known orphan wells, 6,500 temporarily abandoned wells, and 11,000
shut-in wells on Federal lands. Assuming that 3,000 wells are
classified as inactive wells and their average depth is 5,000 feet, the
increased bonding would total $900,000 (3,000 wells x 5,000' x $2
x 3%) or about $300 per inactive well per year. The change allows
operators to better plan their operations, as it may affect the
decision regarding plugging and abandoning a well versus shutting it in
or temporary abandonment. Under this proposal, operators can hold
inactive wells for six years with a $100 annual fee before having to
obtain the higher bonding or taking one of the other required actions.
This amount was calculated to be roughly equivalent to the cost to
operators of the proposed increase in the bond due to having an
inactive well.
The increased bonding represents a relatively small cost of doing
business. It will be incorporated as a cost that may have some impact
on decision making in field operations. The increased bond requirements
for inactive wells may force some marginal wells that would be inactive
under the current requirements to be plugged and abandoned more rapidly
under the proposed requirements if the bond increases are higher than
what would be charged under the existing regulations. However the
opposite could be true, and the advantage of the proposed rule is the

[[Page 66870]]

certainty of the costs. While these wells could potentially produce and
provide additional revenue, the amount is insignificant and less than
the potential cost to the government if they become orphan wells.
Having the bonding reduction option greatly mitigates the impacts
of the bonding increases on small operators.
The net impact to industry is negligible. The minor increased cost
is more than offset by the gains to the public by reducing the risk of
creating new orphan wells. The costs to government are also reduced by
having better compliance by industry. This also represents a net gain
for the environment. Overall, increased bonding represents a net
positive.

Geophysical Exploration Fair Market Value Charges

The proposed rule provides for assessing a FMV charge for the use
of public lands for geophysical exploration. This would only be applied
to the portion of exploration on federally-owned surface estate that is
not already leased for oil and gas. The amount of this FMV assessment
will be determined in a separate action. Thus, the estimated economic
impact will be published with that proposed action.
Paperwork Reduction Act
BLM has submitted an information collection clearance package to
OMB for its approval of the information requirements contained in these
proposed regulations under the requirements of the Paperwork Reduction
Act, 44 U.S.C. 3501 et seq.
The information collections listed below for proposed changes in
the regulations have not been approved by OMB.
Proposed changes in the regulations would increase the information
burden by an estimated 9,441.25 hours. For new information collection,
all of which are nonform items, BLM expects the public reporting burden
to be as follows:
Information Collections in This Rule That Have Not Yet Been Approved
BLM does not yet have information collection approvals from OMB for
the following items. However, these are not new information
collections, but are new requests for information collections for OMB
information collection approval. Existing regulations require these
information collections.
Leasing
Section 3121.12--The respondent must advise BLM by letter of its
nominations for competitive leasing in the BLM State Office with
jurisdiction over the lands involved and provide a legal description of
the nominated lands.
We estimate it will be 15 minutes to prepare a nomination list of
tracts. The information is necessary to list tracts nominated by
operators or the general public for a lease sale. We estimate that
there will be 1,400 filings a year, for a total information collection
burden of 350 hours.
Section 3124.32--For an application for lease consolidation, the
respondent must identify the affected leases and justify why
consolidation promotes conservation of resources that cannot be
achieved through unitization or communitization.
BLM requires this information to ensure compliance with the Mineral
Leasing Act, to ensure conservation of resources, and to protect the
public interest. Leases are combined only when unitization or
communitization are not possible or when unitization or communitization
will not promote conservation of resources.
We estimate it will take approximately two hours to comply with the
required information. The estimate includes time for gathering and
compiling data that shows unit requirements, such as drilling and
production, are met, and providing certification. We estimate 10
responses, for a total of 20 hours.
Section 3125.11--A lessee wishing to exchange its existing 20-year
oil and gas lease for a new lease for the same lands must file an
application for lease exchange in the BLM State Office with
jurisdiction over the lands.
An exchange converts the renewal lease for the benefit of the
lessee and the administrative convenience of BLM.
We estimate it will take approximately 15 minutes to comply with
the application information. The estimate includes time for providing
lease term information about the original lease. We estimate 25
responses, for a total of 6\1/4\ hours.
Operations
Sections 3103.10(aa) and 3153.37--An operator must provide to BLM a
lease automatic custody transfer (LACT) meter proving report.
The information is necessary for BLM to identify the LACT that was
proved and where and when it was proved. The proving report contains
the LACT unit identification number, its location and information
regarding the results of the meter proving, including any adjustments
and new meter factors.
We estimate it will take approximately 10 minutes to comply with
the notices and report information required. The estimate includes time
for compiling the various data requirements. We estimate 200 notices
and reports per year, for a total of 33\1/3\ hours.
Sections 3103.10(bb) and 3154.33--An operator is required to
provide to BLM gas charts/meter proving reports.
The gas chart measures gas over a specified period of time that a
gas well produces. These are original charts that must be submitted to
BLM to allow BLM to perform independent volume calculations or
integrations. Charts identify the well, lease, operator, and other
information regarding the measurement system. The gas meter proving
reports are the results of calibrating the recording component of the
gas measurement system. These reports identify the operator, facility
number, well number, specifics of the measurement system, and the
results of calibrating the meter, including any adjustments that were
made.
We estimate it will take approximately 15 minutes to comply with
the information requirement, and one thousand reports a year, for a
total of 250 hours.
Section 3103.10(dd)--The operator is required to provide to BLM
notice of meter proving or calibration and must provide information
regarding what meters will be calibrated, their lease and well numbers,
and when the calibrations will occur.
These records and notifications are necessary to ensure proper
measurement. BLM uses the information to conduct audits to determine
correct volumes and to determine volume corrections when the
calibration of meters indicate inaccurate measurement. The required
tables, charts, and meter proving reports are generally information
that a prudent operator would already require for its records in order
to verify correct volumes, accurate measurement, etc. Typically, an
operator needs only to reproduce such information. We estimate 5,000
such notifications per year, at five minutes each, for a total of
416\2/3\ hours.
Reports, Submissions and Notifications
Section 3103--The operator is required to provide oral notification
that they are commencing the activities listed below. Oral
notifications generally only require the operator to identify the lease
and well and the anticipated starting or completion time of the
operation.
The following sections reference activities that require the
operator to orally notify BLM:

[[Page 66871]]

Section 3103.10(I)--Construction start-up.
Section 3103.10(j)--Spud notice.
Section 3103.10(m)--Running surface casing and BOP test.
Section 3103.10(o)--Reserve pit closure.
Section 3103.10(x)--Report of theft or production mishandling.
Section 3103.10(z)--Notice of LACT meter proving.
Section 3103.10(ee)--Leak detection system.
Section 3103.10(ff)--Produced water pit completion.
Section 3103.10(gg)--Report of spill or accident.
Section 3103.10(ii)--Well abandonment.
Sections 3103.10(ll) and 3145.43--Concentrations of 100 ppm or more
of H2S.
The notifications are necessary to ensure proper monitoring and
inspection by BLM of lease operations.
We estimate approximately 6,000 notifications per year, at five
minutes for each notification, for a total of 500 hours.

Subpart 3136--Drainage Agreements

Section 3136.10--Respondents are required to submit any drainage
agreements. The agreement includes land identification, lease
ownerships, mineral ownerships, and royalty allocation.
This information is necessary to ensure that Federal royalties are
collected and that Federal minerals are protected from drainage by non-
Federal wells.
BLM estimates there will be five agreements per year and that each
one will take 10 hours to prepare and submit. The total information
collection will be 50 hours.

Subpart 3137--Unit Agreements

Section 3137.13--The respondent must submit an application for
unitization and include the unit agreement, a map of the unit area
showing the committed leases and other tracts, a list of committed
leases with legal description and other tracts, record title, working
interest, acreage, an allocation schedule, if appropriate,
certification of invitation to join the unit, economic, geologic,
engineering and other data, depending on the type of unit.
We estimate it will take approximately 40 hours to comply with the
information requirement for the application for unitization. The
estimate includes time for gathering, preparing, completing, and
maintaining the specified information, but not the time required to
obtain, analyze, and interpret the information normally expended as
part of an exploration program without unitization. We estimate that
there will be 60 unit applications made within a given year, for a
total increase in the information collection burden of 2,400 hours.
Section 3137.64--To establish a participating area or to expand an
existing participating area, the respondent must submit certification
to BLM that unitized production has been established, and as
appropriate, a map showing the participating area and total acreage,
and a schedule showing the production allocation for each tract
participating in production.
We estimate it will take approximately 12 hours to compile and
submit the request for establishing or expanding a participating area.
We estimate that there will be an average of 45 participating area
applications a year for a total increase in the information collection
burden of 540 hours.

Subpart 3145--Drilling

Section 3145.18--This section would require operators to apply for
a Notice of Staking (NOS), which includes the information sufficient to
identify lands that may be potentially affected by a planned oil or gas
well. The information includes legal description, operator name, well
number, surface ownership, and lease number. A map must also be
included that identifies topographic features. The map would assist BLM
in identifying potential problems at the proposed well location.
This information collection provides operators an opportunity to
work with BLM to find the best suitable drilling site, develop site
specific mitigation, and to avoid unnecessary expense when preparing
drilling plans.
Although this information burden is highly variable, we estimate
there will be 1,500 NOS applications a year that take 15 minutes each,
for a total burden of 375 hours.
Section 3145.51(a)(3)--Reclamation of contaminated lands requires
operators to provide to BLM information regarding method of
remediation, location of facility or onsite remediation, soil test
results, volumes of contaminated soils, and rehabilitation schedule,
and request BLM approval.
This information is necessary to ensure that contaminated soils are
properly remediated, to minimize environmental impacts and protect the
public.
We estimate this information will take approximately five hours to
compile and that there will be 100 occurrences per year. The total
information burden would be 500 hours.

Subpart 3151--Production, Storage and Measurement

Section 3151.10(c)--Applications for off-lease measurement must
include justification for the off-lease measurement and information on
the type and location of the off-lease measurement facility, all wells
that will produce into that facility, plans for preventing losses in
transporting production from the lease to the facility, and
certification that any losses will be the responsibility of the
operator.
This information is necessary for BLM to ensure that proper
measurement occurs, that Federal interests are adequately protected,
that Federal rights-of-ways are obtained, and to properly identify and
locate the facilities for production accountability inspections.
We estimate 300 applications per year at one hour each, for a total
increase in the information burden of 300 hours.
Section 3151.10(d)--In a request for approval of commingling, the
operator must identify the affected leases, wells, producing intervals,
proposed production allocations, and the quantity and quality of oil or
gases that are to be combined.
This information is necessary for BLM to determine if the proposal
adversely affects production accountability.
We estimate each request takes 30 minutes and that there will be
500 commingling requests per year, for a total of 250 hours.

Subpart 3164--Civil Penalties

Section 3164.15--To request a waiver or reduction of civil
penalties, the operator must submit, in writing, to the appropriate BLM
State office, justification for the waiver or reduction. The
information is necessary so that BLM may determine whether a waiver or
reduction of the civil penalty should be granted.
We estimate that the preparation of each request takes 30 minutes
and that there would be 100 requests per year, for a total increase in
the information collection burden of 50 hours.
New Information Collections
The following are new information collections that require OMB
approval. These information collections are not in existing
regulations.

Subpart 3107--Lease, Surety and Personal Bonds

Section 3107.53--Respondents are required to provide to BLM
information

[[Page 66872]]

that justifies BLM decreasing their bond amount.
This information is to allow BLM to determine if the lease
obligations associated with a given lease are less than the bond
amount.
We estimate 100 responses per year that take 1 hour per response,
for a total of 100 hours.
Sections 3107.56 and 3145.23--The operator is required to submit
information regarding each inactive well under Federal jurisdiction.
The information includes operator identification, lease and well
number, location, and total and plugged-back well depths. Other
information that may be needed to exempt operators from the increased
bonding requirements includes plans for reworking and returning the
well to production; evidence that the well is capable of producing but
that it is awaiting pipeline connection, or it is uneconomic at this
time to connect to a pipeline; or that the well will be plugged and
abandoned. If additional bonding is needed, proof of additional bonding
will be necessary, such as riders and bond numbers.
This information is necessary to ensure that adequate bond coverage
exists.
We estimate 6,600 operators will provide information for 13,000
wells per year, at 30 minutes per respondent, for a total of 3,300
hours.
Send comments regarding this information collection, including
suggestions for reducing the burden, to: Office of Management and
Budget, Interior Desk Officer (1004-NEW), Office of Information and
Regulatory Affairs, Washington, D.C. 20503, and Information Collection
Clearance Officer, Bureau of Land Management, 1849 C St., N.W., Mail
Stop 401 LS, Washington, D.C. 20240.
We specifically request your comments on: (1) whether the proposed
collection of information is necessary for the proper performance of
the functions of the agency, including whether the information will
have practical utility, (2) the accuracy of BLM's estimate of the
burden of the proposed collection, including the validity of the
methodology and assumptions used, (3) ways to enhance the quality,
utility, and clarity of the information to be collected, and (4) ways
to minimize the burden of the collection of information on those who
are to respond, including the use of appropriate automated, electronic,
mechanical, or other technological collection techniques or other forms
of information technology. BLM will analyze any comments sent in
response to the notices and include them in preparing the final
rulemaking.

Approved Information Collections in This Rule

BLM currently has information collection approvals from OMB as
follows:
OMB 1004-0162
Form 3150-4, Application to Conduct Oil and Gas Geophysical
Exploration Operations, and Form 3150-5, Notice of Completion of Oil
and Gas Exploration Operations, are approved under OMB 1004-0162, Oil
and Gas Geophysical Exploration Operations. This information collection
expires August 31, 1999. BLM uses Form 3150-4 to determine who is
conducting specific geophysical operations on public lands and that
appropriate measures are taken to protect the environment under NEPA.
BLM uses Form 3150-5 to determine when oil and gas explorations
operations are complete and to determine that mitigating measures have
been performed to protect the environment as required under NEPA.
Collectively, the information serves to maintain an accurate account of
operations being conducted on public lands and who is to be held
accountable if there is damage to the lands.
OMB 1004-0034
Form 3000-3, Assignment of Record Title Interest in a Lease for Oil
and Gas and Geothermal Resources, and Form 3000-3a Transfer of
Operating Rights (Sublease), are approved under OMB 1004-0034, Oil and
Gas Lease Transfers by Assignment or Operating Rights (Sublease). The
collection expires September 30, 1998. BLM uses the two forms,
respectively, to transfer all or part of a record title interest, or
operating rights, or overriding royalty or similar interest in an oil
and gas or geothermal lease to another party under the terms of the
mineral leasing laws. They identify ownership of the interest being
transferred and the qualifications of the transferee to take interest.
OMB 1004-0074
Form 3000-2, Competitive Oil and Gas or Geothermal Resources Bid is
approved under OMB 1004-0074, Oil and Gas and Geothermal Resources
Leasing, which expires May 31, 2000. BLM uses the form to determine the
highest qualified bonus bid submitted for a competitive oil and gas or
geothermal resources lease on public domain and acquired lands. The
information collection expires May 31, 2000.
OMB 1004-0145
BLM requires various items of information to determine eligibility
of an applicant to lease, explore for, and produce oil and gas on
Federal lands. These are non-form information items and are grouped and
approved under OMB 1004-0145, Oil and Gas Exploration and Leasing. The
collection expires July 31, 1999. BLM needs this information to process
oil and gas leases, to ensure compliance with terms and conditions of
various statutes, and to determine whether an entity is qualified to
hold a lease. Information items that do not require a form are:
Option Acreage Chargeability. Requires a notice of option holdings
that is required under the Mineral Leasing Act of 1920 (30 U.S.C.
184(d)(2)). BLM uses this information to determine acreage
chargeability. The applicant must submit to BLM copies of notices of
options when we request it.
Excess Acreage. The application must include a petition with
justification requesting additional time to divest excess acreage.
Lease Holdings. Requires statements showing date, acreage, and the
State in which each oil and gas lease is located. BLM does not
routinely request this information. However, when BLM requests it, BLM
uses it to determine that the lessee is in compliance with the law with
respect to acreage limitations (30 U.S.C. 184(d)(2)).
Joinder Evidence Required. A statement is required as to whether or
not a prospective oil and gas lessee has joined in a unit agreement if
the lease is for lands within an approved unit.
Waiver, Suspension or Reduction of Rental, Royalty, or Minimum
Royalty. Application or petition for such benefit is required. The
information is required by law and BLM uses it to determine that
development cannot be promoted or that the lease cannot be successfully
operated if the rental or royalty were not waived, suspended or
reduced.
Communitization Agreements. Requires copy of agreement in order to
obtain permission to join in oil and gas development with other lands.
The information collection has been approved by OMB under 1004-0134.
BLM requires this information to confirm that the lease, or portion
thereof, cannot be independently developed.
Operating, Drilling or Development Contracts. Requires statement
showing interest held by the contractor and a copy of the contract.
Copies of contracts are required to obtain approval to permit operators
to enter into contracts with a number of lessees sufficient to justify
operations on a large scale.

[[Page 66873]]

Subsurface Storage of Oil and Gas. Requires application to obtain
BLM authorization to store oil and gas underground on Federal lands.
BLM requires the information to determine if the subsurface storage
avoids waste and promotes conservation of the natural resources.
Heirs and Devisees. In case of the death of an offeror of a tract
for a Federal lease, applicant, lessee or transferee, the regulations
require a statement that heirs and devisees are qualified to hold a
lease interest in accordance with the law.
Change of Name. Requires that a change of name of the lessee be
reported to the proper BLM office. The notice of name change must
include a list of serial numbers of the leases affected. This
information is necessary for acreage chargeability purposes.
Corporate Merger. Requires notification by lessee of corporate
merger along with a list of leases affected, which BLM uses to
determine acreage accountability.
Renewal Leases. Requires application for renewal, but no specific
form. This information requirement may be submitted on the multipurpose
lease form 3100-11, which has been designated ``certification only'' by
OMB.
Relinquishments. Requires written relinquishment by lessee of a
lease or subdivision thereof, but no specific form is required.
Petition for Reinstatement. Requires petitions of reinstatement
showing that failure to pay rental, or timely file required
instruments, was inadvertent, justifiable, or not due to the lack of
reasonable diligence on the part of the lessee. This information is
required by law and BLM uses it to determine whether the petitioner is
eligible for Class I, II, or III lease reinstatement.
Leasing Under Rights-of-Way. Requires application, but no specific
form, for lease of lands under certain types of rights-of-way. Form
3100-11 may be used. The information is required by 30 U.S.C. 301,
which authorizes the leasing of oil and gas deposits under railroads
and other certain types of rights-of-way, to the owner of the right-of-
way, or the entering of a compensatory royalty agreement.
Application for Oil and Gas Exploration Permit in Alaska. The
information is required for any person wishing to conduct oil and gas
geophysical exploration operations in Alaska as required by the Alaska
National Interest Lands Conservation Act, Section 1008. BLM requires
this information to determine if the applicant complies with the terms
and conditions of the law.
Collection and Submission of Data for an Exploration Permit. BLM
requires this information to determine what actions and operations are
intended by a exploration permittee in Alaska or on DOD lands, and that
the permittee complies with the terms and conditions of the exploration
permit.
Completion of Operations. Requires a completion report containing a
description of the work, dates exploration was conducted, maps showing
the exploration area, and a statement that the operator has complied
with all terms and conditions of the permit, or outlines the corrective
measures that the operator will take to rehabilitate the lands. BLM
needs the information to determine that the operations are complete in
order to release your bond.
OMB 1004-0134
Various data on oil and gas operations required to be submitted by
the operator or operating rights owner are approved under OMB 1004-
0134, Non-form Items. The collection expires November 30, 2000. The
information provides data so that proposed operations may be approved;
it enables BLM to monitor compliance; and it is used to grant approval
to begin or alter operations or to allow operations to continue. The
specific information items in this collection cover the following
activities:
Drilling Plan. The drilling plan provides technical data and
information about the proposed drilling, completing, and associated
surface access for a well. BLM needs this information to assure that
operations are technically feasible and are conducted in a manner that
protects water resources and other environmental values under NEPA, and
protects health and safety.
Well Markers. The marker identifies the surface location and
provides detailed well information. BLM requires this information to
locate wells drilled on Federal or Indian lands.
Directional Drilling. The operator must submit this information to
identify whether or not there is potential for adverse impacts on
adjoining leases. If drainage or lease boundary crossing is likely, the
operator is required to perform a directional survey to chart the
direction of the deviation and the bottom hole location. The operator
must submit information about the direction of the deviation and the
subsurface location of the hole.
Drilling Tests, Logs, and Surveys. Operators routinely perform
tests, logs, and surveys during the normal course of business so a copy
of the company record suffices. The data consists of lithologic and
quantitative logs to indicate type of mineral encountered; drill stem
tests to indicate type of hydrocarbon; and possible exposure to gases
such as hydrogen sulfide.
Plug and Abandon for Water Injection. Various leasing statutes
require the prevention of waste and various laws require the protection
of water resources and prevention of undue harm to the surface and
subsurface environment. The abandonment plan delineates measures to
protect water; measures to prevent escape of toxic gases (hydrogen
sulfide); proof of the complete extraction of the oil or gas; any
proposed secondary use of the well (water injection); possible requests
to waive the requirement for well markers; and mitigation of surface
disturbance. The provision for oral approval to remove a drill rig with
subsequent written confirmation allows faster action and a reduction in
the operator's rental expense.
Conversion to a Water Source Well. This information is required to
allow BLM to approve the use of a nonproducing well as a water source
well for either the operator or the operating rights owner.
Additional Gas Flaring. The regulations require the operator to
conduct operations in such a manner as to prevent avoidable loss of oil
and gas. The operator is liable for royalty payments for such losses.
If the operator requests additional gas flaring, BLM may require a gas
flaring evaluation report from the operator to justify any additional
gas flaring requests.
Report of Spills, Discharges, or Other Undesirable Events. The
operator must report to BLM all spills or leakages of oil, gas,
produced water, toxic liquids, waste materials, etc. The operator's
prompt notification enables BLM to protect public health and safety and
the environment.
Disposal of Produced Water. BLM monitors the process by which the
operator disposes of produced water. BLM needs the information to
ensure adequate protection of public health and safety and compliance
with environmental laws. The operator must describe the nature and
manner in which the produced water will be disposed. The data provides
the technical aspects of pit design to allow for sufficient water
containment, thereby preventing unnecessary releases of produced water.
Contingency Plan. When BLM requires it, the operator must submit a
contingency plan that describes procedures to be implemented to protect
life, property, and the environment.

[[Page 66874]]

BLM may require either a copy of the Spill Prevention Control and
Countermeasure Plan, which is submitted to the Environmental Protection
Agency under 40 CFR 112, or another acceptable contingency plan. Plans
are generally required for proposed operations in sensitive areas such
as hydrogen sulfide high risk areas of Michigan, parts of Florida,
Mississippi, and Wyoming, or when the nature of the proposal leads BLM
to a determination that public health and safety requires such prior
planning. The content of a contingency plan would depend on the nature
of the potential hazard and the proximity to potentially affected
population or resources.
Schematic/Facility Diagrams. The operator is responsible for
documenting how the lease is developed. Most documentation is routinely
prepared for company use and is therefore readily available. Within an
established time of completing or modifying a facility, the operator
submits schematic diagrams that depict facility functions and how oil
and gas flows through the operation.
Facility diagrams are filed within 60 days after new measurement
facilities are installed or existing facilities are modified or
following the inclusion of the facility into a federally supervised
unit or communitization agreement. The diagrams are needed to verify
and account for all oil and gas produced.
Approval and Reporting of Oil in Pits. Having oil in pits is an
unusual operational circumstance, except in emergency situations, and
requires BLM's prior approval. Although uncommon, such production
operation is reasonable under certain circumstances, and approval is on
a case-by-case basis after proper justification.
Preparation of Run Tickets. The operator is required to furnish run
ticket information to BLM and the Minerals Management Service, when
requested, to account for the volume of production, and for royalty
purposes.
Records on Seals. The operator must maintain a record of seal
numbers used and document on which valves or connections they were used
as well as when they were installed and removed. The seal records are
needed for detection of possible theft of oil as well as the proper
isolation of a tank prior to and following a sale.
Application for Suspension. In its applications for suspension of
operations and/or production the operator must include a full statement
of the circumstances that render the relief necessary. Leases and the
laws under which they are issued require operations and production and
provide authority to suspend this requirement.
Site Security. Site security plans are required to be filed for all
facilities. At the operator's option, a single plan may be completed to
include all of that operator's leases within a single BLM District. Any
security elements in excess of the minimum requirements that the
operator wishes to implement, but wants to be held confidential, should
not be filed with the BLM but must be available for inspection by BLM
personnel on request. The notification can be modified from time to
time as additional facilities are brought under the purview of any
specific plan.
OMB 1004-0135
Form 3160-5, Sundry Notices and Reports on Wells, is approved under
OMB 1004-0135. The collection expires November 30, 2000. The
information an operator provides on the Sundry Notices form may be a
notice of intent, a subsequent report, or a final abandonment notice
and pertains to modifying operations conducted under the terms and
provisions of a lease for Federal or restricted Indian lands. The data
enables BLM oversight and approval prior to any modifications to
existing wells.
OMB 1004-0136
Form 3160-3 Application for Permit to Drill or Reenter, is approved
under OMB 1004-0136, Application for Permit to Drill, which expires
November 30, 2000. The operator is required to prepare certain items
such as drilling plans, diagrams, maps, and contingency and other
plans, which are generally submitted with Form 3160-3. The information
provides documentation that drilling and associated activities, when
and if authorized, are technically and environmentally feasible and
ensure proper conservation of resources. The information also provides
a basis for evaluating a proposed well's feasibility and, in turn,
determining whether the application should be disapproved or approved
and, if approved, whether any special conditions of approval should be
made part of the permit.
OMB 1004-0137
Form 3160-4, Well Completion or Recompletion Report and Log is
approved under OMB 1004-0137, which expires November 30, 2000. BLM uses
the information required on Form 3160-4 for technical evaluation of
operations performed on a well. The form documents that the operator
carried out operations in accordance with the terms and provisions of
the lease and in a technically and environmentally safe manner. Failure
to collect and submit the requested information would mean that BLM
would lack the necessary information to monitor compliance with
authorized well activity and operations that were performed on wells.

Authors

The principal authors of this rule are Tim Abing (Milwaukee
District Office), Jim Albano (Montana State Office), Lonny Bagley
(Montana State Office), Shirlean Beshir (Eastern States Office), Peter
Ditton (Great Falls Resource Area Office), Karen Johnson (Montana State
Office), Pam Lewis, (Wyoming State Office), Robert Lopez (Utah State
Office), Patty Ramstetter (Utah State Office), Sherri Thompson
(Colorado State Office), Rick Wymer (New Mexico State Office), John
Duletsky of BLM's Fluid Minerals Group (Washington Office) and Ian
Senio of BLM's Regulatory Affairs Group (Washington Office).

List of Subjects

43 CFR Part 3100

Administrative practice and procedures, Classified information,
Freedom of Information Act, Oil and gas exploration, Public lands-
mineral resources, Reporting and recordkeeping requirements, Surety
bonds.

43 CFR Part 3110

Alaska, Oil and gas exploration, Public lands-mineral resources,
Reporting and recordkeeping requirements, Surety bonds.

43 CFR Part 3120

Government contracts, Oil and gas exploration, Public lands-mineral
resources, Reporting and recordkeeping requirements, Surety bonds.

43 CFR Part 3130

Government contracts, Oil and gas exploration, Public lands-mineral
resources, Reporting and recordkeeping requirements.

43 CFR Part 3140

Government contracts, Mineral royalties, Oil and gas exploration,
Public lands-mineral resources, Reporting and recordkeeping
requirements.

43 CFR Part 3150

Government contracts, Indians-lands, Mineral royalties, Oil and gas
exploration, Public lands-mineral resources, Reporting and
recordkeeping requirements.

[[Page 66875]]

43 CFR Part 3160

Government contracts, Indians-lands, Mineral royalties, Oil and gas
exploration, Penalties, Public lands-mineral resources, Reporting and
recordkeeping requirements.

43 CFR Part 3170

Government contracts, Hydrocarbons, Mineral royalties, Oil and gas
exploration, Public lands-mineral resources, Reporting and
recordkeeping requirements.

43 CFR Part 3180

Alaska, Government contracts, Mineral royalties, Oil and gas
exploration, Oil and gas reserves, Public lands-mineral resources,
Reporting and recordkeeping requirements, Surety bonds.

Accordingly, for the reasons stated in the preamble, amend Title
43, Subtitle B, Chapter II, Subchapter C, Parts 3100, 3110, 3120, 3130,
3140, 3150, 3160, and 3180 as follows:

Dated: July 23, 1998.
Bob Armstrong,
Assistant Secretary, Land and Minerals Management.

1. Revise part 3100--Oil and Gas Leasing to read as follows:

PART 3100--ONSHORE OIL AND GAS LEASING AND OPERATIONS: GENERAL

Subpart 3101--General Information

General

Sec.
3101.5 What terms do I need to know to understand BLM's oil and gas
regulations?
3101.8 Reference material.
3101.10 What do the regulations in parts 3100 through 3190 cover?
3101.11 Who must comply with the lease terms, regulations, orders,
and Notices to Lessees (NTL's) BLM issues?
3101.12 As a record title owner, what are my obligations?
3101.13 As an operating rights owner, what are my rights and
obligations?
3101.14 Does BLM warrant title to the oil and gas deposits when it
issues a lease or approves subsequent lease actions or lease
operations?
3101.15 Must I give BLM information and documentation about my
lease?
3101.16 What requirements must I follow in addition to the
regulations in parts 3100 through 3190 of these regulations?
3101.17 May BLM establish development and production requirements
for my lease?
3101.18 Will I be responsible for compensating the United States or
Indian lessor if my lease is being drained of oil and gas by wells
on adjacent tracts?
3101.19 May I obtain relief from the requirements of these
regulations or other requirements BLM developed?
3101.20 When will BLM consider a document filed?
3101.21 Are there other requirements that affect oil and gas
operations on Federal or Indian lands?
3101.22 May I appeal BLM's decisions under parts 3100 through 3190?

Subpart 3102--Recordkeeping

Recordkeeping

3102.10 What records must I keep?
3102.11 How long must I keep records?

Subpart 3103--Reports, Submissions, and Notifications

Reports, Submissions, and Notifications

3103.10 What reports and notifications must I submit to BLM?
3103.11 If I am the record title or operating rights interest
owner, what must be filed with BLM to authorize someone else to
conduct operations on my lease?

Subpart 3104--Environment and Safety

Environment and Safety

3104.10 How may I use the surface and subsurface of my lease to
develop oil and gas?
3104.11 May BLM take measures to minimize adverse impacts to
resource values, land uses or users not addressed in the lease
stipulations and not required by statutes or regulations?
3104.12 What measures may BLM take that are always consistent with
my lease rights?
3104.13 May anyone other than BLM impose lease stipulations?
3104.14 What must I do to protect the environment and ensure safety
when I conduct operations to develop Federal and Indian lands, or
geophysical operations on Federal lands?

Subpart 3105--Lessee Qualifications

Lessee Qualifications

3105.10 Who may hold a lease?
3105.11 If I am not a United States citizen, may I acquire or hold
an interest in a lease?
3105.12 If I am not qualified to hold a lease, may I hold one
anyway if I acquire it by descent, will, judgement or decree?
3105.13 Under what circumstances may minors acquire or hold
interest in a Federal oil and gas lease?
3105.14 Under what conditions will I be prohibited from acquiring a
lease or interest in a lease?
3105.15 What must I file with BLM to establish that I meet the
qualifications to hold a lease?
3105.16 May BLM require me to submit additional information to
determine if I meet the qualification requirements to acquire or
hold an interest in a lease?

Acreage Limitation

3105.20 What is the acreage limitation for holding, owning or
controlling oil and gas lease interests on public domain lands?
3105.21 What is the boundary between the two leasing districts in
Alaska?
3105.22 What is the acreage limitation for holding, owning or
controlling oil and gas lease interests on acquired lands?
3105.23 What is an option agreement?
3105.24 Must I file my option agreement with BLM?
3105.25 What effect do options have on lease acreage holding
limitations?
3105.26 How will BLM charge acreage holdings on lands where the
United States owns a fractional interest in the mineral resource?
3105.27 What lease interests are not chargeable against acreage
limitations?
3105.28 What if I exceed the acreage limitation?
3105.29 How does BLM compute chargeable acreage?
3105.30 May BLM require me to provide information with respect to
my acreage holdings?

Subpart 3106--Fees, Rentals and Royalties

Fees and Rentals

3106.10 What form of payment will BLM accept?
3106.11 Who should I pay?
3106.12 Where should I submit my payments?
3106.13 What are the rental rates for Federal leases?
3106.14 How does BLM calculate the rental due on my lease?
3106.15 If BLM assessed my nonproducing lease compensatory royalty,
must I also pay rental?
3106.16 What if I do not submit enough rental with my lease offer?
3106.17 When must I pay the balance of a rental deficiency on my
lease offer?
3106.18 What if I do not pay the balance of the rental due within
the time allowed?
3106.19 What if I base my deficient rental payment on an incorrect
acreage advertised in the Notice of Competitive Lease Sale?
3106.20 If the United States owns less than a 100 percent of the
mineral rights in my lease, must I pay rental on the gross acreage
or on the net acreage?
3106.21 When should I pay the second and succeeding rental payments
after BLM issues my lease?
3106.22 Must I pay a full year's rental if less than a full year is
left in my lease term?
3106.23 What if MMS receives my rental payment after the date it is
due?
3106.24 What if the MMS office is closed on the date that my rental
payment is due?
3106.25 What if I incorrectly mail my second or succeeding rental
payment to BLM instead of MMS?
3106.26 What will BLM do if I mail a payment due to BLM to the
wrong BLM office?

[[Page 66876]]

Royalties

3106.30 What royalty must I pay after I establish production?
3106.31 What is minimum royalty?
3106.32 When must I pay the minimum royalty due on my lease?
3106.33 What minimum royalty must I pay on Federal leases?
3106.34 How does BLM determine royalty and minimum royalty if the
United States owns less than a 100 percent mineral interest?
3106.35 How do I pay royalty and rental if my lease is committed to
a unit agreement?

Waiver/Suspension/Reduction of Rental/Royalty/Minimum Royalty

3106.40 Will BLM waive, suspend, or reduce the rental, royalty, or
minimum royalty if I cannot successfully operate my lease?

Royalty on Oil: Sliding-Scale and Step-Scale Leases

3106.50 How do I determine my royalty rate on oil I produce from a
lease with a sliding-scale or step-scale royalty rate?
3106.51 How do I calculate average daily oil production per well
for my sliding-scale or step-scale lease?
3106.52 What wells do I include in the calculation of average daily
oil production in determining the royalty rate?
3106.53 What is a well-day?
3106.54 What royalty rate must I pay on oil I carry in inventory
when I sell it?

Stripper Oil Property Royalty Reduction

3106.60 What is a stripper oil property?
3106.61 What is an eligible well?
3106.62 What is the qualifying period?
3106.63 What is considered oil for determining whether or not I
have a stripper oil property?
3106.64 How do I calculate the average daily production rate for my
property?
3106.65 What will be my royalty rate if my property qualifies as a
stripper oil property?
3106.66 How do I apply for a stripper royalty rate?
3106.67 When may I start using the stripper royalty rate for my
lease and how long will it be in effect?
3106.68 Does the stripper royalty rate apply to condensate, gas or
gas plant products?
3106.69 How do I determine my royalty rate if my production varies?
3106.70 How do I apply for a lower royalty rate?
3106.71 What happens to my royalty rate if I commit my lease to a
Federal agreement after I qualify for a reduced royalty on a lease
basis?
3106.72 What if I make an error when I calculate the stripper
royalty rate for my lease?
3106.73 What happens if I manipulate production to get a stripper
royalty rate?
3106.74 How long will the stripper oil property program be in
effect?

Heavy Oil Property Royalty Reduction

3106.80 What is a heavy oil property?
3106.81 What wells can I include when I calculate a weighted
average gravity?
3106.82 How do I calculate a weighted average gravity for a
property?
3106.83 What will be my royalty rate if my property qualifies as a
heavy oil property?
3106.84 How do I apply to make a heavy oil reduced royalty rate
effective on my Federal lease?
3106.85 When will the initial heavy oil reduced royalty rate be in
effect on my Federal lease?
3106.86 How long will the initial heavy oil reduced royalty rate be
in effect on my Federal lease?
3106.87 How do I determine my royalty rate after the initial
reduced royalty rate period expires?
3106.88 When will subsequent royalty rate reductions become
effective on my Federal lease?
3106.89 What provisions apply when I begin paying royalty at a
reduced rate?
3106.90 What happens if I make a mistake when I calculate the
reduced heavy oil royalty rate for my lease?
3106.91 What happens if I manipulate production from my heavy oil
property in order to get a reduced royalty rate?
3106.92 How long will the heavy oil property royalty reduction
program be in effect?

Subpart 3107--Lease, Surety and Personal Bonds

General Information

3107.10 Who may file an oil and gas lease bond?
3107.11 Who must a bond cover?
3107.12 When must I file a bond?
3107.13 What must my bond cover?
3107.14 What are the dollar amounts for bonds?
3107.15 What kinds of bonds will BLM accept?
3107.16 Will BLM accept cash for personal bonds?
3107.17 Is there a special bond form I must use?
3107.18 Is there any other documentation that I must file with a
surety bond?
3107.19 Where must I file my bond?
3107.20 How do I modify the terms and conditions of my bond?

Certificates of Deposit, Letters of Credit and Negotiable Treasury
Securities

3107.30 What may I use to back my personal bond?
3107.31 Are there special terms that must be included in a
certificate of deposit to use it to back my bond?
3107.32 Are there special terms that must be included in an
irrevocable letter of credit to use it to back my bond?
3107.33 What special requirements are there for negotiable treasury
securities?

Bonding and Lease Transfers or Operations

3107.40 What are BLM's bonding requirements when a lease interest
is transferred to another party?

Bond Adjustments

3107.50 May BLM adjust my bond amount?
3107.51 What factors will BLM use to determine whether my bond will
be adjusted?
3107.52 When will BLM increase my bond amount?
3107.53 When will BLM decrease my bond amount?
3107.54 To what amount may BLM adjust my bond?
3107.55 What is an inactive well?
3107.56 What additional security must I provide for an inactive
well?

Bond Collection After You Default

3107.60 Under what circumstances will BLM demand performance or
payment under my bond?
3107.61 As the principal on the bond, may BLM require me to restore
the face amount of my bond or require me to replace my bond after
BLM makes demand against it?
3107.62 What if I do not restore the face amount or file a new bond
within 60 calendar days after BLM notifies me?

Bond Cancellation

3107.70 After I fulfill all of the lease terms and conditions, will
BLM cancel my bond?
3107.71 Will BLM cancel my bond if I transferred all of my lease
interests or operations to another bonded party?
3107.72 When will BLM release the collateral backing my personal
bond?

Subpart 3108--Geophysical Exploration Bond Requirements

Geophysical Exploration Bonds

3108.10 Must I file a bond before starting an exploration project?
3108.11 What are the dollar amounts for geophysical bonds?
3108.12 Is there a special bond form I must use?
3108.13 May I use an oil and gas lease bond to cover exploration
operations?
3108.14 Will BLM increase my bond amount?
3108.15 When will BLM cancel my geophysical bond?
3108.16 What will happen if I do not complete additional
reclamation that BLM requests?
Authority: 16 U.S.C. 3150(b) and 668dd; 30 U.S.C. 189, 306 and
359; 43 U.S.C. 1201, 1732(b), 1733, 1734 and 1740; and Pub. L. 105-
85.

Subpart 3101--General Information

General

Sec. 3101.5 What terms do I need to know to understand BLM's oil and
gas regulations?

You need to know the following terms to understand parts 3100
through 3190--
Abandonment means operations you conduct to permanently plug a
well.
Access, with respect to production, means the ability to enter into
any----
(1) Tank or pipe system through a valve, valves, or combination of
valves,

[[Page 66877]]

or tankage that would permit the removal of oil or gas; or
(2) Component in a measuring system that could affect the quality
or quantity of the product being measured, without documentation.
Acquired lands means lands that the United States obtained by deed
through purchase or gift, or through condemnation proceedings,
including lands previously disposed of under the public land laws,
excluding Indian lands.
Act means the Mineral Leasing Act of 1920, as amended and
supplemented (30 U.S.C. 181 et seq.).
Aliquot part means a subdivision of a section under the rectangular
survey system arrived at by dividing a section into halves and quarters
(e.g., \1/2\ section, \1/4\ section, \1/4\ \1/4\ section) down to 40
acres, unless the acreage is a lot that may be more or less than 40
acres.
Allocated production means the proportionate share of production
that is credited to a Federal or Indian lease under an approved
agreement to which the lease is committed.
Association means any entity other than a corporation that is
permitted under State law to hold property in its name.
Available lands means those lands not excluded from leasing by a
statutory or regulatory prohibition and which the Secretary has
discretion to lease.
Avoidably lost means--
(1) Produced gas you vent or flare without BLM's prior, written
approval, unless otherwise allowed under parts 3100 through 3190; and
(2) Produced oil or gas lost when BLM determines that the loss
occurred as a result of your--
(i) Negligence;
(ii) Failure to take all reasonable measures to prevent or to
control the loss; or
(iii) Failure to comply fully with the applicable laws, lease
terms, and regulations, appropriate provisions of a previously approved
operating plan, or the provisions of prior written BLM orders.
Beneficial purposes means oil or gas that you produce but do not
sell from your lease, communitized tract, or unitized participating
area and that you use on or for the benefit of that same lease, same
communitized tract, or same unitized participating area for operating
or producing purposes. Examples include--
(1) Fuel you use to lift oil or gas;
(2) Fuel you use to heat oil or gas to place it in a marketable
condition;
(3) Fuel you use to compress gas to place it in a marketable
condition;
(4) Fuel you use to fire steam generators for the enhanced recovery
of oil; or
(5) Gas you use to actuate automatic valves at wells or facilities.
BIA means the Bureau of Indian Affairs of the Department of the
Interior.
Bioremediation means a treatment technology that uses a natural
process in which microorganisms, primarily bacteria and fungi,
chemically alter and break down organic molecules into other
substances, primarily carbon dioxide and water.
BLM means any employee of the Bureau of Land Management authorized
to perform the duties described in parts 3100 through 3190.
Blowout prevention equipment system (BOP) means the kill line,
choke manifold, closing unit, diverter, blowout preventer, and
auxiliary equipment required to operate the blowout preventer under
varying rig and well conditions.
Bona fide purchaser means a person who acquired an interest in a
Federal lease--
(1) In good faith;
(2) For valuable consideration; and
(3) Without notice of violation of Departmental regulations.
Bond means an agreement in writing in which a surety, or an obligor
for a personal bond, guarantees performance or compliance with the
lease terms.
Bond rider means any document that amends and becomes a part of an
existing bond.
Bonus bid means money a successful bidder pays to the United States
for a competitive oil and gas lease.
Bypass means any piping arrangement that allows oil or gas to
continue on the sales or allocation lines without passing through the
meter. Equipment that allows you to change the orifice plate without
bleeding the pressure off the gas meter run is not a bypass.
Cancellation of a lease means revocation or nullification of a
lease.
Casual use means activities that involve practices that do not
ordinarily lead to any appreciable disturbance or damage to lands,
resources, or improvements. Casual use includes activities that do not
involve using heavy equipment or explosives and that do not involve
vehicular movement except over established roads and trails. For
subparts 3110 through 3113, gravity or magnetic surveys, the placement
of recording equipment devices, and activities that do not involve
vehicle operations that would cause significant compaction or rutting
are generally considered casual use.
Commingle means combining production from different formations,
leases, communitized areas, or unit participating areas prior to sale.
Committed lease means a Federal, Indian, State or private lease
where all owners of record title and all working interest owners have
agreed in writing that they will abide by the terms and conditions of
an agreement.
Committed in part means a lease of which only a part of the lands
have been committed to an agreement.
Communitization agreement means an agreement to jointly operate a
lease with one or more other leased or unleased tracts to share the
benefits of production within a single spacing unit.
Completion operations means work you conduct to prepare your well
for production of oil or gas or service.
Condensate means those natural gas liquids recovered in production
equipment or pipelines that remain in a liquid state at atmospheric
pressure and temperature, and consist primarily of pentanes and heavier
hydrocarbons.
Condition of approval (COA) means a site-specific requirement BLM
attaches to approved Applications for Permits to Drill or Renter (APD)
or Sundry Notices and Reports (SN).
Director means the Director of the Bureau of Land Management.
Dispersion technique means a mathematical representation of the
physical and chemical transportation, dilution, and transformation of
H2S gas emitted into the atmosphere.
Drainage means the migration of hydrocarbons, inert gases or
associated resources from Federal or Indian lands caused by production
from wells on adjacent lands.
Eligible lands means those lands available for leasing when all
statutory requirements and reviews have been met.
Enhanced recovery unit means a unit created to produce oil and gas
from an area that is unrecoverable by primary recovery methods.
Escape rate means the maximum volume used as the escape rate in
determining the radius of exposure specified as follows:
(1) For a production facility, it is the maximum daily rate, or the
best estimate of that rate, of gas you produce through that facility;
(2) For gas wells, it is the current daily absolute open-flow rate
against atmospheric pressure;
(3) For oil wells, you must calculate it by multiplying the
producing gas-oil ratio by the maximum daily production rate; and
(4) For a well you are drilling in a developed area, you may
determine the escape rate by using offset wells completed in the
interval(s) in question.

[[Page 66878]]

Essential personnel means those on-site personnel directly
associated with the operation being conducted and necessary to maintain
control of the well.
Exception means a case-by-case waiver of a lease stipulation,
condition of approval, order, or lease term, that continues to apply to
all other sites within the leasehold, or area covered by the original
order, stipulation or condition of approval.
Exploratory unit means two or more leases operated under an
agreement for the purpose of exploring for or developing the oil and
gas resources of an area.
Federal lands means all lands and interests in lands owned by the
United States that are subject to the mineral leasing laws, including
mineral resources or mineral estates reserved to the United States in
the conveyance of a surface or nonmineral estate, excluding Indian
lands.
Federal lease means an onshore oil and gas lease issued under the
mineral leasing laws. It does not include Indian oil and gas leases.
Gas means any fluid, excluding helium, either combustible or
noncombustible, that is produced in a natural state from the earth and
which maintains a gaseous or rarefied state at ordinary temperatures
and pressure conditions. This includes any fluid within coal resources.
Gas well means a well for which the energy equivalent of the gas it
produces, including the entrained liquid hydrocarbons, exceeds the
energy equivalent of the oil it produces.
Geophysical exploration means activity relating to the search for
oil or gas that results in surface disturbance or disturbance to
resources or land uses. It includes, but is not limited to, geophysical
operations, construction of roads and trails and cross-country transit
of vehicles over the lands. It does not include core drilling for
subsurface geologic information or drilling for oil or gas. However,
this definition includes drilling operations necessary for placing
explosive charges.
H2S public protection plan means a written plan that
provides for the safety of the potentially affected public with regard
to H2S and sulphur dioxide (SO2).
Hazardous material: (1) Means any--
(i) Substance, pollutant, or contaminant listed as hazardous under
42 U.S.C. 9601;
(ii) Hazardous waste defined under 42 U.S.C. 9601;
(iii) Extremely hazardous substances defined under 40 CFR part 355;
or
(iv) Nuclear or byproduct material defined under 42 U.S.C. 2011;
(2) Does not include any petroleum products that are not otherwise
specifically listed or designated as a hazardous substance under 42
U.S.C. 9601 (14). The term does not include natural gas, natural gas
liquids, liquified natural gas, or synthetic gas useable for fuel (or
mixture of natural gas and synthetic gas).
Hazardous substance: (1) Means any--
(i) Substance designated under 33 U.S.C. 1321(b)(2)(A);
(ii) Element, compound, mixture, solution, or substance designated
under 42 U.S.C. 9602;
(iii) Hazardous waste having characteristics identified under or
listed under 42 U.S.C. 6921 (but not including any waste the regulation
of which under the Solid Waste Disposal Act, 42 U.S.C. 6901 et seq.,
has been suspended by Act of Congress);
(iv) Toxic pollutant listed under 33 U.S.C. 1317(a);
(v) Hazardous air pollutant listed under 42 U.S.C. 7412; or
(vi) Immediately hazardous chemical substance or mixture with
respect to which the Administrator of the Environmental Protection
Agency has taken action under 15 U.S.C. 2606;
(2) Does not include any petroleum products that are not otherwise
specifically listed or designated as a hazardous substance under this
definition. The term does not include natural gas, natural gas liquids,
liquified natural gas, or synthetic gas useable for fuel (or mixture of
natural gas and synthetic gas).
Held by production means a lease term is extended so long as oil or
gas is produced or capable of being produced in paying quantities from
the lease or agreement area to which the lease is committed.
Indian lands means any lands or possessory interest in lands owned
or held by any individual Indian or Alaska Native, Indian tribe, band,
nation, pueblo, community, rancheria, colony, or other group, the title
to which is held in trust by the United States or, as a matter of
Federal law, is subject to a restriction against alienation.
Indian lease means an oil and gas lease on Indian lands issued
under the regulations in Title 25 of the CFR and approved by the
Secretary, or an agreement entered into under the Indian Mineral
Development Act of 1982 (25 U.S.C. 2102) and the regulations in 25 CFR
part 225.
Injection well means a well used to dispose of produced water or
used for primary or enhanced recovery operations of oil or gas.
Interest means ownership in a lease or future interest lease of all
or a portion of the record title or operating rights.
Isolating means using one or any combination of cement, cast iron
bridge plugs, or retainers, to protect, separate, or segregate usable
water and mineral resources.
Lease means any contract, profit-share arrangement, joint venture
or other agreement issued or approved by the United States under a
mineral leasing law that authorizes exploration for, or extraction and
removal of oil and gas.
Lease site means any lands on which exploration for, or extraction
and removal of, oil or gas is authorized under the lease.
Lessee means any person holding record title or operating rights in
a lease issued or approved by the United States.
Marketable condition means lease products that are sufficiently
free from impurities and otherwise in a condition that they will be
accepted by a purchaser under a sales contract typical for the field or
area.
Maximum ultimate economic recovery means the recovery of oil and
gas from leased lands that a prudent operator could be expected to make
from that field or reservoir--
(1) Given existing knowledge of reservoir and other pertinent
facts; and
(2) Utilizing common industry practices for primary, secondary or
tertiary recovery operations.
Meter calibration means the operation by which you compare meter
readings with an accepted standard and when necessary, adjust the meter
so that its readings conform to that standard.
Meter uncertainty means the overall inaccuracy of a flow meter
caused by the inherent errors of the flow measurement equipment.
Minimum royalty means the minimum amount of annual royalty due
under the lease or under parts 3100 through 3190 after production is
established.
Mishandling means unmeasured or unaccounted-for removal of
production from a facility other than through theft.
Modification means a temporary or permanent change to the
provisions of a lease stipulation, condition of approval, order, or
lease term. It may include an exception from or alteration to a
stipulation, condition of approval, order, or lease term. The modified
stipulation, condition of approval, order, or lease term may apply to
all or part of the leasehold or area covered by the original order or
condition of approval.

[[Page 66879]]

National Forest System Lands (NFS) means all National Forest lands
reserved or withdrawn from the public domain of the United States, or
acquired through purchase, exchange, donation, or other means. It also
includes the National Grasslands and land utilization projects
administered by the U.S. Department of Agriculture, Forest Service,
under Title III of the Bankhead-Jones Tenant Act (7 U.S.C. 1010 et
seq.), and other lands, waters, or interests administered by the Forest
Service as part of the system under 16 U.S.C. 1609.
National Pollutant Discharge Elimination System (NPDES) means a
program administered by the Environmental Protection Agency, primacy
State, or Indian tribe, that requires permits for the discharge of
pollutants from any point source into navigable water of the United
States.
Off-lease measurement means conducting measurements at a tank
battery or measurement facility off the lease.
Oil means all nongaseous hydrocarbon substances other than those
substances leasable as coal, oil shale or gilsonite (including all
vein-type solid hydrocarbons).
Oil well means a well for which the energy equivalent of the oil it
produces exceeds the energy equivalent of the gas it produces,
including the entrained liquid hydrocarbons.
Operating rights (working interest) means any interest held in a
lease with the right to explore for, develop, and produce leased
substances.
Operating rights owner means a person who holds operating rights in
a lease issued by the United States. A lessee may also be an operating
rights owner in a lease if it did not transfer all of its operating
rights in a lease.
Operator means any person or entity (whether a lessee or operating
rights owner or an agent thereof) who has stated in writing to BLM that
it is responsible under the terms and conditions of the lease for the
operations conducted on the lease or portions of the lease. An operator
need not be an operating rights owner.
Participating area means the lands that contain at least one well
that meets the productivity criteria established in an exploratory unit
agreement. A participating area may be particular to separate producing
intervals or areas.
Paying well means--
(1) On a lease basis, a well with sufficient production capacity to
recover the cost of day-to-day operating expenses with a profit, no
matter how small; or
(2) On a unit basis, a well with sufficient production capacity to
return a reasonable profit over the cost of drilling, equipping,
completing and operating that well.
Person means any individual, firm, corporation, association,
partnership, trust, consortium, or joint venture.
Primary element means the equipment necessary to produce a
measurable and predictable pressure drop in the gas stream. For orifice
installations this includes the orifice plate, orifice plate flanges or
plate holder, the meter tube or ``run'', thermometer well and sampling
taps, and straightening vanes.
Produced water means water produced in conjunction with oil and gas
production.
Producing interval means the geologic strata from which you extract
hydrocarbons. It does not have to be a recognized United States
Geological Survey formation. BLM may consider multiple producing
intervals from a formation as one producing interval.
Production facility means any header, piping, treating, or
separating equipment, water disposal pit, processing plant, measurement
facility, or combination of those things and includes the approved
measurement point for any lease, communitization agreement, or
participating area.
Production phase means that period of time or mode of operating
during which crude oil is delivered directly to or through production
vessels to the storage facilities and includes all operations at the
facility other than those defined by the sales phase.
Prospectively valuable deposit of minerals means any deposit of
minerals, other than fluid hydrocarbons, BLM determines to have
characteristics of quantity and quality that make it technologically
feasible to develop and, therefore, that warrant its protection from
undue damage by oil and gas operations.
Public domain lands means lands, including mineral estates, that--
(1) Never left United States ownership;
(2) The United States obtained in exchange for public domain lands;
(3) Have reverted to the ownership of the United States through the
operation of the public land laws; or
(4) That Congress specifically identified as part of the public
domain.
Public lands means lands or minerals that the United States may
lease for oil and gas.
Reclamation means returning disturbed land and water to their
former uses or other productive uses in a stable state that maintains
healthy ecological conditions.
Recompletion means reentering your well to restore productivity of
the original completion.
Record title means legal ownership of an oil and gas lease recorded
in BLM's records.
Record title owner means the person(s) to whom BLM issued a lease
or the person(s) to whom BLM approved the transfer of record title in a
lease.
Routine well maintenance means work you conduct on a well without
altering its configuration. It includes replacing or repairing
malfunctioning equipment, clean out, or evaluation. This work includes,
but is not limited to--
(1) Cutting paraffin and hot oil treatment;
(2) Changing rods and tubing;
(3) Bailing sand;
(4) Pressure surveys;
(5) Swabbing;
(6) Scale or corrosion treatment;
(7) Caliper and gauge surveys;
(8) Removing or replacing subsurface pumps, packers, or screening
pipe;
(9) Running well logs;
(10) Fishing objects from the wellbore that must be recovered
before work can proceed; and
(11) Minor casing repairs.
Sales phase means that period of time or mode of operation during
which you remove crude oil or condensate from storage facilities for
sale, transportation or other purposes.
Seal means a uniquely numbered device that completely secures
either a valve or those components of a measuring system that affect
the quality or quantity of the liquid being measured.
Secondary element means the equipment necessary to convert the
pressure drop created by the primary element into a flowrate and a flow
volume. More specifically--
(1) For chart recorders, this includes the meter manifold, pressure
lines, differential pressure unit, static pressure element, temperature
element, and chart recorder; or
(2) For electric flow computers (EFC), this includes the meter
manifold, pressure lines, differential pressure, static pressure, and
temperature transducers and flow computer.
Secretary means the Secretary of the Interior or the authorized
representative of that office.
Shut-in with respect to wells, means any well capable of producing
in paying quantities or capable of service use, but not currently
producing or not being used.
Spacing means regulating the number and location of wells in a
field or area.
Stipulation means additional specific terms and conditions in the
lease that

[[Page 66880]]

change the manner in which you may conduct operations or that may
otherwise modify the standard lease terms.
Surface management agency means any agency, other than BLM, with
jurisdiction over the surface overlying Federal or Indian owned
minerals.
Suspension means temporary relief of a lessee's obligation to
perform specific functions stipulated in Federal oil and gas lease
terms, laws, and regulations.
Tagging the plug means running in the hole with a string of tubing
or drill pipe and placing sufficient weight on the plug to ensure its
integrity.

Temporarily abandoned with respect to wells, means a well not in
use.

Toxic constituents means substances in produced water in toxic
concentration specified by Federal or State regulations that have
harmful effects on plant or animal life. These substances include, but
are not limited to, arsenic (As), barium (Ba), cadmium (Cd), hexavalent
chromium (bCr), total chromium (tQr), lead (Pb), mercury (Hg), zinc
(Zn), selenium (Se), benzene, toluene, ethyl benzene, and xylenes, as
defined in 40 CFR part 261.
Transfer means any conveyance of an interest in a lease by
assignment, sublease or otherwise. The definition includes the terms
assignment and sublease.

Unavoidably lost with respect to production, means--

(1) Gas vapors that are vented from storage tanks or other low-
pressure production vessels, unless BLM determines that you must retain
or recover those vapors;
(2) Oil or gas lost because of line failures, equipment
malfunctions, blowouts, fires, or otherwise, when BLM determines that
the loss did not result from your negligence or failure to take all
reasonable measures to prevent or control the loss;
(3) Gas you vent or flare during emergencies, short-term well
tests, short-term production tests, or otherwise with BLM's prior
written approval; and
(4) Oil which you may dispose without incurring a royalty
obligation when BLM has first determined it to be waste oil and to have
no economic value.
Underground injection control (UIC) program means a program the
Environmental Protection Agency, primacy State, or Indian Tribe
administers under the Safe Drinking Water Act (42 U.S.C. 300f et seq.),
to ensure that subsurface injection does not endanger underground
sources of drinking water.
Unit agreement means a BLM-approved agreement to cooperatively
explore, develop, operate and share production of all or part of an oil
or gas pool, field or like area, including at least one Federal lease,
without regard to lease boundaries and ownership.
Unit area means all committed leases, other committed tracts and
unleased Federal lands included in a BLM-approved unit. The unit area
excludes any uncommitted tracts within the external boundaries of the
unit.
Unit operator means the person who has stated in writing to BLM
that the interest owners of the committed leases have designated it as
operator for the unit area.
Unitized substances means all oil and gas production that meets
productivity criteria or all oil and gas production from established
participating areas.
Usable water means water that contains less than 10,000 parts per
million (ppm) of total dissolved solids.
Variance means a BLM-approved alternative that meets the intent of,
and allows you to comply with, a provision or standard of parts 3100
through 3190.
Waiver means a BLM-granted permanent exemption from a lease
stipulation, condition of approval, order, lease term for the entire
leasehold, or area covered by the original order or condition of
approval.
Waste means your act or failure to act that is not sanctioned by
BLM as necessary for proper development and production and that results
in--
(1) A reduction in the quantity or quality of oil and gas
ultimately producible from a reservoir under prudent and proper
operations;
(2) Avoidable surface loss of oil or gas; or (3) An avoidable
change in the quality or quantity of produced oil or gas which may
result in a reduced value of such production.
Waste oil means oil or condensate that BLM determines has no
economic value because it is of such poor quality that it cannot be
treated and placed in a marketable condition with existing or modified
lease facilities or portable equipment and cannot be profitably sold to
a reclaimer.
Workover means operations you conduct to maintain, restore, or
increase production or serviceability of a well in its present
completion interval.
Zones known to contain hydrogen sulfide (H2S) means a
geological formation in a field where prior drilling, logging, coring,
testing, or producing operations have confirmed that H2S-
bearing zones will be encountered that contain 100 ppm or more of
H2S in the gas stream; and Zones reasonably expected to
contain H2S means geological formations in the area which
have not had prior drilling, but prior drilling to the same formations
in similar field(s) within the same geologic basin indicates there is
potential for 100 ppm or more of H2S in the gas stream.

Sec. 3101.8 Reference material.

(a) Matter incorporated by reference. There are industry
publications in part 3100 that are incorporated by reference. These
publications are not specifically set out in the regulatory text but
only referenced. The referenced material is part of the regulations in
parts 3100 through 3190 and you must comply with it. BLM considers
cited American Petroleum Institute (API) recommended practices to be
mandatory. Material is incorporated as it exists in the specific
document cited and BLM will publish a notice of any change in the
material in the Federal Register. This incorporation by reference was
approved by the Director of the Federal Register in accordance with 5
U.S.C. 552(a) and 1 CFR part 51.
(b) Accessibility of materials. You may purchase copies of the
referenced materials from the American Petroleum Institute, Order Desk,
1220 L Street, N.W., Washington, D.C., 20005. Certain out-of-print or
withdrawn API publications may be purchased from Global Engineering
Documents, 15 Inverness Way East, P.O. Box 1154, Englewood, Colorado,
80150-1154. You may inspect copies at the Bureau of Land Management,
Regulatory Affairs Group, Room 401, 1620 L Street, N.W. Washington,
D.C. 20036 or at the Office of the Federal Register, 800 North Capitol
St., N.W., Suite 700, Washington, D.C.
(c) Table of material incorporated by reference. The following
table sets out publications that are incorporated by reference. The
first column sets out the name of the publication and where you may
purchase it. The second column lists the section(s) of these
regulations in which the publication is referenced. The second column
is for information only and may not be all inclusive.

[[Page 66881]]

----------------------------------------------------------------------------------------------------------------
Name of material (vendor) 43 CFR section where the material is incorporated
----------------------------------------------------------------------------------------------------------------
(1) API RP 55, ``Recommended Practices for 3151.23 (b) and (d).
Conducting Oil and Gas Producing and Gas
Processing Plant Operations involving Hydrogen
Sulfide'', Second Edition, February 15, 1995 (API
Documents).
(2) API RP 12R1, ``Recommended Practice for 3153.20(a).
Setting, Maintenance, Inspection, Operation and
Repair of Tanks in Production Service'', Fifth
Edition, August 1997 (API Documents).
(3) API Manual of Petroleum Measurement Standards 3153.20(e).
(MPMS), Chapter 3.1A, ``Standard Practice for the
Manual Gauging of Petroleum and Petroleum
Products'', First Edition, December 1994 or API
MPMS Chapter 3.1 B, ``Standard Practice for Level
Measurement of Liquid Hydrocarbons in Stationary
Tanks by Automatic Tank Gauging'', First Edition,
April 1992 (Reaffirmed January 1997). (API
Documents).
(4) API MPMS, Chapter 2.2A, ``Measurement and 3153.20(b).
Calibration of Upright Cylindrical Tanks by the
Manual Tank Strapping Method'', First Edition,
February 1995 (API Documents).
(5) API MPMS, Chapter 2.2B, ``Calibration of 3153.20(b).
Upright Cylindrical Tanks Using the Optical
Reference Line Method'', First Edition, March
1989 (Reaffirmed May 1996) (API Documents).
(6) API MPMS, Chapter 18.1, ``Measurement 3153.20(c).
Procedures for Crude Oil Gathering from Small
Tanks by Truck'', Second Edition, April 1997 (API
Documents).
(7) API MPMS, Chapter 8.1, ``Standard Practice for 3153.20(d).
Manual Sampling of Petroleum and Petroleum
Products'', Third Edition, October 1995, (ASTM
D4057), or Chapter 8.2, ``Sampling of Liquid
Petroleum and Petroleum Products'', Second
Edition, October 1995 (ANSI/ASTM D4177) (API
Documents).
(8) API MPMS, Chapter 9.1, ``Hydrometer Test 3153.20(f) and 3153.31.
Method for Density, Relative Density (Specific
Gravity), or API Gravity of Crude Petroleum and
Liquid Petroleum Products'', (ANSI/ASTM D1298),
June 1981 (Reaffirmed October 1992) (API
Documents).
(9) API MPMS, Chapter 7.1, ``Static Temperature 3153.20(g).
Determination Using Mercury-In-Glass Tank
Thermometers'', First Edition, February 1991.
(Reaffirmed November 1996) (API Documents).
(10) API MPMS, Chapter 10.4, ``Determination of 3153.20(h) and 3153.31.
Sediment and Water in Crude Oil by the Centrifuge
Method (Field Procedure)'', Second Edition, May
1988 (ASTM D96-88) (Reaffirmed May 1998) (API
Documents).
(11) API Specification 11N, ``Specification for 3153.30(b)(1).
Lease Automatic Custody Transfer (LACT)
Equipment'', Fourth Edition, November 1, 1994
(API Documents).
(12) API MPMS, Chapter 6.1, ``Lease Automatic 3153.30 (a), (b)(2) and 3153.32(a).
Custody Transfer (LACT) Systems'', Second
Edition, May 1991 (Reaffirmed July 1996) (API
Documents).
(13) API MPMS, Chapter 12.2, ``Calculation of 3153.32(d)(1) and 3153.37(b)(1).
Liquid Petroleum Quantities Measured by Turbine
or Displacement Meters'', First Edition,
September 1981 (Reaffirmed May 1996) (API
Documents).
(14) API MPMS, Chapter 11.1, Volume I, ``Table 5A-- 3153.32(d)(2).
Generalized Crude Oils and JP-4, Correction of
Observed API Gravity to API Gravity at 60
deg.F.'' ``Table 6A--Generalized Crude Oils and
JP-4, Correction of Volume to 60 deg.F Against
API Gravity at 60 deg.F.'' (ANSI/ASTM D 1250-
80), (IP 200) (API Standard 2540) August 1980
(Reaffirmed October 1993) (API Documents or ASTM
Documents).
(15) API MPMS, Chapter 11.2.1, ``Compressibility 3153.32(d)(3).
Factors for Hydrocarbons: 0-90 deg. API Gravity
Range'', First Edition, August 1984 (Reaffirmed
May 1996) (API Documents).
(16) API MPMS, Chapter 14.3, ``Orifice Metering of 3154.20(a)(1).
Natural Gas and Other related Hydrocarbon
Fluids'', Second Edition, September 1985 (ANSI/
API 2530) (Global Documents).
(17) API MPMS, Chapter 14.3, Part 2, 3154.20(a)(2) and 3154.40(a)(1).
``Specification and Installation Requirements'',
Third Edition, February 1991, Reaffirmed May 1996
(ANSI/API 2530, Part 2, 1991) (API Documents).
(18) API MPMS, Chapter 14.3, Part 3, ``Natural Gas 3154.21.
Applications'', Third Edition, August 1992 (API
Documents).
(19) API MPMS, Chapter 20.1, ``Allocation 3154.32 (a) and (b).
Measurement'', First Edition, September 1993 (API
Documents).
(20) API MPMS Chapter 14.1 ``Collecting and 3154.70(c).
Handling of Natural Gas Samples for Custody
Transfer, Fourth Edition, August 1993'' (API
Documents).
(21) API Bulletin E3, ``Well Abandonment and 3159.22(a).
Inactive Well Practices for U.S. Exploration and
Production Operations, Environmental Guidance
Document'', First Edition, January 1993 (Section
2) (API Documents).
(22) API RP 49, ``Recommended Practices For Safe 3145.41(a), 3145.44 (a) and (d).
Drilling of Wells Containing Hydrogen Sulfide'',
Second Edition, April 15, 1987 (Global Documents).
(23) API RP 53, ``Recommended Practice for Blowout 3145.30(c) and 3145.33(a)(2).
Prevention Equipment Systems for Drilling
Wells'', Third Edition, March 1997 (API
Documents).
(24) API RP 54, ``Recommended Practice for 3145.31 and 3145.34(a).
Occupational Safety for Oil and Gas Well Drilling
and Servicing Operations,'' Second Edition, May
1, 1992 (API Documents).
----------------------------------------------------------------------------------------------------------------

Sec. 3101.10 What do the regulations in parts 3100 through 3190 cover?

(a) These regulations apply to the leasing of Federal lands for oil
and gas. These regulations also provide the operational requirements
associated with the exploration, development and production of oil or
gas on both Federal and Indian lands.
(b) The regulations relating to site security, measurement, reports
of operation activities, and assessments or penalties for noncompliance
with the requirements apply to your wells or facilities on State or
privately-owned mineral lands committed to an agreement approved by the
Department of Interior, such as a unit or communitization agreement, in
which Federal lands or Indian lands share in production.
(c) Notwithstanding the regulations in title 25 of the CFR
concerning oil and gas operations on Indian leaseholds, the regulations
in this part govern with respect to your conduct of oil and gas

[[Page 66882]]

operations, acts of noncompliance, and BLM's jurisdiction and
authority.
(d) These regulations do not apply to Osage Indian lands.

Sec. 3101.11 Who must comply with the lease terms, regulations, orders
and Notices to Lessees (NTL's) BLM issues?

Interest owners and operators must comply with the lease terms,
regulations and BLM's orders and NTL's. Their agents, contractors or
subcontractors must also comply. The interest owner and operator are
responsible if they do not comply.

Sec. 3101.12 As a record title owner, what are my obligations?

(a) You are responsible for all performance on the lease, including
paying any rent and royalty due. If there is more than one record title
or operating rights owner, each of you is jointly and severally liable
for nonmonetary lease obligations, including the obligation to protect
the lease from drainage and to pay compensatory royalty that may be
owed. You also are jointly and severally liable for plugging and
abandonment obligations that accrue while you hold your record title
interest. This means that if you own a 50 percent record title interest
in the lease, BLM may hold you responsible for 100 percent of the lease
obligations if your joint owner(s) defaults. However, for monetary
obligations, such as paying rent and royalty, your obligation is
proportionate to your interest. Therefore, if you own 25 percent of the
record title interest, you are liable for only 25 percent of the rental
and royalty on production.
(b) You are ultimately responsible for compliance with the lease
terms and conditions regardless of who conducts actual lease
operations.

Sec. 3101.13 As an operating rights owner, what are my rights and
obligations?

(a) You have the right to enter the leased lands to conduct
drilling and related operations including producing oil or gas,
according to the lease terms.
(b) You have the right to authorize another party to conduct
operations on the lease.
(c) You are jointly and severally liable with the other record
title or operating rights holders in the lease for all nonmonetary
lease obligations pertaining to that portion of the lease subject to
your operating rights, and proportionately liable for monetary
obligations with other operating rights holders for that portion of the
lease subject to your operating rights.

Sec. 3101.14 Does BLM warrant title to the oil and gas deposits when
it issues a lease or approves subsequent lease actions or lease
operations?

If BLM issues a Federal oil and gas lease or approves your
application under parts 3100 through 3190, the United States--
(a) Does not make any warranty of title, either express or implied,
to the oil and gas deposits;
(b) Is under no obligation to you to either discover or dispose of
any other person's claims to the oil and gas deposits or assume any
obligation to defend the oil and gas lease against any claims; and
(c) Does not warrant or certify that you hold legal or equitable
title to your leases which would entitle you to conduct drilling
operations.

Sec. 3101.15 Must I give BLM information and documentation about my
lease?

You must give BLM any information or documentation that BLM
requests to properly administer your lease or to determine your
compliance with applicable laws and regulations. This information may
include, but is not limited to, information about your lease operations
or production.

Sec. 3101.16 What requirements must I follow in addition to the
regulations in parts 3100 through 3190?

BLM may--
(a) Include lease stipulations to minimize the impacts or
interference that oil and gas operations may cause to other resource
values, land uses or users. BLM will provide notice of the stipulations
on oil and gas lease parcels before any of the lands are offered for
lease. You agree to the stipulations attached to the parcel offered for
lease when you bid on a competitive lease parcel or file a
noncompetitive lease offer. Stipulations become a part of the terms of
your lease and replace any inconsistent provisions of the standard
lease form at the time of lease issuance. You must comply with the
stipulations for all actions you take on the lease. Some examples of
common stipulation types include--
(1) Limitations on when you may conduct operations;
(2) No surface occupancy;
(3) Other surface use restrictions; and
(4) Requirements to join an approved agreement.
(b) Impose conditions of approval on the granting of required
permits or authorizations that are reasonable and necessary for the
protection of resources and other uses of the land and which are
consistent with lease rights;
(c) Issue NTL's to provide information or explanation as to how the
regulations in this part apply to your lease operations, or to provide
alternative methods to meet the requirements of these regulations;
(d) Issue written or oral orders to you for specific lease
operations. BLM will confirm an oral order in writing;
(e) Require tests and surveys to--
(1) Determine the presence, quantity, and quality of oil, gas,
other minerals, or the presence or quality of water;
(2) Determine the amount and/or direction of deviation of any well
from the vertical;
(3) Determine the relevant characteristics of the oil and gas
reservoirs penetrated; and
(4) Demonstrate the mechanical integrity of the downhole equipment;
and
(f) Require you to provide other information required for proper
administration of your lease.

Sec. 3101.17 May BLM establish development and production requirements
for my lease?

(a) BLM may direct you to drill and produce wells that will
reasonably and timely develop your lease in accordance with good
economic practices.
(b) After you receive written notice from BLM, you must drill and
produce all wells BLM determines necessary to diligently develop your
lease.

Sec. 3101.18 Will I be responsible for compensating the United States
or Indian lessor if my lease is being drained of oil and gas by wells
on adjacent tracts?

You are responsible for protecting the United States or Indian
lessor from losses of royalty due to drainage if it would be economic
to drill a protective well, as further provided in Sec. [to be
specified in the final rule].

Sec. 3101.19 May I obtain relief from the requirements of the
regulations in parts 3100 through 3190 or other requirements BLM
developed?

(a) BLM may grant you a variance to these regulations if your
proposal meets or exceeds the objectives of the regulations involved.
BLM may not waive statutory requirements.
(b) BLM may waive, except or modify stipulations, conditions of
approval, orders, or terms of the lease if you submit a written request
and if--
(1) BLM determines the reason for the stipulation, condition of
approval, order, or term of the lease is no longer valid; or
(2) You propose an alternative that meets or exceeds the intent of
the stipulation, condition of approval, order, or term of the lease.
(c) If BLM determines that a waiver, exception or modification to a
lease stipulation is an issue of major public

[[Page 66883]]

concern, BLM will post the change for at least 30 days to allow public
review. BLM will post the change in the BLM office with jurisdiction
over the land in the lease and make it available for posting in the
local surface management agency office before approval.
(d) BLM will not waive, modify or grant exceptions to stipulations
to a lease covering lands managed by another Federal agency without
that agency's concurrence.
(e) BLM will not process requests for exceptions to lease
stipulations, conditions of approval or orders that concern surface use
on National Forest System (NFS) lands. You must submit requests for
these exceptions to the Forest Service (FS).

Sec. 3101.20 When will BLM consider a document filed?

BLM considers any document required by law, regulation or decision
to be timely filed --
(a) When the BLM office where it must be filed receives it on or
before the date it is due during regular business hours; or
(b) If the BLM office is officially closed on the due date, the
next day the office is open to the public. BLM State Offices and the
lands they administer are identified in 43 CFR 1821.2.

Sec. 3101.21 Are there other requirements that affect oil and gas
operations on Federal or Indian lands?

You will find most of the requirements that affect oil and gas
leasing (for Federal lands) and operations (for Federal and Indian
lands) in this part. However, some BLM requirements are covered under
other sections of title 43 of the CFR. The following table lists some,
but not all, of the other regulations that may apply to your lease--

----------------------------------------------------------------------------------------------------------------
Rights-of-way across BLM managed surface 43 CFR part 2800
----------------------------------------------------------------------------------------------------------------
Production and royalty reporting requirements, 30 CFR parts 200 through 243.
and late payments--Minerals Management
Service (MMS).
Indian oil and gas leasing--Bureau of Indian 25 CFR parts 211, 212, 213, 225 and 227.
Affairs.
Proprietary or confidential information and 43 CFR part 2.
Freedom of Information Act requests.
BLM land use planning......................... 43 CFR part 1600.
Surface use plans--FS......................... 36 CFR part 228.
Special Use Authorizations--FS. (in lieu of 36 CFR parts 212 and 251.
Rights of Way).
Release of hazardous substances--Environmental 40 CFR part 302.
Protection Agency (EPA).
Underground Injection Control permits--EPA.... 40 CFR parts 144 and 146.
Spill Prevention Control and Countermeasure 40 CFR part 112.
plan--EPA.
Worker safety--Occupational Safety and Health 29 CFR part 1910.
Administration.
Late payments--MMS............................ 30 CFR part 202.
Procedures for Tribes to request payment under 43 CFR part 12, subparts A and C.
cooperative agreements.
Disposal of reserved minerals under the Act of 43 CFR parts 3813 and 3814.
July 17, 1914 and Stockraising Homestead Act.
National Environmental Policy Act............. 40 CFR part 1500.
Appeal BLM decisions.......................... 43 CFR parts 4 and 1840.
Appeal FS decisions........................... 36 CFR parts 215, 217 and 251.
----------------------------------------------------------------------------------------------------------------

Sec. 3101.22 May I appeal BLM's decisions under parts 3100 through
3190?

Any person adversely affected by a BLM decision under parts 3100
through 3190 may appeal the decision under 43 CFR parts 4 and 1840.

Subpart 3102--Recordkeeping

Recordkeeping

Sec. 3102.10 What records must I keep?

(a) You must keep accurate and complete records on all lease
operations, such as, drilling, testing, producing, redrilling,
deepening, repairing, plugging back, and abandoning wells, and other
matters pertaining to well operations. For facilities and equipment,
also keep required schematic diagrams. You must keep any records
related to production accountability BLM may require.
(b) You must submit or make available complete and accurate records
to BLM when we request you to do so. Whenever you submit data,
information or notification to BLM, you are certifying that it is
accurate.

Sec. 3102.11 How long must I keep records?

(a) If you are a record title owner, an operating rights owner, or
a designee for a Federal lease, you must keep accurate and complete
records that pertain to all Federal lease operations, for seven years
from the date you generated the record unless the time is extended
under 30 CFR 212.50.
(b) If you are the lessee, operator, revenue payor, or other person
under 30 U.S.C. 1713(a) for Indian leases, you must keep all records
that pertain to Indian lands for six years from the date you generated
them, or such longer period authorized under the Federal Oil and Gas
Royalty Management Act of 1982, as amended (FOGRMA) (30 U.S.C. 1701 et
seq.).

Subpart 3103--Reports, Submissions, and Notifications

Reports, Submissions and Notifications

Sec. 3103.10 What reports and notifications must I submit to BLM?

The following table includes the most common records you must keep,
reports you must submit, notifications you must provide BLM, and when
you must submit them. The local BLM office may adjust notification and
submittal times. When a specific form is required, BLM may approve
alternative methods of data submission. The records that do not require
a specific BLM form, but that you still must submit, are marked
``None.'' You also may be required to submit other records, reports and
notifications not listed in the following table, but that are required
by the regulations in this part.

[[Page 66884]]

(b) Bond or rider to State or Within five business days of filing a 3000-4a............. Secs. 3108.10 and 3108.13.
nationwide bond. Notice of Intent (NOI) or Permit 3104-8a
Application to Conduct Geophysical
Exploration Operations. Your NOI cannot
be approved without an accepted bond or
rider to an existing accepted bond.
(c) Terms and conditions for Return it to the BLM office having 3150-4a............. Sec. 3112.11.
conducting geophysical exploration jurisdiction over the land in the
operations. application prior to starting operations.
(d) Geophysical exploration Within 30 calendar days after you complete 3150-5.............. Secs. 3112.20 and 3113.40.
completion report. geophysical operations, including
reclamation activities.
(e) Competitive lease bid.......... On the day of the sale for each parcel 3000-2.............. Sec. 3122.15.
that you were the winning bidder.
(f) Offer to lease................. Within a reasonable time from the date of 3100-11............. Sec. 3123.20.
execution by the offeror or official
representative.
(g) Assignment of record title Within 90 calendar days of execution by 3000-3.............. Sec. 3129.30
interest. the assignor. Filing it later can lead to
unnecessary delays while BLM requests
additional information.
(h) Transfer of operating rights Within 90 calendar days of execution by 3000-3a............. Sec. 3129.30.
interest (sublease). the transferor. Filing it later can lead
to unnecessary delays while BLM requests
additional information.
(i) Construction start-up notice... At least 48 hours before you start Orally.............. Subpart 3145.
construction.
(j) Spud notice.................... At least 24 hours before spudding......... Orally.............. Subpart 3145.
(k) Electric and other logs run on Within 30 calendar days after you run logs None................ Secs. 3145.22 and 3145.54.
your well.
(l) Completion or Recompletion Within 30 calendar days after you complete 3160-4.............. Secs. 3145.22 and 3145.54.
report. or recomplete your well.
(m) Running surface casing and BOP At least 12 hours before you run surface Orally.............. Secs. 3145.30 and 3145.33.
test notice. casing and before conducting BOP tests.
(n) Drill Stem Tests or other tests Within 30 calendar days after you conduct None................ Sec. 3145.22.
tests.
(o) Removal of drilling fluids At least 24 hours before you remove fluids Orally.............. Subpart 3145.
before reserve pit closure notice. from the reserve pit.
(p) Action to correct or contain an Within 48 hours after the emergency occurs None................ Sec. 3145.52.
emergency.
(q) Subsequent report of additional Within 30 calendar days after you alter an 3160-5.............. Sec. 3145.54.
well operations. existing well bore. Within 30 calendar
days after you complete approved actions
when BLM requests a report.
(r) Production start-up notice..... Not later than five business days after 3160-5.............. Sec. 3151.12.
you begin production, or resume
production after shutting in your well
for 90 calendar days or more.
(s) H2S concentrations at Within five calendar days whenever tests 3160-5.............. Sec. 3151.20.
production facilities. reveal a concentration of 20 ppm, or
greater (unless previously reported).
Within five business days whenever the
H2S concentration changes by 5 percent or
more from a previously reported test.
(t) H2S Public Protection Plan..... Within 60 calendar days after the criteria None................ Sec. 3151.23.
of Sec. 3151.23(d) apply.
(u) Site security plans............ Within five business days after BLM None................ Sec. 3152.50.
requests a plan.
(v) Seal numbers, where the seals Within five business days after BLM None................ Sec. 3152.50.
were used, date and reason for requests a report.
installation and removal.
(w) Site facility diagrams......... Within 60 calendar days after you complete None................ Sec. 3152.51.
construction, first produce, or include a
well on committed non-Federal lands in a
Federally supervised unit or
communitization agreement, whichever
happens first.
(x) Reports of theft or mishandling Within 24 hours after you discover the Orally.............. Sec. 3152.80.
production. theft or mishandling.
(y) Tank or strapping tables....... Within five business days after BLM None................ Sec. 3153.20.
requests a copy.
(z) Notice of LACT Meter Proving... At least five business days before proving Orally.............. Sec. 3153.32.
sales or allocation meters.
(aa) LACT meter proving report..... Within 10 business days after you prove None................ Sec. 3153.37.
the LACT meter.
(bb) Run tickets, gas charts....... Within five business days after BLM None................ Secs. 3153.40 and 3154.30.
requests a copy.
(cc) Records on installation, Within five business days after BLM None................ Subparts 3153 and 3154.
maintenance, repair, inspection, requests a copy.
and testing of metering systems.
(dd) Notice of gas meter proving or At least 10 business days before you None................ Sec. 3154.32.
calibration schedule. conduct the proving or first scheduled
calibration.
(ee) Leak detection system notice.. At least two business days before you Orally.............. Sec. 3155.15.
install a produced water pit liner.
(ff) Produced water pit completion At least two business days before you use Orally.............. Secs. 3155.15 and 3155.16.
notice. a produced water pit.
(gg) Spill or accident reports..... Within 24 hours after the accident or Orally.............. Sec. 3156.11.
spill.
(hh) Spill or accident reports..... In writing within 10 business days after None................ Sec. 3156.12.
the spill or accident occurs.
(ii) Well abandonment notice....... At least 24 hours before you start Orally.............. Sec. 3159.21.
approved plugging operations. BLM may
grant oral approval if you request it..

[[Page 66885]]

3000-3.............. Sec. 3129.30.
(jj) Encountering concentrations of Within 24 hours of the occurrence......... Orally.............. Sec. 3145.43.
100 ppm or more of H2S not
anticipated.
--------------------------------------------------------------------------------------------------------------------------------------------------------

Form Description:

Form 3000-4 is an Oil and Gas or Geothermal Lease Bond.
Form 3000-4a is an Oil and Gas or Geothermal Exploration Bond.
Form 3104-8a is a State or Nationwide Oil and Gas Lease Bond Rider.
Form 3150-4a is a Terms and Conditions for Notice of Intent to
Conduct Oil and Gas Geophysical Exploration Operations.
Form 3150-5 is a Notice of Completion of Oil and Gas Exploration
Operations.
Form 3000-2 is a Competitive Oil and Gas or Geothermal Resources
Lease Bid.
Form 3100-11 is an Offer to Lease and Lease for Oil and Gas.
Form 3000-3 is an Assignment of Record Title Interest in a Lease
for Oil and Gas or Geothermal Resources.
Form 3000-3a is a Transfer of Operating Rights (sublease) in a
Lease for Oil and Gas or Geothermal Resources.
Form 3160-4 is a Well Completion or Recompletion Report and Log.
Form 3160-5 is a Sundry Notices and Reports on Wells.

Sec. 3103.11 If I am the record title or operating rights interest
owner, what must be filed with BLM to authorize someone else to conduct
operations on my lease?

(a) The person you authorize to conduct operations on your lease
must notify BLM in writing that it is the new operator. The new
operator must identify, by number, the bond that will cover its
operations.
(b) The operator may provide bond coverage on its own behalf or the
operator may be covered by the lessee's bond.

Subpart 3104--Environment and Safety

Environment and Safety

Sec. 3104.10 How may I use the surface and subsurface of my lease to
develop oil and gas?

(a) For a Federal lease, you have the right to use as much of your
lease site as you reasonably need to explore, drill, mine, extract,
remove and dispose of the leased resources. However, your lease may
include stipulations that restrict your use of the surface or other
lease areas.
(b) BLM may restrict your use of a lease with conditions of
approval (COA) after lease issuance. These restrictions may include
COA's pertaining to--
(1) Environmental quality and resources;
(2) Threatened and endangered species;
(3) Cultural or historic resources; and
(4) Private or other rights where the surface is either not owned
by the United States or not managed by BLM.
(c) For Indian leases, see Title 25 of the CFR for rights to
surface use.
(d) When the surface is privately owned or held in trust for an
Indian Tribe or allottee, or managed by an agency other than BLM, you
must make access arrangements with the private surface owner, agency
other than BLM, or BIA and Indian mineral owner before you enter the
lands to survey, stake or conduct inventories.

Sec. 3104.11 May BLM take measures to minimize adverse impacts to
resource values, land uses or users not addressed in the lease
stipulations and not required by statutes or regulations?

BLM may develop conditions of approval, consistent with your lease
rights, to reduce adverse impacts to other resource values, land uses
or users or to avoid unnecessary and undue degradation. These measures
may include, but are not limited to--
(a) Modifying the location or design of proposed operations;
(b) Restricting the time that surface disturbance is allowed; and
(c) Specifying interim and final reclamation measures.

Sec. 3104.12 What measures may BLM take that are always consistent
with my lease rights?

Measures that BLM may require consistent with your lease rights
include, but are not limited to--
(a) Relocating proposed operations up to 660 feet, unless this
would place operations off of the lease;
(b) Prohibiting new surface disturbing operations for a period up
to 60 calendar days in each lease year; and
(c) Specifying reclamation measures to prevent unnecessary and
undue degradation of public lands or resources.

Sec. 3104.13 May anyone other than BLM impose lease stipulations?

(a) When Federal oil and gas lie beneath surface that a Federal
agency other than BLM manages, BLM will contact that agency to
determine whether the surface management agency will impose
stipulations on the lease.
(b) BLM will lease the following Federal lands only if the surface
management agency agrees to leasing. BLM will include in the issued
lease any stipulations the surface management agency has required as a
condition of its consent to leasing--
(1) Acquired lands;
(2) Public domain lands, if the statute requires surface management
agency consent or a decision that it has no objection to leasing;
(3) Lands managed by the Department of Defense; and
(4) National Forest System lands.
(c) BLM will only lease public domain lands withdrawn for the use
of another Department of the Interior agency after consulting with the
surface management agency. BLM may adopt recommended stipulations or
decide not to lease the parcel.
(d) Where the United States has conveyed control of the surface of
lands to any State, local or tribal government or agency, or
educational or religious organization and reserved the oil and gas
rights, BLM will give the entity holding the surface rights an
opportunity to suggest stipulations necessary to protect existing
surface improvements or uses. BLM may adopt or modify recommended
stipulations, add stipulations, or decide not to lease the parcel.
(e) When a surface management agency has agreed that BLM may lease
lands under its jurisdiction, BLM retains the right to make the final
determination whether to offer the lands for lease.

Sec. 3104.14 What must I do to protect the environment and ensure
safety when I conduct operations to develop Federal and Indian lands,
or geophysical operations on Federal lands?

You must--
(a) Plan and conduct your operations and develop contingency plans
that --
(1) Protect the environment;
(2) Avoid contaminating lands and waters on and adjacent to your
lease; and

[[Page 66886]]

(3) Ensure safe field operations;
(b) Conduct your operations with care and diligence and in a safe
manner to--
(1) Avoid unreasonable damage to surface or subsurface resources
and surface improvements; and
(2) Protect public health and safety;
(c) Maintain your equipment and facilities to--
(1) Provide adequate protection for public health and safety and
the protection of property; and
(2) Avoid accidents and spills;
(d) Report, control and clean up spills and accidents; and
(e) Properly plug and abandon your wells and reclaim all lands and
waters that you disturb or contaminate.

Subpart 3105--Lessee Qualifications

Lessee Qualifications

Sec. 3105.10 Who may hold a lease?

You may acquire and hold a lease or lease interests if you are--
(a) A citizen of the United States;
(b) An association (including a partnership or trust) of United
States citizens;
(c) A corporation organized under the laws of the United States or
of any State or Territory of the United States; or
(d) A municipality.

Sec. 3105.11 If I am not a United States citizen, may I acquire or
hold an interest in a lease?

If you are not a United States citizen you may--
(a) Not hold an interest in a lease directly or as a member of an
association;
(b) If your country does not deny similar or like privileges to
United States citizens because of nationality, hold --
(1) Stock in a corporation which holds a lease interest;
(2) Stock in a corporation which holds an interest in an
association which holds a lease interest; or
(3) An interest in an association or stock in another corporation,
which in turn holds stock in a corporation which holds a lease
interest.

Sec. 3105.12 If I am not qualified to hold a lease, may I hold one
anyway if I acquire it by descent, will, judgment or decree?

If you are not qualified to hold a lease for any reason, you may
acquire or hold lease interests by descent, will, judgment or decree
for no longer than two years from the time you acquire it. If you hold
this interest for more than the two-year period allowed, it is subject
to cancellation.

Sec. 3105.13 Under what circumstances may minors acquire or hold
interest in a Federal oil and gas lease?

(a) Minors may not directly hold or acquire leases. Whether you are
a minor is determined by the laws of the State where the leased lands
are located.
(b) Leases may be acquired and held by legal guardians or trustees
of minors. Legal guardians or trustees must be citizens of the United
States and not in violation of any statute or regulation cited in
Sec. 3105.14.

Sec. 3105.14 Under what conditions will I be prohibited from acquiring
a lease or interest in a lease?

You are prohibited from acquiring lease interests if you are in
violation of--
(a) 43 CFR 3472.1-2(e)(1)(i), except for an assignment or transfer
under subpart 3129;
(b) Section 41 of the Act, or have been subjected to criminal
penalties or to a civil order prohibiting participation in exploration,
leasing or development of Federal oil and gas;
(c) Section 17(g) of the Act (30 U.S.C. 226(g)), after notice and
an opportunity to comply with such requirements or standards was given
and you did not comply. This means that you must not be a person,
association or corporation, or any subsidiary, affiliate or person
controlled by or under common control with such person, association, or
corporation, during any period in which you or any subsidiary,
affiliate or person controlled by, or under common control with you,
failed or refused to comply in any material respect with reclamation
requirements or other standards established under Section 17 of the Act
(30 U.S.C. 226); and
(d) Federal acreage limitation requirements (see Sec. 3105.20).

Sec. 3105.15 What must I file with BLM to establish that I meet the
qualifications to hold a lease?

When you sign and submit to BLM an application, lease offer,
competitive bid, assignment or transfer form, you certify that you are
in compliance with the provisions of this subpart.

Sec. 3105.16 May BLM require me to submit additional information to
determine if I meet the qualification requirements to acquire or hold
an interest in a lease?

BLM may require additional information from anyone seeking to
acquire or currently holding a Federal lease interest.

Acreage Limitation

Sec. 3105.20 What is the acreage limitation for holding, owning or
controlling oil and gas lease interests on public domain lands?

(a) Except for Alaska, you may not hold, own or control more than
246,080 acres of Federal oil and gas leases or operating rights, or
200,000 acres in options, in any one State at any one time.
(b) In Alaska, you may not hold, own or control more than 300,000
acres in the northern leasing district and 300,000 acres in the
southern leasing district in options, leases or operating rights.

Sec. 3105.21 What is the boundary between the two leasing districts in
Alaska?

The boundary between the two leasing districts in Alaska begins at
the northeast corner of the Tetlin National Wildlife Refuge as
established on December 2, 1980 (16 U.S.C. 3101), at a point on the
boundary between the United States and Canada, then northwesterly along
the northern boundary of the refuge to the left limit of the Tanana
River (63 deg. 9' 38'' north latitude, 142 deg. 20' 52'' west
longitude), then westerly along the left limit to the confluence of the
Tanana and Yukon Rivers, and then along the left limit of the Yukon
River from said confluence to its principal southern mouth.

Sec. 3105.22 What is the acreage limitation for holding, owning or
controlling oil and gas lease interests on acquired lands?

The acreage limitations for holding, owning or controlling leases
of acquired lands is the same as for public domain lands (see
Sec. 3105.20). Acquired lands acreage holdings are charged separately
from public domain lands acreage holdings.

Sec. 3105.23 What is an option agreement?

An option agreement is a contractual arrangement between two or
more persons that grants a right to acquire record title or operating
rights interest in a lease(s) at some future date or occurrence.

Sec. 3105.24 Must I file my option agreement with BLM?

You are not required to automatically file option agreements.
However, BLM may require you to furnish this information for acreage
audit purposes.

Sec. 3105.25 What effect do options have on lease acreage holding
limitations?

(a) You may not hold more than 200,000 acres under option in any
one State or in each of the two leasing districts in Alaska.
(b) If you hold an option, BLM charges the acreage to you against
the limits in Secs. 3105.20 and 3105.22.

[[Page 66887]]

Sec. 3105.26 How will BLM charge acreage holdings on lands where the
United States owns a fractional interest in the mineral resource?

If your lease includes lands where the United States owns only a
fractional interest in the mineral resources of the lands, BLM will
charge you only with the net mineral acres owned by the United States.

Sec. 3105.27 What lease interests are not chargeable against acreage
limitations?

BLM does not include the following acreage or interests against
acreage chargeability--
(a) Lease acreage held in leases issued under the Act of May 21,
1930;
(b) Acreage in a future interest lease until the mineral interest
vests in the United States;
(c) Lease acreage committed to any BLM-approved cooperative or unit
plan;
(d) Leases subject to an operating, drilling or development
contract BLM approved; and
(e) Overriding royalty interests, net profits or production
payments.

Sec. 3105.28 What if I exceed the acreage limitation?

(a) If the acreage you hold exceeds the statutory limit as a result
of --
(1) The termination or contraction of a unit or cooperative plan or
due to the elimination of a lease from an operating, drilling or
development contract, you must reduce your holdings to the prescribed
limitation within 90 calendar days from the date you first held excess
acreage and provide BLM proof of the reduction; or
(2) A merger or the purchase of the controlling interest in a
corporation, you must reduce your holdings to the prescribed limitation
within 180 calendar days from the date you first held excess acreage
and provide BLM proof of the reduction. If you require additional time
to complete the divestiture of the excess acreage, you may petition the
BLM office with jurisdiction over the subject leases for additional
time.
(b) If BLM finds that you hold chargeable acreage in violation of
the provisions of the regulations in this part and you do not
voluntarily reduce your acreage holdings to the amount of acreage
allowed, BLM may seek a court order to cancel or require you to forfeit
lease(s) or interests in inverse order of acquisition, until sufficient
acreage has been eliminated to comply with the acreage limitation. This
means that the last leases you acquired will be the first leases BLM
will ask the court to cancel or require you to forfeit.

Sec. 3105.29 How does BLM compute chargeable acreage?

(a) BLM will aggregate all record title, operating rights and lease
options you hold, own or control to determine whether you exceed the
acreage limitations. If you --
(1) Own 100 percent of the record title, operating rights or
options in a lease, you are charged for all of the acreage in the
lease;
(2) Own an undivided interest in the record title, operating rights
or options in a lease, you are charged for your proportionate part of
the lease acreage;
(3) Own or control more than 10 percent of the stock of a
corporation, or of the instruments of ownership or control of an
association, that holds the record title, operating rights or options
in a lease, you are accountable for your proportionate part of the
lease acreage held by the corporation or association. If you are a
corporation, you are not charged for the acreage owned by your
stockholders; or
(4) Are part of a group that is not an association, and that holds,
owns or controls record title, operating rights or options in a lease,
you are charged proportionately.
(b) Any group of persons who holds, owns or controls a lease or
leases in common may not exceed the acreage that the law allows persons
to hold.

Sec. 3105.30 May BLM require me to provide information with respect to
my acreage holdings?

BLM may require you to file a statement indicating the lease
interests you hold as of a specified date by serial number, date of
issuance and number of acres for each lease in any State.

Subpart 3106--Fees, Rentals and Royalties

Fees and Rentals

Sec. 3106.10 What form of payment will BLM accept?

BLM will accept payments by--
(a) Personal, cashier and certified checks;
(b) Money orders;
(c) Electronic funds transfers; or
(d) Credit cards when BLM authorizes it.

Sec. 3106.11 Who should I pay?

Your payment must be made payable to the Department of the
Interior, Bureau of Land Management (BLM) or to the Minerals Management
Service (MMS), as appropriate.

Sec. 3106.12 Where should I submit my payments?

Submit your payments according to the following chart--

------------------------------------------------------------------------
Type of payment Submit to
------------------------------------------------------------------------
(a) Filing fees for offers, transfers, The BLM State Office with
first year rentals and bonus bids. jurisdiction over the lands
in your lease.
(b) Second year and subsequent rentals.... MMS.
(c)(1) Royalties and minimum royalties;... MMS.
(2) Compensatory royalty assessments on
leases;
(3) Payments due on drainage agreements;
and
(4) Subsurface storage agreement payments.
------------------------------------------------------------------------

Sec. 3106.13 What are the rental rates for Federal leases?

The rental rates for Federal leases are as follows--

------------------------------------------------------------------------
Rental rate per acre or
Types of leases fraction of an acre
------------------------------------------------------------------------
(a) Offers filed and leases issued after $1.50 for the first five
December 22, 1987. years and $2 for the
sixth and succeeding
years.
(b) Leases issued from offers filed before Rental as stated in the
December 22, 1987, except those leases lease or in regulations
identified in paragraphs (c) through (h) of in effect at the time
this table. the offer was filed.
(c) Leases issued under the simultaneous $1 for the first five
leasing regulations, 43 CFR part 3100, years and $2 for the
subpart 3112 (contained in the 43 CFR, parts sixth and succeeding
1000 to 3199, edition revised as of October years.
1, 1981 and amended at 47 FR 2864 (January
20, 1982)), on or after February 19, 1982.
(d) Exchange (30 U.S.C. 226(i)) and Renewal $2.
Leases issued under Sections 13 and 14 of
the original Mineral Leasing Act of 1920.
(e) Leases issued under the 1930 Right-of-Way $1.50 for the first five
Leasing Act (30 U.S.C. 301-306). years and $2 the sixth
and succeeding years.

[[Page 66888]]

(f) Terminated leases originally issued $5. Each succeeding
noncompetitively and reinstated under reinstatement will
subpart 3142 (Class II reinstatement increase the rental by
regulations) beginning with the termination $5 per acre or fraction
date. of an acre.
(g) Terminated leases originally issued under $5. Each succeeding
subpart 3142 (Class III reinstatement reinstatement under
provisions for conversion of unpatented oil subpart 3142 (Class II)
placer claims) beginning with the will increase the rental
termination date. by $5 per acre or
fraction of an acre.
(h) Terminated leases originally issued $10. Each succeeding
competitively and reinstated under Sec. reinstatement will
3142.8 (Class II reinstatement regulations) increase the rental by
beginning with the termination date. $10 per acre or fraction
of an acre.
------------------------------------------------------------------------

Sec. 3106.14 How does BLM calculate the rental due on my lease?

Rental is calculated on a per acre or fraction of an acre basis.
For example, if your lease contains 640.32 acres and the rental is $2
per acre, you should round the acreage up to 641.00 and multiply by $2.
Your annual rental would be $1,282.00.

Sec. 3106.15 If BLM assessed my nonproducing lease compensatory
royalty, must I also pay rental?

You must pay rental in addition to any compensatory royalty.

Sec. 3106.16 What if I do not submit enough rental with my lease
offer?

BLM determines the rental you filed as the total amount of money
you submitted minus the required filing fee. BLM will accept your lease
offer, without loss of priority, if your rental payment is deficient by
not more than the lesser of--
(a) Ten percent of the total rental due; or
(b) $200.

Sec. 3106.17 When must I pay the balance of a rental deficiency on my
lease offer?

You must pay the balance to BLM within 30 calendar days from the
date you receive BLM's notice of rental deficiency.

Sec. 3106.18 What if I do not pay the balance of the rental due within
the time allowed?

BLM will--
(a) Reject your lease offer; or
(b) Cancel your lease if it has been issued.

Sec. 3106.19 What if I base my deficient rental payment on an
incorrect acreage advertised in the Notice of Competitive Lease Sale?

You must pay the additional rental within the time stated in BLM's
deficiency notice, without loss of priority to your offer.

Sec. 3106.20 If the United States owns less than 100 percent of the
mineral rights in my lease, must I pay rental on the gross acreage or
on the net acreage?

You must pay rental on the entire lease, even if the United States
owns less than 100 percent of the mineral rights in your lease.

Sec. 3106.21 When should I pay the second and succeeding rental
payments after BLM issues my lease?

The MMS must receive your second and succeeding rental payments on
or before the anniversary date of lease issuance each year.

Sec. 3106.22 Must I pay a full year's rental if less than a full year
is left in my lease term?

If less than a full year remains in your lease term, you must pay a
full year's rental.

Sec. 3106.23 What if MMS receives my rental payment after the date it
is due?

(a) If your rental payment is late, your lease automatically
terminates by operation of law. BLM will send you a termination notice.
(b) Refer to subpart 3142 for more information on terminations and
reinstatements.

Sec. 3106.24 What if the MMS office is closed on the date that my
rental payment is due?

If the MMS office is closed on the date your rental payment is due,
payment it receives on the next day the office is open to the public is
considered timely.

Sec. 3106.25 What if I incorrectly mail my second or succeeding rental
payment to BLM instead of MMS?

BLM will return the rental payment to you if you incorrectly mailed
your second or succeeding advance rental payment to BLM instead of MMS.
If MMS does not receive your payment timely, see Sec. 3106.23.

Sec. 3106.26 What will BLM do if I mail a payment due to BLM to the
wrong BLM office?

If you mail any payment due to BLM to the wrong BLM office, BLM
will return the payment to you. It is your responsibility to timely
make your payment to the BLM office with jurisdiction over the lease(s)
or lands for which you are making payment.

Royalties

Sec. 3106.30 What royalty must I pay after I establish production?

You must pay royalty according to the following chart--

------------------------------------------------------------------------
Type of lease Royalty rate
------------------------------------------------------------------------
(a) Leases issued after December 22, 1987, 12\1/2\ percent.
including: (1) Competitive; (2)
Noncompetitive; (3) Exchange; (4) Renewal;
and (5) Leases issued in lieu of unpatented
oil placer mining claims under subpart 3142.
(b) Railroad Right-of-Way.................... At a minimum 12\1/2\
percent, subject to
competitive bidding.
(c) Leases issued after December 22, 1987, The rates identified in
resulting from offers or bids filed on or the lease terms or in
before December 22, 1987. regulations in effect on
December 22, 1987
(d) Leases issued on or before December 22, The rates identified in
1987. the lease terms or in
regulations in effect at
the time of lease
issuance.
(e) Reinstated Noncompetitive Leases......... 16\2/3\ percent plus an
additional 2 percent for
each succeeding
reinstatement.
(f) Reinstated Competitive leases............ Not less than 4 percent
above the existing
royalty rate, plus an
additional 2 percent for
each succeeding
reinstatement.

[[Page 66889]]

(g) Deposits determined by BLM to be a new 12\1/2\ percent.
deposit and discovered on leases after May
27, 1941 (30 U.S.C. 226(c)), by a well
drilled on a lease or committed to a unit
agreement or proposed for unitization at the
time of discovery.
(h) Lands not believed to be within the 12\1/2\ percent.
productive limits of any producing oil and
gas deposit found by the Secretary to exist
on August 8, 1946, under the Act of that
date (30 U.S.C. 226(c)).
------------------------------------------------------------------------

Sec. 3106.31 What is minimum royalty?

Minimum royalty is the minimum amount of money you must pay
following the date you establish production in paying quantities. You
must pay the minimum royalty or the royalty due for the actual
production, whichever is greater.

Sec. 3106.32 When must I pay the minimum royalty due on my lease?

You must pay minimum royalty at the end of each lease year after
you discover oil or gas in paying quantities.

Sec. 3106.33 What minimum royalty must I pay on Federal leases?

You must pay minimum royalty according to the following chart--

------------------------------------------------------------------------
Type of lease Minimum royalty
------------------------------------------------------------------------
(a) Leases issued on or after August 8, 1946 $1 per acre or fraction
(excluding leases issued from offers filed of an acre in lieu of
after December 22, 1987). rental.
(b) Leases issued before August 8, 1946, if $1 per acre or fraction
the lessee files an election under Section of an acre in lieu of
15 of the Act of August 8, 1946. rental.
(c) Leases issued from offers filed after Not less than the amount
December 22, 1987. of rental required for
the lease.
(d) Reinstated lease......................... The minimum royalty
indicated in paragraphs
(a), (b), or (c),
depending on when the
lease was issued.
------------------------------------------------------------------------

Sec. 3106.34 How does BLM determine royalty and minimum royalty if the
United States owns less than a 100 percent mineral interest?

The royalty and minimum royalty is based on net acreage. Net
acreage is determined as follows: Net acreage = number of acres in the
lease x the percent of U.S. mineral interest.

Sec. 3106.35 How do I pay royalty and rental if my lease is committed
to a unit agreement?

(a) If your lease is committed to a unit agreement, you must pay
royalty on any production from or attributable to your lease based on
the royalty terms of your lease.
(b) You must pay rental for leased lands outside the participating
area, unless there is a non-unit well subject to royalty or minimum
royalty.

Waiver/Suspension/Reduction of Rental/Royalty/Minimum Royalty

Sec. 3106.40 Will BLM waive, suspend, or reduce the rental, royalty,
or minimum royalty if I cannot successfully operate my lease?

You may ask BLM to waive, suspend, or reduce your rental, royalty,
or minimum royalty requirements if it is necessary to promote
development. Your application must describe the relief you are
requesting and include--
(a) The lease serial number;
(b) The names of the operating rights owners for each lease;
(c) The names of the operators for each lease;
(d) A description of the relief you are requesting;
(e) The number, location, and status of each well drilled;
(f) A statement that shows the aggregate amount of oil or gas
subject to royalty for each month covering a period of at least six
months immediately before the date you filed the application;
(g) The number of wells counted as producing each month and the
average production per well per day;
(h) A detailed statement of expenses and costs of operating the
entire lease;
(i) The income from the sale of any production;
(j) All facts tending to show whether the wells can be successfully
operated under the lease royalty or rental; and
(k) The percentage of production dedicated to paying outstanding
overriding royalty and payments out of production or similar interests.
To receive a royalty reduction, you must reduce royalties or similar
payments from your lease to an aggregate not greater than one-half the
royalties due the United States.

Royalty on Oil: Sliding-Scale and Step-Scale Leases

Sec. 3106.50 How do I determine my royalty rate on oil I produce from
a lease with a sliding-scale or step-scale royalty rate?

(a) Calculate your average daily oil production per well for your
Federal lease, communitization or unit agreement, or unit participating
area during the production month in accordance with Secs. 3106.51
through 3106.54. The production rate you calculate for an agreement or
participating area must be used for the Federal lease(s) to which you
allocate production.
(b) Refer to the lease royalty schedule attached to your lease to
find the oil royalty rate that corresponds to the average daily oil
production you calculated. This royalty rate becomes the royalty rate
you must pay on oil you produced from or that was allocated to your
lease for the month.

Sec. 3106.51 How do I calculate average daily oil production per well
for my sliding-scale or step-scale lease?

Calculate the average daily oil production per well by dividing the
gross oil production from all wells you produce on your lease,
communitization or unit agreement in a calendar month by the total
well-days for eligible wells on your lease, communitization or unit
agreement as reported on Form MMS-3160.

[[Page 66890]]

Sec. 3106.52 What wells do I include in the calculation of average
daily oil production in determining the royalty rate?

(a) To calculate average daily oil production, the wells must be--
(1) Paying oil wells;
(2) Injection wells that you use to recover oil; or
(3) Paying gas wells that produce oil.
(b) All wells you use must be--
(1) Integral to production during the month; and
(2) Operated and produced as a result of routine business on your
property for that month.

Sec. 3106.53 What is a well-day?

A well-day is any day or part of a day you use a well to produce
oil or for injection purposes to recover oil.

Sec. 3106.54 What royalty rate must I pay on oil I carry in inventory
when I sell it?

When you sell oil that was placed in inventory, you must use the
royalty rate that was determined for the month in which the oil was
produced. You must use a first-in-first-out approach to determine what
royalty rate you apply to oil you sell from inventory.

Stripper Oil Property Royalty Reduction

Sec. 3106.60 What is a stripper oil property?

(a) A stripper oil property is any Federal lease or agreement that
produces an average of less than 15 barrels of oil per eligible well,
per well-day, for the qualifying period, determined in accordance with
Secs. 3106.61 through 3106.64.
(b) To determine if you have a stripper oil property, you must
consider only wells that you operate on the property. If there are
other operators producing wells on the same lease or agreement as you,
they must make a separate stripper oil property determination based on
the wells they operate.

Sec. 3106.61 What is an eligible well?

(a) An eligible well is--
(1) A producing oil well;
(2) An injection well that injects a fluid, including gas, for
secondary or enhanced oil recovery, including reservoir pressure
maintenance operations; or
(3) A gas well that produces oil and less than an average of 60 Mcf
of gas per day during the qualifying period under Sec. 3106.62.
(b) All eligible wells must be operated and produced as a result of
routine business for that period and for your property. You must not
manipulate production to obtain a royalty reduction.

Sec. 3106.62 What is the qualifying period?

(a) The initial qualifying period was from August 1, 1990 through
July 31, 1991.
(b) The current qualifying period is the first consecutive 12-month
period in which your property qualifies as a stripper oil property.
(c) If all wells on your property were shut-in for 12 consecutive
months or longer, the qualifying period is the 12-month production
period immediately before the shut-in.

Sec. 3106.63 What is considered oil for determining whether or not I
have a stripper oil property?

(a) For purposes of determining if you have a stripper oil property
you must include only--
(1) Hydrocarbon liquids you produce with an API gravity of 45 deg.
or lower, regardless of the color of the liquid; and
(2) Hydrocarbon liquids you produce with an API gravity more than
45 deg. but less than 50 deg. which are not light, neutral, or straw
colored in appearance, unless BLM determines the liquids to be produced
from an oil reservoir.
(b) All other hydrocarbon liquids you produce that do not meet the
characteristics described in paragraph (a) of this section are
condensate and must not be used to determine average daily oil
production.

Sec. 3106.64 How do I calculate the average daily production rate for
my property?

(a) Divide the total oil you produced from eligible wells for the
12-month qualifying period as reported on Form MMS-3160 or MMS-4054 by
the total number of well days determined under Sec. 3106.53 for those
eligible wells for the same 12-month period;
(b) Round the result down to the nearest whole number (e.g., 6.7
becomes 6);
(c) If the production rate you calculate is less than 15 barrels
per day, the 12-month period you used for the calculation in paragraph
(a) of this section is a qualifying period and your Federal lease is
eligible for a reduced royalty rate; and
(d) If your stripper oil property is in a Federal agreement, the
average daily production rate you determine for the agreement is then
used to determine the stripper royalty rate for the Federal lease(s) to
which you allocate oil production.

Sec. 3106.65 What will be my royalty rate if my property qualifies as
a stripper oil property?

(a) A reduced royalty rate will not relieve you of your obligation
to meet the minimum royalty requirements of your lease.
(b) Once you have determined your average daily production rate for
your property, use this table to determine your royalty rate--

------------------------------------------------------------------------
Reduced
royalty
Average barrels per day rate
(percent)
------------------------------------------------------------------------
0......................................................... 0.5
1......................................................... 1.3
2......................................................... 2.1
3......................................................... 2.9
4......................................................... 3.7
5......................................................... 4.5
6......................................................... 5.3
7......................................................... 6.1
8......................................................... 6.9
9......................................................... 7.7
10......................................................... 8.5
11......................................................... 9.3
12......................................................... 10.1
13......................................................... 10.9
14......................................................... 11.7
------------------------------------------------------------------------

Sec. 3106.66 How do I apply for a stripper royalty rate?

To apply for a stripper royalty rate--
(a) Submit Form MMS-4377 to MMS for verification.
(b) When you submit Form MMS-4377 to MMS, you certify that you--
(1) Did not manipulate your production rate for the qualifying and
later 12-month periods to obtain the royalty rate reduction; and
(2) Calculated the royalty rate using the instructions and
procedures in the regulations in this part.

Sec. 3106.67 When may I start using the stripper royalty rate for my
lease and how long will it be in effect?

(a) You may begin using the reduced royalty rate for your lease on
the first day of the month after MMS receives your Form MMS-4377.
(b) The reduced royalty rate that you calculate for your initial
qualifying period will be the maximum rate for your lease as long as
the stripper oil property program is in effect.

Sec. 3106.68 Does the stripper royalty rate apply to condensate, gas
or gas plant products?

The stripper royalty rate applies only to oil produced on your
property.

Sec. 3106.69 How do I determine my royalty rate if my production
varies?

(a) Your stripper royalty rate may vary as your production varies,
but it will never go above your initial qualifying rate for the life of
the stripper oil property program.
(b) At the end of each 12-month period, you must calculate a new
daily production rate using the methods prescribed in Sec. 3106.64 and
the oil production and well days from eligible wells for the claim year
you have just

[[Page 66891]]

completed to determine if your property is eligible for a royalty rate
lower than your initial qualifying rate.

Sec. 3106.70 How do I apply for a lower royalty rate?

(a) To apply for a lower stripper royalty rate, before the end of
each claim year, submit Form MMS-4377 to notify MMS of your lower
royalty rate. Use Secs. 3106.61 through 3106.65 to determine your new
royalty rate based on the production data from the last claim year.
(b) Your lower royalty rate will be effective for one year starting
with production on the first day of the month after the month in which
MMS receives your notice.
(c) If you do not submit a completed Form MMS-4377 to MMS within 60
calendar days after the end of the last claim year, the royalty rate
for your property will revert back to the initial qualifying period
royalty rate.
(d) Even if you determine that your royalty rate for the next claim
year did not change from the previous claim year, you must notify MMS
using Form MMS-4377 that your royalty rate is unchanged; otherwise your
royalty rate will revert back to the initial qualifying period rate.

Sec. 3106.71 What happens to my royalty rate if I commit my lease to a
Federal agreement after I qualify for a reduced royalty on a lease
basis?

If your lease qualified for a reduced stripper royalty rate, and
after qualifying you commit your lease to an agreement--
(a) The royalty rate for production from or allocable to your lease
under the agreement will not exceed the stripper royalty rate from your
qualifying period as long as at least one of the wells on which the
lease rate was calculated moves to the agreement;
(b) You must submit Form MMS-4377 under this section to continue to
receive the reduced stripper royalty rate for your lease committed to
the agreement; and (c) For periods beginning after the date you commit
your lease to the agreement, unless the agreement qualifies as a
stripper oil property under Secs. 3106.60 through 3106.71, you will not
be allowed to calculate a reduced royalty rate for production from or
allocable to your lease under the agreement. However, as provided in
paragraph (a) of this section, the royalty rate for your lease will not
exceed the stripper royalty rate from your qualifying period. Any
further reduction in the royalty rate for your lease under the
agreement will be due to the agreement qualifying for a lower rate at
the agreement level.

Sec. 3106.72 What if I make an error when I calculate the stripper
royalty rate for my lease?

If you make an error calculating your stripper royalty rate, MMS
will calculate the correct rate for your lease and inform you of the
change. Any additional royalties due are payable immediately. Late
payment or underpayment charges will be assessed in accordance with 30
CFR 218.102.

Sec. 3106.73 What happens if I manipulate production to get a stripper
royalty rate?

(a) If BLM determines that you manipulated production to obtain a
stripper royalty rate, BLM will terminate your royalty rate reduction
retroactively to its effective date. You may also be subject to civil
or criminal penalties.
(b) You must pay the difference in royalty between the manipulated
rate and the unmanipulated rate as well as any interest and
underpayment charges.

Sec. 3106.74 How long will the stripper oil property program be in
effect?

(a) BLM may terminate your reduced royalty rate if--
(1) The posted price for West Texas Intermediate crude (WTI),
adjusted for inflation by BLM and MMS, remains on average above $28 per
barrel for six consecutive months; or
(2) The Secretary determines that royalty reductions under this
program should terminate.
(b) BLM must give you six months notice of the termination of the
program by publishing a notice in the Federal Register.

Heavy Oil Property Royalty Reduction

Sec. 3106.80 What is a heavy oil property?

A heavy oil property is any Federal lease or agreement that
produces crude oil with a weighted average gravity of less than 20
degrees as measured on the American Petroleum Institute (API) scale.

Sec. 3106.81 What wells can I include when I calculate a weighted
average gravity?

You can include a well that you operate if--
(a) The energy equivalent of the oil produced exceeds the energy
equivalent of the gas produced (including entrained liquefiable
hydrocarbons); or
(b) It produces oil and less than 60 Mcf of gas per day.

Sec. 3106.82 How do I calculate a weighted average gravity for a
property?

(a) Calculate the weighted average gravity for a property by
averaging (adjusted to rate of production) the API gravities reported
on your Purchaser's Statement (sales receipts).
(b) Use Purchaser's Statements for the last three calendar months
before you intend to notify BLM that you want a royalty rate reduction,
during each of which you had at least one sale. For example, if you
make a request for a royalty reduction in October 1996 and your
property--
(1) Had oil sales every month, you must use Purchaser's Statements
for July, August, and September 1996;
(2) Had oil sales only once every six months in the months of March
and September, you must use Purchaser's Statements for September 1995,
and March and September 1996; or (3) Had multiple sales each month, you
must use Purchaser's Statements for every sale during July, August, and
September 1996.
(c) You must use the following equation to calculate the weighted
average gravity for your property:
[GRAPHIC] [TIFF OMITTED] TP03DE98.000

Where:

V1 = Average Production (bbls) of Well #1 over the last
three calendar months of sales
V2 = Average Production (bbls) of Well #2 over the last
three calendar months of sales
Vn = Average Production (bbls) of each additional well
(V3, V4, etc.) over the last three calendar
months of sales
G1 = Average Gravity (degrees) of oil produced from Well #1
over the last three calendar months of sales
G2 = Average Gravity (degrees) of oil produced from Well #2
over the last three calendar months of sales
Gn = Average Gravity (degrees) of each additional well
(G3, G4, etc.) over the last three calendar
months of sales

[[Page 66892]]

Sec. 3106.83 What will be my royalty rate if my property qualifies as
a heavy oil property?

Use your weighted average gravity for your property, rounded down
to the nearest whole degree (e.g., 11.7 deg. API becomes 11 deg. API)
and use the following table to determine your royalty rate--

------------------------------------------------------------------------
Royalty
Weighted average gravity (degrees API) Rate
(percent)
------------------------------------------------------------------------
6......................................................... 0.5
7......................................................... 1.4
8......................................................... 2.2
9......................................................... 3.1
10......................................................... 3.9
11......................................................... 4.8
12......................................................... 5.6
13......................................................... 6.5
14......................................................... 7.4
15......................................................... 8.2
16......................................................... 9.1
17......................................................... 9.9
18......................................................... 10.8
19......................................................... 11.6
20......................................................... 12.5
------------------------------------------------------------------------

Sec. 3106.84 How do I apply to make a heavy oil reduced royalty rate
effective on my Federal lease?

You must notify BLM in writing that you want a heavy oil royalty
rate reduction and provide--
(a) The BLM case number of the Federal lease for which you want a
reduced rate;
(b) The BLM case number of any communitization or unit agreement
that allocates production to the lease;
(c) Names of all operators on the lease;
(d) The reduced royalty rate that you have determined for your
lease; and
(e) Copies of the Purchaser's Statements that document your
calculations of weighted average gravity.

Sec. 3106.85 When will the initial heavy oil reduced royalty rate be
in effect on my Federal lease?

The heavy oil reduced royalty rate will be in effect on the first
day of the second month after you notify BLM as required in
Sec. 3106.84.

Sec. 3106.86 How long will the initial heavy oil reduced royalty rate
be in effect on my Federal lease?

(a) The reduced royalty rate will apply to all oil you produce from
your lease for the next 12 months after the reduced rate becomes
effective.
(b) The reduced royalty rate will also apply for two months
following the end of the initial 12-month period while you determine
what your royalty rate will be for the next period under Sec. 3106.87.

Sec. 3106.87 How do I determine my royalty rate after the initial
reduced royalty rate period expires?

(a) Within two months after the end of the initial 12-month period,
you must--
(1) Calculate the weighted average oil gravity for your property
for that initial 12-month period just concluded, using the formula in
Sec. 3106.82;
(2) Determine your royalty rate from the table in Sec. 3106.83; and
(3) Notify BLM in writing, providing the information required in
Sec. 3106.84.
(b) If you do not notify BLM as required in paragraph (a) of this
section within two months after the end of any 12-month period for
which you received a reduced royalty rate, the royalty rate will return
to the rate in the terms of your Federal lease.

Sec. 3106.88 When will subsequent royalty rate reductions become
effective on my Federal lease?

Any heavy oil royalty rate reductions after the initial 12-month
period will become effective for oil you produce in the third month
after the prior 12-month royalty reduction period ends. For example: On
September 30, 1997, at the end of a 12-month royalty reduction period,
you determine the weighted average API oil gravity for your property
for that period just ended. You then determine your new heavy oil
royalty rate by using the table in this section and notify BLM within
two months. The new royalty rate would be effective December 1, 1997
through January 31, 1999. Between December 1, 1998 and January 31,
1999, you would calculate the next royalty rate based on production
from December 1, 1997 through November 30, 1998, that would be
effective February 1, 1999 through March 31, 2000.

Sec. 3106.89 What provisions apply when I begin paying royalty at a
reduced rate?

(a) The reduced royalty rate applies only to oil that is produced
from or which is allocated to your Federal lease.
(b) You may not intentionally manipulate the API gravity to obtain
a reduced royalty rate.
(c) You continue to be subject to the minimum royalty provisions of
your lease.
(d) You may be eligible for both a stripper royalty rate reduction
and a heavy oil royalty rate reduction. If you are eligible for both
the stripper royalty rate reduction and the heavy oil royalty rate
reduction, use the lower of the two royalty rates.

Sec. 3106.90 What happens if I make a mistake when I calculate the
reduced heavy oil royalty rate for my lease?

If you made an error calculating the heavy oil royalty rate, BLM
will determine the correct rate for your lease and notify you in
writing of the change. You must adjust your royalty reports and
payments to MMS accordingly.

Sec. 3106.91 What happens if I manipulate production from my heavy oil
property in order to get a reduced royalty rate?

(a) If BLM determines that you manipulated production to obtain a
heavy oil royalty rate reduction, BLM will terminate your royalty rate
reduction retroactively to its effective date. You may also be subject
to civil or criminal penalties.
(b) You must pay the difference in royalty between the manipulated
rate and the unmanipulated rate as well as any interest and
underpayment charges.

Sec. 3106.92 How long will the heavy oil property royalty reduction
program be in effect?

(a) BLM may suspend or terminate your heavy oil property royalty
reductions if--
(1) The average oil price has remained above $24 per barrel over a
period of six consecutive months (based on the WTI Crude average posted
prices and adjusted for inflation using the implicit price deflator for
gross national product with 1991 as the base year); or
(2) After September 10, 1999, the Secretary determines that the
heavy oil royalty reductions are not reducing the loss of otherwise
recoverable reserves, the Secretary may terminate heavy oil royalty
reductions granted under the program.
(b) BLM must give you six months notice of the termination of the
program by publishing a notice in the Federal Register.

Subpart 3107--Lease, Surety and Personal Bonds

General Information

Sec. 3107.10 Who may file an oil and gas lease bond?

Either the record title owner, operating rights owner or operator
may file a bond. The bond must guarantee the compliance of all record
title owners, operating rights owners and operators for the lease.

Sec. 3107.11 Who must a bond cover?

The bond must cover all record title owners (lessees), operating
rights owners and operators and anyone who conducts operations on your
lease, unless any one of those persons provides its own bond.

[[Page 66893]]

Sec. 3107.12 When must I file a bond?

BLM must have a bond, under this subpart, before it will approve--
(a) An Application for Permit to Drill;
(b) Surface disturbing activities; or
(c) A transfer of record title or operating rights on a lease which
has outstanding obligations, including reclamation.

Sec. 3107.13 What must my bond cover?

Your bond must guarantee performance and compliance with the lease
terms and cover all liabilities arising from or related to drilling
operations on a Federal lease including the following obligations--
(a) Complete and timely plugging of well(s);
(b) Reclamation of the lease area;
(c) Restoration of any lands or surface waters adversely affected
by lease development;
(d) Payments owed to the United States Government such as
royalties, rentals, civil penalties, fines and assessments;
(e) Compensatory royalties assessed to compensate for drainage; and
(f) Other requirements related to operations and compliance with
all lease terms and conditions, regulations, orders and notices to
lessees.

Sec. 3107.14 What are the dollar amounts for bonds?

(a) Bonds covering a single lease must be $20,000;
(b) Bonds covering all of your leases in one State must be $75,000;
(c) Bonds covering all of your leases in all States must be
$150,000; and
(d) BLM may adjust the bond amounts in paragraphs (a) through (c)
under Sec. 3107.50.

Sec. 3107.15 What kinds of bonds will BLM accept?

BLM will accept--
(a) Surety bonds, provided that the surety company is approved by
the Department of Treasury (See Department of the Treasury Circular No.
570); and
(b) Personal bonds, which are pledges of cashier's checks,
certified checks, certificates of deposit, irrevocable letters of
credit, or negotiable Treasury securities.

Sec. 3107.16 Will BLM accept cash for personal bonds?

BLM will not accept cash for personal bonds.

Sec. 3107.17 Is there a special bond form I must use?

You must use a current bond form (Form 3000-4 or 3000-4a) approved
by BLM's Director.

Sec. 3107.18 Is there any other documentation that I must file with a
surety bond?

You must include a power of attorney or other proof of an agent's
authority to sign on behalf of the surety. BLM will accept copies of
powers of attorney.

Sec. 3107.19 Where must I file my bond?

(a) File a signed original of the bond instrument in the BLM State
Office with jurisdiction over your lease or operations. BLM will not
accept copies.
(b) File your nationwide bond in any BLM State Office.

Sec. 3107.20 How do I modify the terms and conditions of my bond?

(a) Modify the terms and conditions of your bond or adjust the bond
amount by filing a rider with BLM. No special form is required;
(b) If your bond is a surety bond, any rider must also be signed by
your surety's agent and filed with a power of attorney for that agent;
and
(c) You must file bond riders for BLM approval in the BLM State
Office where your bond is located.

Certificates of Deposit, Letters of Credit and Negotiable Treasury
Securities

Sec. 3107.30 What may I use to back my personal bond?

BLM accepts negotiable treasury securities, certificates of deposit
and irrevocable letters of credit issued by Federally-insured financial
institutions authorized to do business in the United States to back a
personal bond.

Sec. 3107.31 Are there special terms that must be included in a
certificate of deposit to use it to back my bond?

If you use a certificate of deposit to back your bond, it must
indicate on its face that Secretarial approval is required prior to
redemption by any party.

Sec. 3107.32 Are there special terms that must be included in an
irrevocable letter of credit to use it to back my bond?

Your irrevocable letter of credit (LOC) used to back a bond must
include a clause that grants the Secretary authority to demand
immediate payment if you default or fail to replace the LOC within 30
calendar days from its expiration date. The LOC must be--
(a) Payable to the Department of the Interior, BLM;
(b) Irrevocable during its term and have an initial expiration date
of not less than one year following the date BLM receives it; and
(c) Automatically renewable for a period of not less than one year,
unless the issuing financial institution provides BLM with written
notice at least 90 calendar days before the letter of credit's
expiration date that it will not be renewed.

Sec. 3107.33 What special requirements are there for negotiable
treasury securities?

(a) Negotiable treasury securities used to back a bond must--
(1) Have a market value equal to the bond amount; and
(2) Be accompanied by a statement granting full authority to the
Secretary to sell such securities in case of a default of the terms of
the lease.
(b) You must monitor their value and provide additional security if
their market value falls below the required bond amount.

Bonding and Lease Transfers or Operations

Sec. 3107.40 What are BLM's bonding requirements when a lease interest
is transferred to another party?

(a) If the existing operator is providing the bond and there will
be no change in operator, BLM will not require the transferee of a
lease interest to file a bond. BLM may require a statement confirming
there will be no change in operator.
(b) If lease interests are transferred and there will be a change
in operator, the new operator must provide a bond or furnish evidence
that the new lessee will cover the operator with a bond.

Bond Adjustments

Sec. 3107.50 May BLM adjust my bond amount?

(a) BLM may increase your bond amount.
(b) BLM may decrease your bond amount if it determines that your
obligations under your bond are less than the existing bond amount.

Sec. 3107.51 What factors will BLM use to determine whether my bond
will be adjusted?

Factors BLM uses to determine your bond amount include, but are not
limited to, your--
(a) Record of previous violations;
(b) Uncollected royalties; and
(c) Plugging and reclamation costs.

Sec. 3107.52 When will BLM increase my bond amount?

BLM will increase your bond amount if--
(a) You file an Application for Permit to Drill and within the five
previous years BLM has made a claim against your bond because you
failed to properly plug a well or completely reclaim any areas of
surface associated with lease operations;
(b) You have a well classified as inactive under Sec. 3107.55; or

[[Page 66894]]

Sec. 3107.53 When will BLM decrease my bond amount?

BLM will decrease your bond amount if--
(a) You apply to BLM and request a decrease in bond amount; and
(b) BLM approves your application.

Sec. 3107.54 To what amount may BLM adjust my bond?

BLM may adjust your bond to an amount that does not exceed the
total of--
(a) Estimated costs to have BLM plug and reclaim all wells and
areas of surface use associated with lease operations;
(b) Uncollected royalties due; and
(c) Outstanding monies due from previous violations.

Sec. 3107.55 What is an inactive well?

For the purposes of Secs. 3107.52 and 3107.56 only, an inactive
well is any well that for the last 12 months has not--
(a) Produced oil or gas;
(b) Been actively used as a service or water source well; or
(c) Been actively drilled or reworked.

Sec. 3107.56 What additional security must I provide for an inactive
well?

Within 30 calendar days after your well becomes inactive you must--
(a) Submit to BLM additional bonding, either as a rider to your
existing BLM bond or as a separate bond, in an amount equal to $2.00
per foot of total depth or plugged-back total depth of your inactive
well. Each inactive well you maintain is subject to a bond increase
unless you demonstrate to BLM that your existing bond exceeds the
maximum bond amount under Sec. 3107.51;
(b) Submit to BLM a $100 nonrefundable payment for each inactive
well. You must submit the $100 payment for each 12-consecutive month
period that your well remains inactive. This option is available to you
only for the first six years your well is inactive. After six years of
inactive status, you must file the additional bonding set out in
paragraph (a) of this section, in lieu of this payment; or
(c) Comply with the requirements of Sec. 3145.23.

Bond Collection After you Default

Sec. 3107.60 Under what circumstances will BLM demand performance or
payment under my bond?

BLM will demand performance or payment under your bond for
noncompliance with the lease terms, governing regulations or BLM orders
including--
(a) Well plugging and abandonment;
(b) Reclamation of the lease area;
(c) Royalty payments and related interest or penalties that have
accrued;
(d) Assessed royalties to compensate for drainage; or
(e) Payment of penalties or assessments for violations.

Sec. 3107.61 As the principal on the bond, may BLM require me to
restore the face amount of my bond or require me to replace my bond
after BLM makes demand against it?

After the bond is reduced by the amount required to remedy
noncompliance, you must either--
(a) Post a new bond of equal value to the original bond within 60
calendar days after BLM notified you that the bond is deficient; or
(b) Restore the existing bond(s) to the amount previously held
within 60 calendar days after BLM notifies you that the bond is
deficient.

Sec. 3107.62 What if I do not restore the face amount or file a new
bond within 60 calendar days after BLM notifies me?

If you do not restore the face amount of the bond on file, or file
a new bond after BLM notifies you that your bond is deficient--
(a) BLM will require you to shut down operations; or
(b) Your leases covered by the bond are subject to cancellation
under subpart 3144.

Bond Cancellation

Sec. 3107.70 After I fulfill all of the lease terms and conditions,
will BLM cancel my bond?

BLM will cancel your bond after you have--
(a) Fulfilled all of the lease terms and conditions;
(b) Completed all plugging and reclamation requirements of subpart
3159 for the wells covered by your bond; and
(c) Paid all outstanding rents, royalties, interest, assessments,
or penalties due to noncompliance.

Sec. 3107.71 Will BLM cancel my bond if I transferred all of my lease
interests or operations to another bonded party?

BLM will cancel your bond following approval of the transfer of
your lease interests or a change of operator if that party provides a
bond that assumes all of your existing liabilities.

Sec. 3107.72 When will BLM release the collateral backing my personal
bond?

BLM will release the collateral backing your personal bond when we
cancel it.

Subpart 3108--Geophysical Exploration Bond Requirements

Geophysical Exploration Bonds

Sec. 3108.10 Must I file a bond before starting an exploration
project?

You must file a bond with the BLM State office with jurisdiction
over the lands before each planned exploration project.

Sec. 3108.11 What are the dollar amounts for geophysical bonds?

Bonds covering--
(a) A single exploration operation must be $5,000.
(b) Your exploration operations in one State must be $25,000;
(c) Your exploration operations in all States must be $50,000; and
(d) BLM may adjust the bond amounts under Sec. 3108.14.

Sec. 3108.12 Is there a special bond form I must use?

You must use a current bond form approved by BLM's Director for
either a surety bond or a personal bond.

Sec. 3108.13 May I use an oil and gas lease bond to cover exploration
operations?

(a) If you hold an individual, statewide or nationwide oil and gas
lease bond, you may conduct exploration on leases in which you hold an
interest without further bonding.
(b) If you hold a statewide or nationwide bond and intend to
conduct exploration on lands that you do not have under lease, you must
obtain a rider, subject to BLM approval, to include such oil and gas
exploration operations under the bond.

Sec. 3108.14 Will BLM increase my bond amount?

BLM may increase your bond amount if it determines that additional
coverage is necessary to protect the lands or resources.

Sec. 3108.15 When will BLM cancel my geophysical bond?

If you request it, BLM will cancel your bond after you--
(a) Satisfy the terms and conditions of your notice(s) of intent or
permit(s) to conduct geophysical exploration operations; and
(b) Complete any additional reclamation BLM or the surface
management agency requires after you file a notice of completion.

[[Page 66895]]

Sec. 3108.16 What will happen if I do not complete additional
reclamation that BLM requests?

If you do not complete reclamation, BLM will--
(a) Demand performance or payment under your bond to cover the
costs of reclamation; and
(b) Initiate judicial action to compel performance or to recover
the costs of reclamation.
2. Revise part 3110--Noncompetitive Leases to read as follows:

PART 3110--OIL AND GAS GEOPHYSICAL EXPLORATION

Subpart 3110--Onshore Oil and Gas Geophysical Exploration

General Provisions

Sec.
3110.10 When must I have BLM authorization to conduct geophysical
exploration operations?
3110.11 When would the requirements of this subpart not apply to my
activities?
3110.12 When may BLM suspend or cancel my right to conduct
geophysical exploration?
3110.13 What is the fee to use BLM lands to conduct geophysical
exploration operations?

Subpart 3112--Geophysical Exploration Outside of Alaska

Notice of Intent

3112.10 What must I file to conduct oil and gas geophysical
exploration operations?
3112.11 When must I file my NOI and what action will BLM take?
3112.12 May BLM require that I participate in a field review as a
part of the filing process?

Notice of Completion

3112.20 When must I file a notice of completion of operations?
3112.21 What action will BLM take on my notice of completion?

Subpart 3113--Geophysical Exploration In Alaska (Outside the Arctic
National Wildlife Refuge)

Exploration Permit Application

3113.10 How do I apply for an oil and gas geophysical exploration
permit?
3113.11 What action will BLM take on my permit application?
3113.12 What terms and conditions will BLM include in my permit?

Exploration Permit

3113.20 When is my exploration permit effective and what is its
duration?
3113.21 May I relinquish my exploration permit?
3113.22 When can my exploration permit be modified?

Data and Inforamtion Obligations

3113.30 Must I collect and submit all data which I obtain while
performing exploration operations under the permit?
3113.31 When may BLM disclose such data?

Completion Report

3113.40 What does BLM require after I complete operations under my
exploration permit?
3113.50 What if my exploration operation is on unleased lands
managed by the Department of Defense (DOD)?

Authority: 16 U.S.C. 3150(b) and 668dd; 30 U.S.C. 189 and 359;
42 U.S.C. 6508; and 43 U.S.C. 1201, 1732(b), 1733, 1734 and 1740.

Subpart 3110--Onshore Oil and Gas Geophysical Exploration

General Provisions

Sec. 3110.10 When must I have BLM authorization to conduct geophysical
exploration operations?

(a) You must obtain BLM authorization before you conduct
geophysical exploration--
(1) On public lands, if BLM manages the surface;
(2) On unleased public lands managed by another agency, if that
agency and BLM agree for BLM to process your application to conduct
geophysical exploration operations according to the regulations in this
part; and
(3) Under the rights granted by any Federal oil and gas lease,
unless the Forest Service manages the surface.
(b) If you conduct geophysical exploration outside of the rights
granted by a Federal oil and gas lease on lands where BLM does not
manage the surface, you may need authorization from the surface
management agency or surface owner.

Sec. 3110.11 When would the requirements of this subpart not apply to
my activities?

The requirements of this subpart do not apply to--
(a) Casual use activities. Gravity or magnetic surveys, the
placement of recording equipment, and activities that do not involve
vehicle operations that would cause significant compaction or rutting
are generally considered casual use; and
(b) Operations you conduct on private surface overlying Federal
minerals, unless you conduct operations under the rights granted by a
Federal oil and gas lease.

Sec. 3110.12 When may BLM suspend or cancel my right to conduct
geophysical exploration?

(a) If BLM determines that you have violated any of the terms or
conditions of your subpart 3112 Notice of Intent to conduct oil and gas
geophysical operations or of your exploration permit in Alaska under
subpart 3113, BLM may suspend or cancel your right to conduct
exploration. BLM will provide notice to you before it suspends or
cancels your right to conduct exploration.
(b) BLM may order an immediate temporary suspension of your
geophysical activities until a hearing or final administrative finding,
if it determines that a suspension is necessary to protect public
health and safety or the environment.

Sec. 3110.13 What is the fee to use BLM lands to conduct geophysical
exploration operations?

BLM will--
(a) Determine the fair market value fee (FMV) for your use of
public lands for each notice of intent or exploration permit, if BLM
manages the surface;
(b) Base the FMV on the size of the area physically affected; and
(c) Not charge a FMV for portions of your geophysical exploration
operation you are conducting on your Federal lease or on behalf of the
Federal lessee.

Subpart 3112--Geophysical Exploration Outside of Alaska

Notice of Intent

Sec. 3112.10 What must I file to conduct oil and gas geophysical
exploration operations?

Before you conduct oil and gas geophysical exploration, you must
submit a Notice of Intent (NOI) to Conduct Oil and Gas Geophysical
Exploration Operations, Form 3150-4, and provide BLM information to
determine a FMV according to Sec. 3110.13.

Sec. 3112.11 When must I file my NOI and what action will BLM take?

(a) You must file a NOI at least 14 business days before you plan
to start operations and BLM will review and process it according to--
(1) BLM land use planning decisions for geophysical exploration in
the area where you plan to conduct operations; or
(2) Your lease terms, if you conduct geophysical exploration under
the rights granted by your lease and the lease was issued before the
effective date of the applicable land use plan.
(b) BLM will give you a copy of the Terms and Conditions for Notice
of Intent to Conduct Geophysical Exploration, Form 3150-4a, and other
conditions which you must sign and follow to--
(1) Protect the public lands from unnecessary and undue
degradation; and

[[Page 66896]]

(2) Assure compliance with applicable laws for the protection of
the environment;
(c) BLM will notify you--
(1) If it cannot process your NOI and why; or
(2) Why processing will be delayed and when you can expect BLM to
complete processing.
(d) BLM will not authorize your NOI until you pay the required FMV.

Sec. 3112.12 May BLM require that I participate in a field review as a
part of the filing process?

BLM may require you to participate in a field review of your
proposal to conduct geophysical operations. The purpose of this review
is to complete development of the terms and conditions of your NOI.

Notice of Completion

Sec. 3112.20 When must I file a notice of completion of operations?

You must submit a Notice of Completion of Oil and Gas Exploration
Operations, Form 3150-5, to BLM 30 calendar days after completing
operations, including reclamation activities.

Sec. 3112.21 What action will BLM take on my notice of completion?

After you file Form 3150-5, BLM will notify you whether your
reclamation is satisfactory or whether you must perform additional
reclamation, specifying the nature and extent of further actions you
must take.

Subpart 3113--Geophysical Exploration In Alaska (Outside the Arctic
National Wildlife Refuge)

Exploration Permit Application

Sec. 3113.10 How do I apply for an oil and gas geophysical exploration
permit?

If you plan to conduct oil and gas geophysical exploration
operations in Alaska, you must--
(a) Complete an application for an oil and gas geophysical
exploration permit that fully describes and illustrates your plans for
conducting exploration operations;
(b) Provide evidence that you have bond coverage according to the
requirements of subpart 3108; and
(c) Provide BLM information to determine a FMV according to
Sec. 3110.13. BLM will not approve your permit until you pay the
required FMV.

Sec. 3113.11 What action will BLM take on my permit application?

(a) BLM will--
(1) Review your application and approve or disapprove it; or
(2) Notify you if processing will be delayed, why it will be
delayed, and when BLM will complete processing.
(b) BLM will only authorize exploration for lands subject to
section 1008 of the Alaska National Interest Lands Conservation Act (16
U.S.C. 3148), after it determines that you can conduct exploration
activities in a manner consistent with BLM's management of the affected
area.

Sec. 3113.12 What terms and conditions will BLM include in my permit?

BLM will include--
(a) Terms and conditions necessary to protect mineral and
nonmineral resources;
(b) Terms to insure that your operations are consistent with BLM's
management of the affected area, if your proposal occurs on lands
subject to section 1008 of the Alaska National Interest Lands
Conservation Act (16 U.S.C. 3148); and
(c) Reasonable conditions, restrictions and prohibitions, if you
plan to conduct geophysical operations within the National Petroleum
Reserve in Alaska, to--
(1) Mitigate adverse effects upon the surface resources of the
reserve; and
(2) Satisfy the requirement of section 104(b) of the Naval
Petroleum Reserves Production Act of 1976 (42 U.S.C. 6504).

Exploration Permit

Sec. 3113.20 When is my exploration permit effective and what is its
duration?

(a) An exploration permit is valid for one year after the effective
date specified by BLM; and
(b) BLM may renew your exploration permit for an additional year if
you submit a written request.

Sec. 3113.21 May I relinquish my exploration permit?

You may relinquish all or part of your exploration permit by filing
a request for relinquishment with BLM. BLM will approve the
relinquishment, provided you and your surety comply with the terms and
conditions of your exploration permit and the regulations in this part.

Sec. 3113.22 Can my exploration permit be modified?

(a) BLM may approve your proposal to modify your exploration
permit; and
(b) BLM may, after consulting with you, require you to modify your
exploration permit.

Data and Information Obligations

Sec. 3113.30 Must I collect and submit all data which I obtain while
performing exploration operations under the permit?

You must collect and submit to BLM all data which you obtain while
conducting exploration operations.

Sec. 3113.31 When may BLM disclose such data?

BLM will manage this data according to the Freedom of Information
Act and 43 CFR part 2.

Completion Report

Sec. 3113.40 What does BLM require after I complete operations under
my exploration permit?

Within 30 calendar days after completing all operations under the
permit you must submit a completion report that describes and
illustrates the work that you performed and any reclamation activity
completed or planned. BLM will review the completion report and notify
you of any additional measures which you must perform to correct damage
to the lands and resources.

Sec. 3113.50 What if my exploration operation is on unleased lands
managed by the Department of Defense (DOD)?

If the DOD refers your geophysical exploration permit application
to BLM for issuance--
(a) BLM will follow the provisions of subpart 3113 to process your
permit; and
(b) DOD must consent to BLM issuance of your permit and may impose
terms and conditions on your permit.
3. Revise part 3120--Competitive Leases to read as follows:

PART 3120--OIL AND GAS LEASING

Subpart 3120--Leasing (General)

Leasing: General

Sec.
3120.10 What public lands may BLM lease for oil and gas under this
subpart?
3120.11 What units of the National Park System are subject to oil
and gas leasing?
3120.12 May BLM lease minerals under the jurisdiction of an agency
outside of the Department of the Interior?

National Wildlife Refuge System Lands

3120.20 What are National Wildlife Refuge System lands?
3120.21 May BLM lease lands that are within the National Wildlife
Refuge System?

Coordination Lands

3120.30 What are coordination lands?
3120.31 May BLM lease coordination lands?
3120.32 May BLM lease lands within a wildlife refuge in Alaska?

[[Page 66897]]

3120.33 May BLM lease lands within Recreation and Public Purposes
leases or patents?
3120.34 May a lease contain both acquired and public domain
minerals?

Oil and Gas Lease Administration

3120.40 For Federal lands, what types of leases does BLM issue or
administer?
3120.41 For each type of lease, what is the primary lease term,
maximum lease size, administrative filing fee, and advance annual
rental rate?

Subpart 3121--Competitive Leasing

Notice of Competitive Lease Sale

3121.10 How does BLM provide notice of what lands are available for
competitive oil and gas leasing?
3121.11 What information will BLM include in the Notice of
Competitive Lease Sale?
3121.12 How does BLM decide which lands to include in a Notice of
Competitive Lease Sale?
3121.13 What types of lands may I include in my letter of
nomination?

Legal Descriptions

3121.20 How should I describe the lands in my letter of nomination?
3121.21 What other rules must I follow when I submit my nomination
letter?

Future Interest Leasing

3121.30 May I submit a nomination letter for mineral interests that
will vest in the United States in the future and how will BLM offer
them?

Subpart 3122--Competitive Lease Sale

General

3122.10 How often must each BLM State Office hold competitive lease
sales?
3122.11 How are competitive oil and gas lease sales conducted?
3122.12 Is there a minimum per-acre amount that I must bid on a
parcel?
3122.13 If the United States owns a fractional interest (less than
100 percent of the mineral interest in a parcel), is the minimum bid
per acre prorated?
3122.14 How does BLM determine the winning bid?
3122.15 What documents must I submit on the day of the sale if I am
the winning bidder of a parcel?
3122.16 May I withdraw my bid?
3122.17 What must I pay per parcel at the sale if I am the winning
bidder?
3122.18 If I am the winning bidder for a future interest lease,
what payments must I make on the day of the sale?

Balance of Bonus Bid

3122.20 When is the balance of my bonus bid due?
3122.21 What happens if BLM does not receive the balance of my
bonus bid within 10 business days following the date of the sale?

Rejection of Bid

3122.30 Under what circumstances will BLM reject my bid?
3122.31 Are parcels for which BLM rejected bids available for
noncompetitive leasing during the two years after the sale?

Parcels That Receive No Bid at Oral Auction

3122.40 If a parcel receives no bid at the competitive lease sale,
is it available for noncompetitive leasing?

Subpart 3123--Noncompetitive Leasing

Parcels Available for Noncompetitive Lease Offers

3123.10 What parcels are available for noncompetitive lease offers?
3123.11 When do parcels that received no bid at the competitive
sale become available for noncompetitive leasing?

Priority of Noncompetitive Lease Offers

3123.20 What if more than one noncompetitive offer is filed for the
same parcel?
3123.21 If my noncompetitive offer requires a correction, under
what circumstances does it retain priority?

Descriptions of Lands in Noncompetitive Lease Offers

3123.30 How do I describe the lands in my offer I file the day
after the competitive lease sale?
3123.31 How do I describe the lands in my noncompetitive offer for
public domain or acquired minerals that I file within the two years
after the sale?

Requirements of a Noncompetitive Lease Offer

3123.40 How do I file a noncompetitive offer?
3123.41 If I file a noncompetitive future interest offer, when must
I pay the first year's advance rental?
3123.42 What happens to my noncompetitive offer if an earlier
offeror is entitled to a lease, either as a result of priority of
the offer, or a pending lease reinstatement?
3123.43 May I amend my noncompetitive lease offer before BLM issues
the lease?
3123.44 May I withdraw my noncompetitive lease offer?

Subpart 3124--Lease Administration and Renewals

Dating of Leases

3124.10 What is the effective date of my lease?

Leases Within Unit Agreements

3124.20 What if the lands I am leasing are within an existing unit
agreement?
3124.21 What effect does the commitment to a unit have on my lease
offer or lease?

Lease Consolidation

3124.30 May I consolidate leases?
3124.31 What information must I include in my application for lease
consolidation?
3124.32 How many copies of my application must I file and where
must I file it?

Lease Renewals

3124.40 For how many years will BLM renew my lease?
3124.41 For how many years will BLM renew my lease if it wasn't
issued under Section 14 of the Mineral Leasing Act?
3124.42 If my lease is committed to a unit agreement may I file a
renewal lease application?
3124.43 Who may file a renewal lease application?
3124.44 How must I file my renewal lease application?

Subpart 3125--Exchange Leases

Exchange Leases

3125.10 May I exchange my existing oil and gas lease for a new
lease?
3125.11 How must I file an exchange lease application?

Subpart 3126--Railroad Right-of-Way Leases

Railroad Right-of-Way Leases

3126.10 To which rights of way does this subpart apply?
3126.11 Who may lease the oil or gas deposits underlying a railroad
right-of-way?
3126.12 How must I file a lease application under this subpart?
3126.13 What information must my application include?
3126.14 Who must BLM notify that I filed an application to lease
the oil and gas under the right-of-way?
3126.15 Who may submit a bid for compensation?
3126.16 What must I include in my bid for compensation?
3126.17 Who must BLM notify that I have filed an application for
compensation?
3126.18 May BLM request offers to lease or for compensation?
3126.19 Who will receive the rights to the oil and gas underlying
the right-of-way?
3126.20 What is the term of my lease or agreement?

Subpart 3129--Record Title, Operating Rights and Estate Transfers, Name
Changes and Mergers

General

3129.10 What is a transfer?
3129.11 When must I file a transfer with BLM?
3129.12 Who may receive a transfer of lease interests?
3129.13 What must I include in my transfer application?
3129.14 When is my transfer effective?
3129.15 May I withdraw my transfer?
3129.16 May I file a record title transfer limited to a specific
depth, formation, zone or defined deposit or fluid mineral?
3129.17 May I file my operating rights transfer to a specific
depth?
3129.18 How do transfers of interest affect future transfers?
3129.19 When will BLM segregate a lease as a result of a transfer?
3129.20 What is a mass transfer?
3129.21 May I file a mass transfer?
3129.22 Does BLM's approval of a transfer certify that title is
clear?

[[Page 66898]]

Forms, Fees and Filing Requirements

3129.30 What forms must I use to transfer lease interests, how many
copies must I file, what is the filing fee per lease or document,
and where must I file them?
3129.31 Are filing fees refundable?
3129.32 How do I describe the lands on Form 3000-3 for my record
title transfer?
3129.33 May I transfer less than a legal subdivision?
3129.34 May I file a record title transfer containing less than 640
acres?
3129.35 What must I submit to BLM to transfer the rights or
interests of a decedent to its heir, devisee or estate?
3129.36 What must I submit to BLM for a merger or name change?
3129.37 Where must I file documentation of estate, merger and name
changes?
3129.38 As the transferee, what should I file to show I am
qualified to hold Federal lease interests?
3129.39 When must I file transfers with BLM?
3129.40 May I transfer an interest before BLM issues the lease?

Bonding, Obligations and Liabilities

3129.50 When will BLM require a new bond for a transfer?
3129.51 If I transfer my lease, when do my obligations under the
lease end?
3129.52 If I acquire a lease by an assignment or transfer, what
obligations do I agree to assume?

Denial/Disapproval

3129.60 When will BLM deny or disapprove a transfer to me?
3129.61 Must I file assignments of rights to production with BLM?
3129.62 May I file a lien against a lease for monies owed me?
3129.63 Must I file transfers of overriding royalty interest, net
profit or production payments with BLM?

Authority: 16 U.S.C. 3150(b) and 668dd; 30 U.S.C. 189, 306 and
359; 43 U.S.C. 1733, 1734 and 1740; and 10 U.S.C.A. 7439.

Subpart 3120--Leasing (General)

Leasing: General

Sec. 3120.10 What public lands may BLM lease for oil and gas under
this subpart?

This subpart applies to public domain and acquired minerals subject
to leasing under the Mineral Leasing Act, as amended (30 U.S.C. 181 et
seq.) and the Mineral Leasing Act for Acquired Lands (30 U.S.C. 351 et
seq.). This subpart does not apply to leasing minerals in--
(a) National Parks and the following units of the National Park
System except as provided at Sec. 3120.11;
(b) National monuments;
(c) Incorporated cities, towns and villages;
(d) National Petroleum Reserve-Alaska and Naval petroleum and oil
shale reserves, except Naval Oil Shale Reserves 1 and 3;
(e) Lands recommended for wilderness allocation by the surface
management agency;
(f) Lands within BLM wilderness study areas;
(g) Lands designated by Congress as wilderness study areas, except
where oil and gas leasing is specifically allowed to continue by the
statute designating the study area;
(h) Lands within areas allocated for wilderness or further planning
in Executive Communication 1504, Ninety-Sixth Congress (House Document
numbered 96-119), unless the lands are allocated to uses other than
wilderness by a land and resource management plan or have been released
to uses other than wilderness by an Act of Congress;
(i) Lands within the National Wilderness Preservation System,
subject to valid existing rights under section 4(d)(3) of the
Wilderness Act established before midnight, December 31, 1983;
(j) Lands north of 68 degrees north latitude and east of the
western boundary of the National Petroleum Reserve-Alaska;
(k) Arctic National Wildlife Refuge in Alaska;
(l) Any other lands withdrawn from leasing;
(m) Tidelands or submerged coastal lands within the continental
shelf adjacent or littoral to lands within the jurisdiction of the
United States; and
(n) Lands acquired by the United States for development of helium,
fissionable material deposits or other minerals essential to the
defense of the country, except oil, gas, and other minerals subject to
leasing under the Act.

Sec. 3120.11 What units of the National Park System are subject to oil
and gas leasing?

(a) The Secretary may allow oil and gas leasing in units of the
National Park System listed in paragraph (b) of this section if leasing
those lands would not have significant adverse effects on the
administration of the area and if lease operations can be conducted in
a manner that will preserve the scenic, scientific and historic
features contributing to public enjoyment of the area;
(b) BLM may lease oil and gas in--
(1) Lake Mead National Recreation Area as portrayed on the map
identified as ``boundary map'' 8360-80013B, revised February 1986;
(2) Whiskeytown Unit of the Whiskeytown-Shasta-Trinity National
Recreation Area as portrayed on the map identified as ``Proposed
Whiskeytown-Shasta-Trinity National Recreation Area,'' numbered BOR-WST
1004, dated July 1963. BLM may lease lands within the recreation area
under the jurisdiction of the Secretary of Agriculture under the
Mineral Leasing Act of 1920, as amended, or the Acquired Lands Mineral
Leasing Act of 1947, if disposition would not have significant adverse
effects on the purpose of the Central Valley Project or the
administration of the recreation area;
(3) Glen Canyon National Recreation Areas as portrayed on the map
identified as ``boundary map, Glen Canyon National Recreation Area,''
numbered GLC-91,006, dated August 1972; and
(4) Any other units of the National Park Service where Congress
authorizes leasing;
(c) BLM may not lease oil and gas in the--
(1) Lake Mead National Recreation Area--
(i) All waters of Lakes Mead and Mohave and all lands within 300
feet of those lakes measured horizontally from the shoreline at maximum
surface elevation; and
(ii) All lands within the unit of supervision of the Bureau of
Reclamation around Hoover and Davis Dams and all lands outside of
resource utilization zones as designated by the Superintendent on the
map (602-2291B., dated October 1987) of Lake Mead National Recreation
Area which is available for inspection in the Office of the
Superintendent;
(2) Whiskeytown Unit of the Whiskeytown-Shasta-Trinity National
Recreation Area--
(i) All waters of the Whiskeytown Lake and all lands within 1 mile
of that lake measured from the shoreline at maximum surface elevation;
(ii) All lands classified as high density recreation, general
outdoor recreation, outstanding natural and historic, as shown on the
map numbered 611-20,004B, dated April 1979, entitled ``Land
Classification, Whiskeytown Unit, Whiskeytown-Shasta-Trinity National
Recreation Area.'' This map is available for public inspection in the
Office of the Superintendent; and
(iii) All lands within section 34 of Township 33 North, Range 7
West, Mt. Diablo Meridian; or
(3) Glen Canyon National Recreation Area--Those units closed to
mineral disposition within the natural zone, development zone, cultural
zone and portions of the recreation and resource utilization zone as
shown on the map numbered 80,022A, dated March 1980, entitled ``Mineral
Management Plan--Glen Canyon National Recreation Area.'' This map is
available for public

[[Page 66899]]

inspection in the Office of the Superintendent and the offices of the
State Directors, Bureau of Land Management, Arizona and Utah.

Sec. 3120.12 May BLM lease minerals under the jurisdiction of an
agency outside of the Department of the Interior?

If minerals are under the jurisdiction of an agency outside the
Department of the Interior, BLM may lease--
(a) Acquired lands only after BLM receives consent from the surface
management agency;
(b) Public domain lands only after BLM has consulted with the
surface management agency; and
(c) National Forest System lands and lands withdrawn for use by the
Department of Defense, whether acquired or public domain, only with the
written consent of the surface management agency.

National Wildlife Refuge System Lands

Sec. 3120.20 What are National Wildlife Refuge System lands?

National Wildlife Refuge System lands are those lands under the
jurisdiction of the United States Fish and Wildlife Service included
within a withdrawal of public domain and acquired lands for the
protection of all species of wildlife within a particular area.

Sec. 3120.21 May BLM lease lands that are within the National Wildlife
Refuge System?

BLM may lease National Wildlife Refuge System lands only--
(a) If it is necessary to protect those lands from drainage; or
(b) Where there are valid existing rights.

Coordination Lands

Sec. 3120.30 What are coordination lands?

Coordination lands are those lands withdrawn or acquired by the
United States and made available to the States by--
(a) Cooperative agreements entered into between the Fish and
Wildlife Service and the game commissions of the various States, in
accordance with the Act of March 10, 1934 (48 Stat. 401), as amended by
the Act of August 14, 1946 (60 Stat. 1080); or
(b) Long-term leases or agreements between the Department of
Agriculture and the game commissions of the various States pursuant to
the Bankhead-Jones Farm Tenant Act (50 Stat. 525), as amended, where
such lands were subsequently transferred to the Department of the
Interior, with the Fish and Wildlife Service as the custodial agency of
the United States.

Sec. 3120.31 May BLM lease coordination lands?

BLM may lease coordination lands (not closed to oil and gas
leasing) only after it has--
(a) Consulted with the applicable State Game Commission and the
Fish and Wildlife Service; and
(b) Obtained any lease stipulations necessary to protect the lands
proposed for lease.

Sec. 3120.32 May BLM lease lands within a wildlife refuge in Alaska?

Lands within a wildlife refuge in Alaska, except the Arctic
National Wildlife Refuge, are open to oil and gas leasing after the
Fish and Wildlife Service has completed a favorable compatibility
determination.

Sec. 3120.33 May BLM lease lands within Recreation and Public Purposes
leases or patents?

Recreation and Public Purposes Act leases and patents authorized
under 43 U.S.C. 869 et seq. are subject to oil and gas leasing under
the regulations in this part, subject to any conditions or stipulations
that the Secretary considers appropriate.

Sec. 3120.34 May a lease contain both acquired and public domain
minerals?

A lease may not contain both public domain and acquired minerals.

Oil and Gas Lease Administration

Sec. 3120.40 For Federal lands, what types of leases does BLM issue or
administer?

BLM issues or administers the following types of leases--
(a) Competitive;
(b) Noncompetitive;
(c) Future Interest (Competitive/Noncompetitive);
(d) Right-of-Way;
(e) Renewal;
(f) Exchange;
(g) Combined Hydrocarbon; and
(h) Private.

Sec. 3120.41 For each type of lease, what is the primary lease term,
maximum lease size, administrative filing fee, and advance annual
rental rate?

The following chart describes the terms for each type of lease BLM
issues--

----------------------------------------------------------------------------------------------------------------
Rental rate per acre
Type of lease Primary lease Maximum lease size Administrative or fraction of an
term filing fee acre
----------------------------------------------------------------------------------------------------------------
(a) Competitive............... 10 years......... 2,560 acres for lower $75 $1.50 for the first
48 States and 5,760 five years; $2.00
acres in Alaska. the sixth and
succeeding years.
(b) Noncompetitive............ 10 years......... 2,560 acres for lower 75 See Competitive.
48 States and 5,760
acres in Alaska.
(c) Future Interest........... 10 years......... 2,560 acres for lower 75 See Competitive.
48 States and 5,760
acres in Alaska.
(d) Right-of-Way Leasing...... 20 years......... N/A................... 75 See Competitive.
(e) Renewal Leases............ 20 years......... N/A................... 75 $2.
(f) Exchange Leases........... 5 years.......... N/A................... 75 $2.
(g) Combined Hydrocarbon 10 years......... 5,120 acres........... 75 $2.
Leases.
(h) Private Leases............ Subject to N/A................... None Subject to private
private lease lease terms.
terms.
----------------------------------------------------------------------------------------------------------------

Subpart 3121--Competitive Leasing

Notice of Competitive Lease Sale

Sec. 3121.10 How does BLM provide notice of what lands are available
for competitive oil and gas leasing?

BLM will--
(a) Post a Notice of Competitive Lease Sale in the public room of
the BLM State Office with jurisdiction over the lands available for
lease for a minimum of 45 calendar days before the sale date; and
(b) Make the notice available for posting at the offices of all
appropriate surface management agencies with jurisdiction over any of
the parcels included in the sale notice for at least 45 calendar days
before the sale date.

[[Page 66900]]

Sec. 3121.11 What information will BLM include in the Notice of
Competitive Lease Sale?

In the Notice of Competitive Lease Sale, BLM will include--
(a) The time, date, and place of the sale;
(b) A description of the lands available for sale;
(c) Stipulations or lease conditions that apply to each sale
parcel; and
(d) Any special requirements that apply to a parcel such as
communitization or unit agreement joinder requirements, or any
plugging, bonding, or surface reclamation requirements for existing
wells.

Sec. 3121.12 How does BLM decide which lands to include in a Notice of
Competitive Lease Sale?

BLM includes lands in a Notice of Competitive Lease Sale as a
result of a--
(a) Letter of nomination from the public;
(b) BLM recommendation; or
(c) Request from a surface management agency.

Sec. 3121.13 What types of lands may I include in my letter of
nomination?

You may include the following types of lands in your letter of
nomination for competitive leasing--
(a) Lands available for leasing under Sec. 3120.10, including--
(1) Lands in oil and gas leases that have terminated, expired, been
canceled or relinquished;
(2) Interests forfeited to the United States;
(3) Lands that have never been leased;
(b) Lands which are otherwise unavailable for leasing but are
subject to drainage (protective leasing); and
(c) Lands in gas storage agreements that also meet the requirements
of paragraph (a) or (b) of this section.

Legal Descriptions

Sec. 3121.20 How should I describe the lands in my letter of
nomination?

------------------------------------------------------------------------
If-- Then you must describe the lands--
------------------------------------------------------------------------
(a) The public lands have By township, range, meridian, section and
been surveyed under the legal subdivision.
public land rectangular
survey system or the
acquired lands lie within
and conform to the
rectangular system of public
land surveys and constitute
either all or a portion of
the tract acquired by the
United States.
(b) The public lands have not By metes and bounds, giving courses and
been surveyed under the distances between the successive angle
public land rectangular points on the boundary of the tract, and
survey system or the connected by courses and distances
acquired lands do not connected to an official corner of the
conform to the rectangular public land surveys, or furnish a copy
system of public land of the deed or other conveyance document
surveys, but lie within an by which the United States acquired
area of the public land title to the lands.
surveys and constitute the
entire tract acquired by the
United States.
(c) The acquired lands do not By metes and bounds, giving courses and
conform to the rectangular distances between the successive angle
system of public land points with appropriate ties to the
surveys, but lie within an nearest official survey corner. If a
area of the public land portion of the boundary of the lands
surveys and constitute less requested coincides with the boundary in
than the entire tract the deed or other conveyance document,
acquired by the United you don't have to redescribe the
States. boundary if a copy of the deed or other
conveyance document is attached to your
nomination. Any portion of the lands
nominated that does not coincide with
the boundary in the deed or other
conveyance document must be tied by
courses and distances between successive
angle points into the description in the
deed or other conveyance document.
(d) The acquired lands lie Either as shown in the deed or other
outside an area of the conveyance document by which the United
public land surveys and States acquired title to the lands, or
constitute the entire tract attach a copy of the document to your
acquired by the United nomination.
States.
(e) The acquired lands lie By metes and bounds, giving courses and
outside an area of the distances between successive angle
public land surveys and points tying by courses and distances
constitute less than the into the description in the deed or
entire tract acquired by the other conveyance document. If a portion
United States. of the boundary of the lands requested
coincides with the boundary in the deed
or other conveyance document, you don't
have to redescribe the boundary if a
copy of the deed or other conveyance
document is attached to your nomination.
Any portion of the lands nominated that
does not coincide with the boundary in
the deed or other conveyance document
must be tied by courses and distances
between successive angle points into the
description in the deed or other
conveyance document.
(f) The acquired lands do not By filing three copies of a map upon
conform to the rectangular which the location of the lands are
survey system of public land clearly marked with respect to the
surveys. administrative unit or project of which
they are a part.
(g) The acquired lands have By the acquisition or tract number
been assigned an acquisition together with the identity of the State
or tract number by the and county where the lands are located.
acquiring agency.
(h) The public lands have a By legal subdivision, section, township,
protracted survey that has range and meridian. However, the
been approved and the smallest legal subdivision for which you
effective date published in may apply is a full section for the
the Federal Register. lower 48 states and four full contiguous
sections for Alaska.
(i) The lands are accreted... By metes and bounds giving courses and
distances between the successive angle
points on the boundary of the tract, and
connected by courses and distances to an
angle point on the perimeter of the
tract to which the accretions apply.
------------------------------------------------------------------------

Sec. 3121.21 What other rules must I follow when I submit my
nomination letter?

(a) You must not combine public domain and acquired minerals in the
same parcel nominated.
(b) Each parcel nominated must not exceed 2,560 acres for the lower
48 states or 5,760 acres for Alaska.
(c) The lands within each parcel nominated must be within a six
square mile area, unless you show BLM that a larger area is necessary.

[[Page 66901]]

Future Interest Leasing

Sec. 3121.30 May I submit a nomination letter for mineral interests
that will vest in the United States in the future and how will BLM
offer them?

(a) You may submit a nomination letter for future mineral
interests; and
(b) BLM will offer eligible future mineral interests at a
competitive lease sale.

Subpart 3122--Competitive Lease Sale

General

Sec. 3122.10 How often must each BLM State Office hold competitive
lease sales?

Each BLM State Office must hold competitive lease sales at least
quarterly if lands are eligible and available for competitive leasing.

Sec. 3122.11 How are competitive oil and gas lease sales conducted?

(a) Competitive lease sales are conducted by oral bidding.
(b) If you make the highest bid at the sale, you are committed to
execute the lease under Sec. 3122.15 and to pay the amounts required
under Secs. 3122.17 and 3122.20.
(c) If you are the highest bidder and you fail to complete the
requirements to obtain your lease under this subpart, BLM considers
your bid rejected.

Sec. 3122.12 Is there a minimum per-acre amount that I must bid on a
parcel?

The minimum acceptable bid is $2.00 per acre or fraction of an
acre, calculated on the gross acreage in the parcel.

Sec. 3122.13 If the United States owns a fractional interest (less
than 100 percent of the mineral interest in a parcel) is the minimum
bid per acre prorated?

The minimum acceptable bid will not be prorated for any lands in
which the United States owns a fractional interest. Your bid per acre
must be calculated on the gross acreage in the parcel.

Sec. 3122.14 How does BLM determine the winning bid?

The winning bid is the highest oral bid on a parcel that equals or
exceeds the minimum acceptable bid.

Sec. 3122.15 What documents must I submit on the day of the sale if I
am the winning bidder of a parcel?

(a) On the day of the sale, you must submit a signed BLM-approved
lease bid form for each parcel on which BLM determines you are the
winning bidder.
(b) Your signature on a BLM-approved lease bid form binds you to
the lease agreement and constitutes acceptance of the lease terms and
conditions.

Sec. 3122.16 May I withdraw my bid?

You may not withdraw your bid.

Sec. 3122.17 What must I pay per parcel at the sale if I am the
winning bidder?

(a) If you are the winning bidder of a parcel, on the day of the
sale you must pay--
(1) A nonrefundable $75 administrative fee;
(2) The first year's advance annual rental of $1.50 per acre or
fraction of an acre calculated on the gross acreage in the parcel; and
(3) The minimum bonus bid of $2.00 per acre or fraction of an acre
calculated on the gross acreage in the parcel.
(b) The BLM State Office with jurisdiction over the parcels in the
sale notice must receive your payment by the close of official business
hours on the day of the sale, or other time specified in the Notice of
Competitive Lease Sale, or BLM considers your bid rejected.

Sec. 3122.18 If I am the winning bidder for a future interest lease,
what payments must I make on the day of the sale?

If you are the winning bidder on a future interest lease, you do
not have to pay the first year's advance rental until the mineral
interest vests in the United States. Other payments are due in
accordance with Sec. 3122.17.

Balance of Bonus Bid

Sec. 3122.20 When is the balance of my bonus bid due?

You must submit the balance of your bonus bid within 10 business
days after the date of the sale.

Sec. 3122.21 What happens if BLM does not receive the balance of my
bonus bid within 10 business days following the date of the sale?

If BLM does not receive your bonus bid within 10 business days
following the date of the sale, you forfeit all monies paid on the day
of the sale and you lose all rights to the lease, unless the envelope
containing your payment is postmarked by the United States Postal
Service, or is dated as received at a courier or other delivery
service, on or before the tenth business day.

Rejection of Bid

Sec. 3122.30 Under what circumstances will BLM reject my bid?

BLM will reject your bid if--
(a) You do not submit the balance of bonus bid within 10 business
days from the date of the sale as provided in Sec. 3122.21;
(b) You do not comply with the requirements of this part, such as
furnishing BLM with evidence required under subpart 3130 that you will
commit your lease to the unit;
(c) BLM determines you are not qualified to hold Federal mineral
leases; or
(d) Your payment is returned to BLM by your bank for insufficient
funds.

Sec. 3122.31 Are parcels for which BLM rejected bids available for
noncompetitive leasing during the two years after the sale?

Parcels for which BLM rejected bids are not available for
noncompetitive leasing. BLM will offer the parcels at a future
competitive sale.

Parcels That Receive No Bid at Oral Auction

Sec. 3122.40 If a parcel receives no bid at the competitive lease
sale, is it available for noncompetitive leasing?

(a) Except as provided in paragraph (b) of this section, a parcel
for which BLM receives no bid at the competitive lease sale is
available for noncompetitive leasing.
(b) BLM may withdraw the following parcels from noncompetitive
leasing and lease those parcels through a process BLM considers
appropriate--
(1) Land reported as excess under the Federal Property and
Administrative Services Act of 1949. BLM leases these General Services
Administration surplus lands only through the competitive process.
(2) An interest in an existing lease that has been canceled or
forfeited. The specific lease interest in the parcel will be available
for lease beginning the first day after the sale to the first qualified
applicant that submits a bonus bid of $75.
(3) An area closed to leasing that is subject to drainage
(protective leasing). BLM leases these lands only through the
competitive process.
(c) Notwithstanding the provisions of subpart 3123, BLM may reject
any noncompetitive lease offer under paragraph (b) of this section that
is not as favorable to the United States as any other offer BLM
receives for a parcel. Also, for parcels subject to paragraph (b)(2),
the noncompetitive offer may not be less than required under
Sec. 3122.12.

Subpart 3123--Noncompetitive Leasing

Parcels Available for Noncompetitive Lease Offers

Sec. 3123.10 What parcels are available for noncompetitive lease
offers?

The only parcels available for noncompetitive lease offers are
parcels that received no bid at the competitive sale.

[[Page 66902]]

Sec. 3123.11 When do parcels that received no bid at the competitive
sale become available for noncompetitive leasing?

Parcels offered for bid that received no bid at the competitive
lease sale are available for noncompetitive leasing on the first
business day after the sale. These parcels are available for
noncompetitive bid for a period of two years, unless they are
withdrawn.

Priority of Noncompetitive Lease Offers

Sec. 3123.20 What if more than one noncompetitive offer is filed for
the same parcel?

(a) If more than one noncompetitive offer is filed for the same
parcel on the day after the sale, BLM considers the offers
simultaneously filed and holds a public drawing to determine priority.
(b) If BLM receives more than one noncompetitive offer for the same
parcel after the first day, your noncompetitive offer will receive
priority according to the date and time you filed it in the BLM State
Office with jurisdiction over the parcel for which you applied.
(c) If you properly filed your noncompetitive offer the day after
the sale, but BLM erroneously excluded the offer from the drawing for
priority, BLM will hold a new public drawing to include your offer.

Sec. 3123.21 If my noncompetitive offer requires a correction, under
what circumstances does it retain priority?

(a) Your noncompetitive offer must be complete when you file it or
BLM will reject it. However, BLM will accept your noncompetitive offer
and allow it to retain its priority under Sec. 3123.20 if --
(1) You filed your noncompetitive offer on an obsolete form;
(2) You submitted only one copy of your noncompetitive offer form;
(3) You failed to sign or date your noncompetitive offer form;
(4) Your bank erroneously returned your remittance for the first
year's advance rental, required under Sec. 3123.41, for insufficient
funds;
(5) You submitted copies of the offer which were not exact
reproductions, except where BLM cannot determine which parcels you
included;
(6) Someone other than yourself signed your offer and, in response
to BLM's request, you timely provide BLM a description of your
relationship to the person who signed the offer;
(7) Your rental payment, under Sec. 3123.40, is deficient by not
more than 10 percent or $200, whichever is less, and you make your
payment to correct the deficiency to BLM within 30 calendar days from
your receipt of the notification of deficiency; or
(8) Your offer contains public domain and acquired mineral parcels.
Your offer retains priority for the type of lands you have indicated in
the upper portion of the offer form. Your offer for the other lands
will be rejected.
(b) You must correct the errors in paragraphs (a)(1) through (a)(6)
of this section within 10 business days after BLM's notice.

Description of Lands in Noncompetitive Lease Offer

Sec. 3123.30 How do I describe the lands in my offer I file the day
after the competitive lease sale?

Your noncompetitive lease offer must describe the lands by the
parcel number indicated in the Notice of Competitive Lease Sale.

Sec. 3123.31 How do I describe the lands in my noncompetitive offer
for public domain or acquired minerals that I file within the two years
after the sale?

(a) Your noncompetitive lease offer must describe the lands by the
parcel number indicated in the Notice of Competitive Lease Sale.
(b) You may combine more than one parcel from more than one sale
notice on an offer, but your lease offer must--
(1) Include entire parcels;
(2) Be within a six square mile area, unless you show BLM that a
larger area is necessary; and
(3) Not exceed 2,560 acres for the lower 48 states and 5,760 acres
for Alaska.

Requirements of a Noncompetitive Lease Offer

Sec. 3123.40 How do I file a noncompetitive offer?

To file a noncompetitive lease offer--
(a) File it in duplicate (an original and one copy) on a form
approved by the Director. BLM will accept a reproduction of the form if
it includes no additions, omissions, other changes, or advertising;
(b) File a form that is typewritten or printed plainly in ink,
signed in ink and dated by you or your authorized agent;
(c) Include a nonrefundable $75 filing fee; and
(d) Except for noncompetitive future interest lease offers, include
the first year's advance rental at $1.50 per acre or fraction of an
acre.

Sec. 3123.41 If I file a noncompetitive future interest offer, when
must I pay the first year's advance rental?

You must pay the first year's advance rental when the mineral
interest vests in the United States.

Sec. 3123.42 What happens to my noncompetitive offer if an earlier
offeror is entitled to a lease, either as a result of priority of the
offer, or a pending lease reinstatement?

BLM will not reject your noncompetitive offer until we take final
action on the earlier offer or pending reinstatement.

Sec. 3123.43 May I amend my noncompetitive lease offer before BLM
issues the lease?

You may not amend your noncompetitive lease offer. However, you
should notify BLM of any insignificant errors in your offer that BLM
should correct before it issues your lease.

Sec. 3123.44 May I withdraw my noncompetitive lease offer?

You may not withdraw your noncompetitive offer in whole or in part
until 60 calendar days have elapsed from the date the offer was filed
in the BLM State Office with jurisdiction over the lands. BLM will
refund only your first year's advance rental. You may not withdraw your
offer under any circumstance after BLM issues the lease.

Subpart 3124--Lease Administration and Renewals

Dating of Leases

Sec. 3124.10 What is the effective date of my lease?

(a) Your lease is effective the first day of the month following
the date BLM signs it. BLM will issue the lease effective the first day
of the month in which it is signed if you request it in writing.
(b) BLM will issue your future interest lease effective the date
the mineral interest vests in the United States.
(c) If the United States owns both a present fractional interest
and a future fractional interest of the minerals in the same parcel,
BLM will issue your lease to cover both the present fractional interest
and future fractional interest. The effective date and primary term of
your present fractional interest lease is unaffected by the vesting of
the future fractional interest in the United States.
(d) Your renewal lease is effective the first day of the month
following the month the original lease expired.
(e) The effective date of your consolidated lease is that of the
oldest lease in the consolidation.

Leases Within Unit Agreements

Sec. 3124.20 What if the lands I am leasing are within an existing
unit agreement?

If the lands you are leasing are within an existing unit agreement,
before BLM issues your lease, you must file--

[[Page 66903]]

(a) Evidence that you will commit your lease to the unit; or
(b) Your reasons for not joining the unit. If BLM accepts the
reasons, you will be permitted to operate independently. If BLM rejects
the reasons, you must commit the lease to the unit, or BLM will reject
your lease offer.

Sec. 3124.21 What effect does the commitment to a unit have on my
lease offer or lease?

(a) If your lease offer contains lands partly within and partly
outside the unit boundary, BLM will issue separate leases, one for the
lands within the unit boundary and one for the lands outside the unit
boundary.
(b) BLM will segregate the lease and issue a new lease for the
lands outside the unit, which is effective on the effective date of
unitization. See Sec. 3137.16, which explains when a unit is effective.

Lease Consolidation

Sec. 3124.30 May I consolidate leases?

(a) BLM may approve your request to consolidate your leases if they
are producing, have the same lease terms and rental and royalty rates,
and record title owners of all the lands are the same. You may only
consolidate leases, with BLM's approval, that have at least one point
as a common boundary and that were issued under the same statutory
authority.
(b) The effective date of the consolidated leases is the earliest
effective date of the several leases that were consolidated.

Sec. 3124.31 What information must I include in my application for
lease consolidation?

As record title owner(s), your application for lease consolidation
must show, in addition to the requirements in Sec. 3124.30--
(a) That the lease consolidation promotes conservation of the oil
or gas resource that cannot be achieved through either unitization or
communitization;
(b) The location of the leases you plan to consolidate;
(c) That the leases you plan to consolidate are in a producing
status;
(d) What nonproducing acreage within the leases you plan to
consolidate and that which you will relinquish;
(e) How record title to the leases you plan to consolidate is held;
and
(f) That the proposed consolidated lease would not exceed the
maximum lease size under Sec. 3120.41.

Sec. 3124.32 How many copies of my application must I file and where
must I file it?

You must file an original and a duplicate of your application for
lease consolidation in the BLM State Office with jurisdiction over the
lands in your application. Consolidation is not effective until the
date BLM approves the application.

Lease Renewals

Sec. 3124.40 For how many years will BLM renew my lease?

If you have a lease issued under Section 14 of the Mineral Leasing
Act (MLA) (30 U.S.C. 223), it will continue in effect for so long as
you produce oil or gas in paying quantities or your lease is committed
to a producing communitization agreement. If your lease was committed
to a unit after August 8, 1946, then only the portion of your lease in
the unit is extended by commitment to the unit. If any portion of your
lease was committed to the unit before that date, your entire lease is
extended by commitment.

Sec. 3124.41 For how many years will BLM renew my lease if it was not
issued under Section 14 of the Mineral Leasing Act?

(a) If you have a lease that BLM originally issued with an initial
20 year lease term under any section of the MLA other than section 14,
BLM will automatically renew it for successive 10 year periods.
(b) All other leases BLM issues are not subject to renewal.
However, the original lease term may be extended under the provisions
of subpart 3140.

Sec. 3124.42 If my lease is committed to a unit agreement may I file a
renewal lease application?

If your 20-year lease is--
(a) Committed to a unit agreement, BLM will not renew it, except as
provided in paragraph (b). Your lease continues in force until it
expires, the unit terminates, or your lease is eliminated from the
unit, whichever occurs last.
(b) In a 10-year renewal term, and is committed to and then
eliminated from a unit before the renewal term expires, BLM will renew
it.

Sec. 3124.43 Who may file a renewal lease application?

The lessees of record or the operating rights owners may file a
lease renewal application.

Sec. 3124.44 How must I file my renewal lease application?

You must file your renewal lease application--
(a) In the BLM State Office with jurisdiction over the lands;
(b) At least 90 calendar days before your lease expires; and
(c) With a nonrefundable $75 filing fee.

Subpart 3125--Exchange Leases

Exchange Leases

Sec. 3125.10 May I exchange my existing oil and gas lease for a new
lease?

If the existing lease is a renewal of a twenty-year lease, the
lessee of record, with the concurrence of the operating rights owner,
may exchange it for a new lease for the same lands with a primary term
of five years. See Secs. 3106.30 and 3120.41 for the royalty and rental
rates that apply to your exchange lease.

Sec. 3125.11 How must I file an exchange lease application?

The lessee of record or operating rights owner must--
(a) File the exchange lease application in duplicate in the BLM
State Office with jurisdiction over the lands in the application; and
(b) Include a nonrefundable $75 filing fee.

Subpart 3126--Railroad Right-of-Way Leases

Railroad Right-of-Way Leases

Sec. 3126.10 To which rights of way does this subpart apply?

(a) This subpart applies to--
(1) Railroad rights-of-way and easements issued under the Act of
March 3, 1875 (43 U.S.C. 934 et seq.) and earlier right-of-way
statutes; or
(2) Rights-of-way and easements issued under the Act of March 3,
1891 (43 U.S.C. 946 et seq.).
(b) Oil and gas leases for other rights-of-ways are leased under
subparts 3121 and 3122.

Sec. 3126.11 Who may lease the oil or gas deposits underlying a
railroad right-of-way?

(a) You may file an application to lease the oil and gas underlying
a right-of-way subject to this subpart if you--
(1) Own the right-of-way; or
(2) Acquired the right to apply for a lease from the owner of the
right-of-way.
(b) If you are an owner or lessee of the oil or gas rights
adjoining the right-of-way (see Sec. 3126.15(b)), you may enter into an
agreement with the United States under which you agree to compensate
the United States for any drainage of the oil or gas underlying the
right-of-way.

[[Page 66904]]

Sec. 3126.12 How must I file a lease application under this subpart?

(a) No approved form is required for a right-of-way lease, but you
must--
(1) File an application to lease in duplicate in the BLM State
Office with jurisdiction over the lands; and
(2) Include a nonrefundable $75 filing fee.
(b) If you are not the owner of the right-of-way, but acquired the
right to file for a lease from the owner, you must submit a copy of the
document granting you that right.

Sec. 3126.13 What information must my application include?

In your application, you must--
(a) Show that you have the right to lease the oil and gas under the
right-of-way;
(b) Describe the development of oil or gas on adjacent or nearby
lands, the location and depth of the well, and the production and
probability of drainage of the deposits in the right-of-way;
(c) Describe each legal subdivision through which the right-of-way
extends in the area you propose to lease. You are not required to
describe the lands by metes and bounds;
(d) Furnish a plat or map of the area showing the location and
acreage of the right-of-way in the area you propose to lease;
(e) Provide the names and addresses of all mineral owners or
lessees of oil and gas interests in the lands adjoining the right-of-
way in the area you propose to lease; and
(f) Include the amount of compensation (not less than 12\1/2\
percent of the value of production) you are willing to pay.

Sec. 3126.14 Who must BLM notify that I filed an application to lease
the oil and gas under the right-of-way?

BLM must--
(a) Notify the owner or lessee of the oil and gas interests in
lands adjoining the area you propose to lease; and
(b) Tell the persons notified how long they have to submit a bid
for the amount of compensation they are willing to pay the Federal
Government for extracting the oil and gas underlying the right-of-way
through wells on its adjoining lands, under Sec. 3126.15.

Sec. 3126.15 Who may submit a bid for compensation?

If you are the owner or lessee of oil and gas interests adjoining
the right-of-way, you may submit a proposal to enter into an agreement
with the United States under which you agree to compensate the United
States for draining of oil or gas underlying the right-of-way.

Sec. 3126.16 What must I include in my bid for compensation?

(a) Provide the same information required for a lease application
in Sec. 3126.13(b), (c), (d) and (e). Also provide the amount of
compensation you are offering to pay the United States, including at
least 12\1/2\ percent in the amount or value of production; and
(b) File the bid for compensation in the BLM office with
jurisdiction over the right-of-way.

Sec. 3126.17 Who must BLM notify that I have filed an application for
compensation?

(a) BLM will notify the holder of the right-of-way that a bid for
compensation has been filed. BLM also will require the holder to either
provide notice to any person who acquired the owner's right to lease
the oil and gas underlying the right-of-way, or tell BLM who that
person is, so BLM may provide notice.
(b) BLM will also notify all other owners or lessees of oil and gas
interest in lands adjoining the right-of-way in the area subject to
your bid.
(c) BLM will tell the persons notified how long they have to submit
a lease application or a bid for compensation under this subpart.

Sec. 3126.18 May BLM request offers to lease or for compensation?

BLM may request offers to lease or offer compensation for oil and
gas underlying a right-of-way subject to this subpart. BLM will provide
notice under Secs. 3126.14 and 3126.17(a).

Sec. 3126.19 Who will receive the rights to the oil and gas underlying
the right-of-way?

BLM will evaluate all lease applications and compensation
agreements it receives. BLM will issue a lease or enter into a
compensation agreement with the person whose offer is most advantageous
to the United States.

Sec. 3126.20 What is the term of my lease or agreement?

The term of your lease or agreement is 20 years.

Subpart 3129--Record Title, Operating Rights and Estate Transfers,
Name Changes and Mergers

General

Sec. 3129.10 What is a transfer?

A transfer is a conveyance of either record title or operating
rights in a lease.

Sec. 3129.11 When must I file a transfer with BLM?

You must file a transfer with BLM when--
(a) You convey a lease interest;
(b) An interest holder dies;
(c) There is a corporate merger or name change; or
(d) A court orders a transfer.

Sec. 3129.12 Who may receive a transfer of lease interests?

You may receive a transfer of lease interests only if you are
qualified to hold a lease under subpart 3105.

Sec. 3129.13 What must I include in my transfer application?

Your transfer application must be complete. See Sec. 3129.30 for
the form you need.

Sec. 3129.14 When is my transfer effective?

BLM approves transfers effective the first day of the month
following the date--
(a) BLM determines your transfer had no defects; or
(b) BLM determines you cured all defects in the transfer. Common
examples of defects are--
(1) No signature;
(2) No original signatures;
(3) No date(s);
(4) Insufficient number of copies;
(5) Incorrect legal descriptions;
(6) Legal descriptions of less than a legal subdivision;
(7) Incorrect description of the lease interest(s);
(8) The transferor has no interest in the lease or the incorrect
interest is shown on the transfer because an intervening transfer has
not been filed;
(9) The transfer conveys only oil or only gas; and
(10) The transfer of record title attempts to convey only specific
formations.

Sec. 3129.15 May I withdraw my transfer?

You may withdraw your transfer if BLM has not approved it. Your
request to withdraw the transfer must be in writing and signed by both
the transferor and transferee.

Sec. 3129.16 May I file a record title transfer limited to a specific
depth, formation, zone or defined deposit or fluid mineral?

Unless your lease was issued limited horizontally, you may not file
a record title transfer limited to a specific depth, formation, zone or
defined deposit or limited to only oil or only gas.

Sec. 3129.17 May I file my operating rights transfer to a specific
depth?

You may convey operating rights limited to a specific depth. For
example, you may convey a 100 percent operating rights interest from
the surface to 2,000 feet and retain the interest in the depths below
2,000 feet.

[[Page 66905]]

Sec. 3129.18 How do transfers of interest affect future transfers?

When BLM issues you a lease, you receive both the record title and
operating rights interest in the lease. As the lessee, you may transfer
the operating rights without assigning record title interest in the
lease. If you transfer only operating rights interests in the lease,
the record title and operating rights are split. After those rights are
split, the respective owners of such rights must file transfers of
operating rights separately from transfers of record title.

Sec. 3129.19 When will BLM segregate a lease as a result of a
transfer?

(a) If you transfer 100 percent record title interest in a
described portion of the lands in the lease, BLM will segregate the
lease into two separate leases (see Sec. 3140.70).
(b) If you transfer 100 percent operating rights interest in a
described portion of the lands in the lease, BLM will not segregate the
lease.

Sec. 3129.20 What is a mass transfer?

A mass transfer occurs when a transferor transfers interests of any
type in multiple Federal leases to the same transferee.

Sec. 3129.21 May I file a mass transfer?

You may file a mass transfer. However, you must file three signed
originals of the record title or operating rights transfer forms for
each affected lease. Each lease is a separate transfer. BLM will not
accept copies of these signed documents.

Sec. 3129.22 Does BLM's approval of a transfer certify that title is
clear?

BLM's approval of a transfer does not warrant or certify that
parties to a transfer hold legal or equitable title to a lease.

Forms, Fees and Filing Requirements

Sec. 3129.30 What forms must I use to transfer lease interests, how
many copies must I file, what is the filing fee per lease or document,
and where must I file them?

To transfer an interest, you must file in each BLM State Office
with jurisdiction over the lands involved (except as provided in
Sec. 3129.37) according to the following chart--

--------------------------------------------------------------------------------------------------------------------------------------------------------
Number of copies
Type of transfer Form required Form number required Filing fee
--------------------------------------------------------------------------------------------------------------------------------------------------------
(a) Record Title................ Yes.................... 3000-3................. Three.................. $25 per interest transferred.
(b) Operating Rights............ Yes.................... 3000-3a................ Three.................. $25 per interest transferred.
(c) Estate...................... No..................... N/A.................... One (Include a list of None.
all leases affected).
(d) Mergers..................... No..................... N/A.................... One (Include a list of None.
all leases affected).
(e) Name Changes................ No..................... N/A.................... One (Include a list of None.
all leases affected).
--------------------------------------------------------------------------------------------------------------------------------------------------------

Sec. 3129.31 Are filing fees refundable?

Filing fees are not refundable. However BLM will refund filing fees
that exceed the amount required by the regulations in parts 3100
through 3190.

Sec. 3129.32 How do I describe the lands on Form 3000-3 for my record
title transfer?

If you are transferring--
(a) All of the lands in a lease, you do not need to include a legal
land description; or
(b) A portion of the lands in a lease, you must describe those
lands in the same manner as described in the lease document.

Sec. 3129.33 May I transfer less than a legal subdivision?

You may transfer less than a legal subdivision if those lands were
originally described that way in the lease.

Sec. 3129.34 May I file a record title transfer containing less than
640 acres?

BLM will approve a record title transfer of less than 640 acres
outside Alaska or 2,560 acres within Alaska only if--
(a) The transfer constitutes the entire lease; or
(b) You demonstrate that the transfer will further the development
of oil or gas. Your signature on the transfer form certifies that the
transfer will further the development of oil or gas. However, BLM may
request additional information before approving the transfer.

Sec. 3129.35 What must I submit to BLM to transfer the rights or
interests of a decedent to its heir, devisee or estate?

(a) To transfer the rights or interests of a decedent to its heir,
devisee or estate, you must submit--
(1) If probate of the estate has been completed--
(i) A copy of the will or decree of distribution; and
(ii) A statement as to citizenship and acreage holdings in Federal
oil and gas leases signed by each heir;
(2) If probate of the estate has not been completed, a statement
signed by each heir as to citizenship and acreage holdings in Federal
oil and gas leases and evidence--
(i) Of the authority of the executor or administrator to act on
behalf of the estate; or
(ii) That the heirs or devisees are the only heirs or devisees of
the deceased;
(3) If there is no will, and State law does not require probate
proceedings, a statement signed by --
(i) The heirs that they are the only heirs of the deceased; and
(ii) Each heir as to citizenship and acreage holdings in Federal
oil and gas leases.
(b) You must file a bond rider or a replacement bond under subpart
3107 for any bonds the decedent previously furnished.

Sec. 3129.36 What must I submit to BLM for a merger or name change?

For a merger or name change, you must file--
(a) Evidence that the State has acted on your request for a name
change or merger;
(b) A list of all of the Federal lease serial numbers affected by
the merger or name change; and
(c) Any bond rider or a replacement bond required under subpart
3107.

Sec. 3129.37 Where must I file documentation of estate, merger and
name changes?

(a) If you maintain a bond, you must file documentation of estate,
merger and name changes in the BLM State Office(s) that accepted your
bond(s); or
(b) If you don't maintain a bond, you must file documentation of
estate, merger and name changes in the BLM State Office with
jurisdiction over any of the affected leases.

Sec. 3129.38 As the transferee, what should I file to show I am
qualified to hold Federal lease interests?

By signing the Certification and Request for Approval, on Forms
3000-3 or 3000-3a, you certify that you meet the qualification
requirements of subpart 3105.

Sec. 3129.39 When must I file transfers with BLM?

(a) You must file record title and operating rights transfers
within 90 calendar days from the date the transferor signs the
document. If you file a transfer more than 90 calendar days after the
transferor signed the document, BLM will require the transferor to

[[Page 66906]]

certify that it still intends to transfer its interest.
(b) There is no timeframe for filing estate, merger and name change
documents.

Sec. 3129.40 May I transfer an interest before BLM issues the lease?

You may file a transfer before a lease is issued, but BLM will not
approve your transfer until we issue the lease.

Bonding, Obligations and Liabilities

Sec. 3129.50 When will BLM require a new bond for a transfer?

If the person that provided the existing bond no longer has
responsibility for performance on the lease, the transferee or other
person with an interest in the lease, or the operator, must provide a
new bond before BLM will approve the transfer.

Sec. 3129.51 If I transfer my lease, when do my obligations under the
lease end?

You are responsible for the performance of all obligations under
the lease until the date BLM approves an assignment of your record
title or transfer of your operating rights. You will continue to be
responsible for obligations that accrued prior to the approval date,
whether or not they were identified at the time of the assignment or
transfer, including the payment of compensatory royalties for drainage.
As the assignor or transferor, you remain responsible for plugging
wells you drilled and abandoning facilities installed or used prior to
the effective date of the assignment or transfer.

Sec. 3129.52 If I acquire a lease by an assignment or transfer, what
obligations do I agree to assume?

If you acquire a Federal lease interest by assignment or transfer,
you agree to comply with the terms of the original lease during your
lease tenure, notwithstanding any terms of your assignment or sublease.
Also, you must plug and abandon all unplugged wells, reclaim the lease
site, and remedy all environmental problems in existence and knowable
to a purchaser exercising reasonable diligence at the time you receive
the assignment or transfer. You are also liable for any obligations you
agreed to assume from the transferor as part of the transfer agreement.
You must also maintain an adequate bond to ensure performance of these
responsibilities.

Denial/Disapproval

Sec. 3129.60 When will BLM deny or disapprove a transfer to me?

(a) BLM will deny a transfer to you if you--
(1) Do not furnish a bond if one is required;
(2) Are not qualified to hold Federal lease interests;
(3) Are in violation of the reclamation requirements or other
standards established under Section 17(g) of the Mineral Leasing Act,
as amended; or
(4) Do not correct a defect in your transfer document.
(b) BLM will return your transfer unapproved if--
(1) The lease is no longer in effect (i.e., the lease has
terminated, expired, been canceled or relinquished);
(2) The transfer is a duplicate of one which has already been
filed; or
(3) The interest has previously been conveyed.

Sec. 3129.61 Must I file assignments of rights to production with BLM?

BLM will not accept assignments of rights to production that do not
transfer record title or operating rights interests.

Sec. 3129.62 May I file a lien against a lease for monies owed me?

BLM will not accept liens against Federal leases. If you attempt to
file a lien with BLM, we will return it and retain any filing fee you
submitted.

Sec. 3129.63 Must I file transfers of overriding royalty interest, net
profit or production payments with BLM?

BLM will not accept transfers of overriding royalty interest, net
profit, or production payments. If you file any of these transfers with
BLM, we will return them and retain any filing fee you submitted.

PART 3180--[REMOVED]

4. Remove part 3180.
5. Revise the authority citation for part 3130 as follows:

PART 3130--[AMENDED]

Authority: 42 U.S.C. 6508 and 43 U.S.C. 1732(b).

PART 3130--[REDESIGNATED AS PART 3180]

6. Redesignate part 3130--Oil and Gas Leasing: National Petroleum
Reserve, Alaska as part 3180.
7. Add new part 3130 to read as follows:

Part 3130--Oil and Gas Agreements

Subpart 3130--Reservoir Management

Well Spacing

Sec.
3130.10 Who establishes well spacing for Federal and Indian
minerals?
3130.11 Must I follow a spacing program when I drill a well on
Federal or Indian lands?
3130.12 What setback applies to a well I drill on a Federal or
Indian lease or agreement?
3130.13 Must I follow State producing restrictions?

Subpart 3132--Oil and Gas Agreements: General

General

3132.10 What agreements require BLM approval?
3132.11 What is BLM's role in agreements on Indian lands?
3132.12 What benefits will I or my lease receive when I enter into
an approved agreement?
3132.13 Must I obtain rights-of-ways for roads, facilities, or
other surface uses, for Federal lands excluded from an agreement by
contraction or termination?
3132.14 May I include non-Federal oil and gas interests in an
agreement?

Subpart 3133--Communitization Agreements

Communitization Agreements

3133.10 When will BLM approve my request to communitize oil and gas
leases?
3133.11 How do I apply for a communitization agreements (CA)?
3133.12 When is a CA effective and what is its term?
3133.13 When does a CA meet the public interest requirement?
3133.14 When does a CA terminate?
3133.15 What is the effect of a CA on my lease term?
3133.16 Will BLM allow more than one operator for a CA?
3133.17 What are the requirements to change the CA operator?
3133.18 Who will BLM notify about requirements for the CA?

Subpart 3134--Subsurface Storage Agreements

Subsurface Storage Agreements

3134.10 Will BLM allow subsurface storage agreements covering
Federally-owned lands?
3134.11 How do I apply for a subsurface storage agreement?
3134.12 What must I pay for storage?

Subpart 3135--Development Contracts

Development Contracts

3135.10 What is a development contract?
3135.11 When will BLM approve a development contract?
3135.12 What lands may I include in a development contract?
3135.13 How do I apply for a development contract?
3135.14 How many Federal lessees must enter into a development
contract?
3135.15 May BLM be a party to the development contract?
3135.16 May existing development contracts be renegotiated?
3135.17 What must I do to satisfy my obligations under a
development contract?

[[Page 66907]]

3135.18 What information in my proposal will be held
confidentially?
3135.19 When does a development contract terminate?

Subpart 3136--Drainage Compensation Agreements

Drainage Compensation Agreements

3136.10 What is a drainage compensation agreement?
3136.11 How are the terms of a drainage compensation agreement
determined?

Subpart 3137--Unit Agreements

Application

3137.10 What agreements does this subpart cover?
3137.11 How are the terms of an exploratory unit agreement
determined?
3137.12 How are the terms of an enhanced recovery unit agreement
determined?
3137.13 What must I include in a unitization application?
3137.14 As the unit operator, what must I certify in my unitization
application?
3137.15 As the unit operator, must I provide BLM with evidence of
commitment status in my unitization application?
3137.16 When is a unit agreement effective?
3137.17 How will the parties to the unit know if BLM provisionally
approves the unit agreement?
3137.18 Why would BLM reject a unitization application?

Mandatory Provisions

3137.20 What must an exploratory unit agreement include?
3137.21 What must an enhanced recovery unit agreement include?
3137.22 Will BLM accept or approve other terms?

Optional Provisions

3137.30 Are there any optional provisions that I may include in a
unit agreement?
3137.31 What are the requirements for multiple unit operators?
3137.32 How can parties modify their unit agreement?
3137.33 What must I submit to BLM if I propose to modify a unit
area or change the commitment status of a lease?
3137.34 What effect do other BLM oil and gas agreements have on the
unit agreement?

Size and Shape

3137.40 What are the size and configuration requirements for a unit
area?

Development

3137.50 What initial unit obligations must I define in an
exploratory unit agreement?
3137.51 What must I do to meet initial unit obligations and fulfill
the public interest requirement in an exploratory unit?
3137.52 What enhancement obligations must I define in an enhanced
recovery unit agreement?
3137.53 What must I do to meet enhancement obligations and fulfill
the public interest requirement in an enhanced recovery unit?
3137.54 What happens if I do not meet initial unit obligations in
an exploratory unit or enhancement obligations in an enhanced
recovery unit?
3137.55 What are continuing development obligations?
3137.56 How must I define continuing development obligations in the
unit agreement?
3137.57 Must I perform additional development outside established
participating areas to fulfill continuing development obligations?
3137.58 What happens if I do not meet a continuing development
obligation?
3137.59 What must I submit to BLM after I meet a continuing
development obligation?

Productivity Criteria and Participating Area

3137.60 What are productivity criteria?
3137.61 What is a participating area and what is its function?
3137.62 What establishes a participating area?
3137.63 What happens to the participating area when new wells are
drilled that meet the productivity criteria?
3137.64 What must I submit to BLM when I establish a participating
area or add to an existing participating area?
3137.65 Must additions to an existing participating area be the
same size as the initial participating area?
3137.66 Must participating areas for different producing intervals
be the same size?
3137.67 How do I allocate participating area production when there
are unleased Federal lands in the participating area?
3137.68 What if unleased Federal lands are leased after the
effective date of the unit agreement?
3137.69 What happens when a well outside any participating area
does not meet the productivity criteria?
3137.70 How does allocation of production occur from wells that do
not meet the productivity criteria?
3137.71 Who must operate wells that do not meet the productivity
criteria?
3137.72 May a well BLM previously determined to be a non-unit well
establish or revise a participating area?
3137.73 What is the effective date of an initial participating area
or revision to an existing participating area?
3137.74 How long does a participating area remain in effect?

Unit Operations

3137.80 What is unit development or operations?
3137.81 As unit operator, what are my obligations?
3137.82 What must I file with BLM to change the unit operator?
3137.83 When does my liability as unit operator end?
3137.84 As a unit operator, what must I do to prevent or compensate
for drainage?

Suspensions and Extensions of Development

3137.90 As the unit operator, what happens if I cannot meet unit
requirements for reasons outside of my control?
3137.91 Will BLM grant an extension of time to meet the initial or
continuing development obligations?

Unit Termination

3137.100 Under what circumstances will BLM approve a voluntary unit
termination?
3137.101 What if I do not meet a continuing development obligation
before any participating area has been established in the unit?
3137.102 After participating areas are established, when does the
unit terminate?

Royalties

3137.110 How is unit production from an exploratory unit agreement
allocated?
3137.111 What is the royalty rate for unleased Federal lands in a
participating area?
3137.112 What is average daily production for a Federal lease
committed to a unit where the royalty rate depends on average daily
production?
3137.113 May the United States take an in-kind royalty share of
unit production?

Leases and Contracts Conformed and Extended

3137.120 As the unit operator, must I develop and operate on every
tract in the unit to comply with the development obligations of the
underlying leases, contracts or agreements (other than unit
agreements)?

Change in Ownership

3137.130 As a transferee of an interest in a unitized Federal
lease, am I subject to the terms and conditions of the unit
agreement?

Authority: 30 U.S.C. 189 and 226.

Subpart 3130--Reservoir Management

Well Spacing

Sec. 3130.10 Who establishes well spacing for Federal and Indian
minerals?

BLM establishes well spacing to protect Federal or Indian mineral
interests, promote orderly development, conserve oil and gas, and
assure that each Federal or Indian tract and its lessees have the
opportunity to participate in reservoir development. State spacing
orders do not necessarily apply to Federal or Indian minerals.
However--
(a) For Federal minerals, after independent review and evaluation,
BLM will either--
(1) Concur with spacing set by an appropriate State authority, if
the proposed spacing protects Federal interests; or
(2) Issue its own spacing order for the Federal minerals;

[[Page 66908]]

(b) For Indian minerals, BLM must approve spacing, except for Osage
leases. In the case of Oklahoma Indian leases subject to district court
approval, spacing orders of the Oklahoma Corporation Commission apply
when approved by the Secretary.

Sec. 3130.11 Must I follow a spacing program when I drill a well on
Federal or Indian lands?

(a) You must locate your well to conform with well spacing
established under Sec. 3130.10.
(b) BLM may waive spacing requirements on Federal and Indian lands.

Sec. 3130.12 What setback applies to a well I drill on a Federal or
Indian lease or agreement?

(a) If your lease is not in an agreement, you must locate your
wells so that the bottom hole location is not closer than 200 feet from
the boundary of the lease, or if subject to spacing, then 200 feet from
the spacing unit boundary.
(b) If your lease is in an agreement, you must locate your well so
that the bottom hole location is not closer than 200 feet from an
agreement boundary.
(c) BLM may approve a different location requirement in your
Application for Permit to Drill or Reenter.

Sec. 3130.13 Must I follow State producing restrictions?

State producing restrictions do not apply to Federal or Indian
minerals. However, on Federal or Indian lands, after independent review
and evaluation, BLM may decide to apply production restrictions set by
an appropriate State authority if the proposed restrictions protect or
conserve Federal or Indian interests.

Subpart 3132--Oil and Gas Agreements: General

General

Sec. 3132.10 What agreements require BLM approval?

These agreements require BLM approval if they include one or more
Federal leases--
(a) A communitization agreement when you want to join tracts within
a single drilling or spacing unit. (See subpart 3133.)
(b) A subsurface storage agreement if you want to use a formation
to store gas or oil for later production and sale. (See subpart 3134.)
(c) A development contract with an agreed rate or amount of
exploration and development for areas that you may not otherwise
explore or to provide for large scale development. (See subpart 3135.)
(d) A drainage compensation agreement where wells on adjacent lands
are draining leased or unleased minerals. (See subpart 3136.)
(e) An exploratory unit agreement, so that drilling and production
may proceed in an entire area or structure in the most efficient and
economical manner. (See subpart 3137.)
(f) An enhanced recovery unit agreement, to produce hydrocarbons
that cannot be recovered by primary methods. (See subpart 3137.)

Sec. 3132.11 What is BLM's role in agreements on Indian lands?

The Bureau of Indian Affairs (BIA) approves agreements that include
Indian minerals but not Federal minerals. See 25 CFR 211.28 and 212.28.
BLM approval is not required. In agreements covering both Federal and
Indian minerals, BLM approves the agreement following BIA approval of
the commitment of the Indian mineral interests. BLM regulates
operations under the terms of agreements that include Indian minerals.

Sec. 3132.12 What benefits will I or my lease receive when I enter
into an approved agreement?

The benefits of your agreement include those items in the following
list that are checked in the table in this section for your specific
type of agreement--
(a) The acreage committed to agreements is exempt from statewide
statutory acreage limitations;
(b) Development or production on one tract within the agreement is
considered full performance of obligations to develop and produce on
each individual tract committed to the agreement;
(c) Production in paying quantities from any part of the lands
committed to an agreement will extend all leases committed to the
agreement. Production is not required to extend Federal leases in
subsurface storage agreements;
(d) During the term of an agreement, and while Federal leases
remain committed to the agreement, you do not need to obtain rights-of-
way for roads, facilities, or other surface uses, on those Federal
leases committed to the agreement;
(e) You may choose a drilling location without regard to certain
lease restrictions, such as lease boundaries within the unit or spacing
offsets, unless BLM has adopted State spacing restrictions for that
area;
(f) You may consolidate operations and reporting requirements;
(g) You have no obligation to protect your lease from drainage
resulting from production on committed tracts; or
(h) When Federal lease(s) are eliminated from the agreement, you
are eligible for lease extensions. (See subpart 3140.)

Sec. 3132.13 Must I obtain rights-of-ways for roads, facilities, or
other surface uses, for Federal lands excluded from an agreement by
contraction or termination?

You must obtain a right-of-way for those roads and facilities
located on Federal surface located outside the agreement boundaries
after contraction or termination of the agreement.

Sec. 3132.14 May I include non-Federal oil and gas interests in an
agreement?

You may include Indian, State or private minerals in an agreement
with Federal minerals.

Subpart 3133--Communitization Agreements

Communitization Agreements

Sec. 3133.10 When will BLM approve my request to communitize oil and
gas leases?

BLM will approve your request for a communitization agreement (CA)
if--

[[Page 66909]]

(a) Your Federal lease or a portion of your Federal lease cannot be
independently developed and operated within a single well spacing unit
that includes other leased or unleased tracts; and
(b) You demonstrate that communitization is in the public interest
under Sec. 3133.13.

Sec. 3133.11 How do I apply for a CA?

You must--
(a) Submit a request to communitize to BLM and in it--
(1) Describe the separate tracts comprising the drilling or spacing
unit and formation(s) you intend to commit to the CA;
(2) Identify the well(s) you drilled or plan to drill within the
communitized area;
(3) Certify that all owners of mineral rights (leased or unleased)
and lease interests (record title and operating rights) have committed
or consented to the commitment of their interest in writing;
(4) Name who will be responsible for operations under the CA;
(5) Specify the date you propose to make the CA effective; and
(6) Include a schedule allocating production for each committed
tract on a surface acreage basis.
(b) If BLM requests it, submit--
(1) A copy of any operating agreements between working interest
owners; or
(2) Evidence of commitment required in paragraph (a)(3) of this
section.

Sec. 3133.12 When is a CA effective and what is its term?

(a) BLM must approve a CA. Its effective date is the date BLM
specifies in the approval which will be the earlier of--
(1) The completion date of a well drilled to a communitized
formation;
(2) The effective date of a State pooling order involving lands you
are communitizing; or
(3) A date specified by all parties to the agreement.
(b) All CA approvals under paragraph (a) of this section are
provisional and become final only after you meet the public interest
requirement under Sec. 3133.13.
(c) The term of a CA is two years from the effective date. The term
of the CA extends as long as there is a paying well within the
communitized area, or you meet the requirements under Sec. 3140.10.

Sec. 3133.13 When does a CA meet the public interest requirement?

A CA meets the public interest requirement when you--
(a) Test a communitized formation; or
(b) BLM agrees that further drilling of a well you began under
paragraph (a) of this section is unwarranted or impracticable.

Sec. 3133.14 When does a CA terminate?

(a) A CA automatically terminates at the end of its fixed term
unless you qualify for extension under Sec. 3133.12(c).
(b) During the two-year term of the CA, you may apply for a
termination. The CA terminates when BLM approves your request.

Sec. 3133.15 What is the effect of a CA on my lease term?

(a) If there is production from a well on the CA on the date your
lease would have expired, your lease term extends until the CA
terminates.
(b) Drilling on the CA over the expiration date of your lease will
extend your lease term. (See Sec. 3140.10.)
(c) If the CA terminates and you met the public interest
requirement under Sec. 3133.13, your lease continues until the later
of--
(1) The expiration date of your lease; or
(2) Two years after the date the CA terminates.
(d) If you fail to meet the public interest requirement, the CA is
invalid from the beginning and any Federal lease that was a part of the
agreement is ineligible for any benefits of communitization. Therefore,
if the expiration date of your lease has passed, your lease is
terminated.

Sec. 3133.16 Will BLM allow more than one operator for a CA?

BLM will allow more than one operator for a CA if an application
defines--
(a) Responsibilities of respective persons, including obtaining
approvals, reporting, paying royalties and conducting operations;
(b) Which CA operator(s) is obligated to provide bond coverage; and
(c) The consequences if one or more CA operator defaults.

Sec. 3133.17 What are the requirements to change the CA operator?

(a) BLM will accept a new CA operator when the new operator--
(1) Furnishes BLM with evidence of bonding;
(2) States in writing to BLM that it accepts its CA obligations;
and
(3) Certifies that all owners of mineral rights (leased or
unleased) and lease interests (record title and operating rights) have
consented to the change in CA operator.
(b) The effective date of the change is the date BLM accepts the
new CA operator.

Sec. 3133.18 Who will BLM notify about requirements for the CA?

BLM will notify the person you named as responsible for operations,
and will communicate directly with this party for any requirements
related to the CA.

Subpart 3134--Subsurface Storage Agreements

Subsurface Storage Agreements

Sec. 3134.10 Will BLM allow subsurface storage agreements covering
Federally-owned lands?

BLM will allow you to use either leased or unleased Federally-owned
lands for the subsurface storage of oil and gas, whether or not the oil
or gas you intend to store is produced from Federally-owned lands, if
you demonstrate that storage is necessary to--
(a) Avoid waste; or
(b) Promote conservation of natural resources.

Sec. 3134.11 How do I apply for a subsurface storage agreement?

(a) You must submit an application to BLM for a subsurface storage
agreement that includes--
(1) The reason for forming a subsurface storage agreement;
(2) A description of the area you plan to include in the subsurface
storage agreement;
(3) A description of the formation you plan to use for storage;
(4) Proposed storage fees or rentals. The fees or rentals must be
based on the appraised value of the subsurface storage, injection and
withdrawal volumes, and rental income or other income generated by the
operator for letting or subletting the storage facilities;
(5) The payment of royalty for native oil or gas (oil or gas that
exists in the formation before injection and that is produced when the
stored oil or gas is withdrawn);
(6) A description of how often and under what circumstances you and
BLM intend to renegotiate fees and payments;
(7) The proposed effective date and term of the subsurface storage
agreement;
(8) Certification that all owners of mineral rights (leased or
unleased) and lease interests (record title and operating rights) have
committed or consented to the commitment of their interest in writing;
(9) An ownership schedule showing lease or land status;
(10) A schedule showing the participation factor for all parties to
the subsurface storage agreement; and

[[Page 66910]]

(11) Supporting data (geologic maps showing the storage formation,
reservoir data, etc.) demonstrating the capability of the reservoir for
storage.
(b) BLM will negotiate the terms of a subsurface storage agreement
with you for the subsurface storage of oil and gas.
(c) BLM may request additional documentation.

Sec. 3134.12 What must I pay for storage?

You must pay any combination of storage fees, rentals or royalties
to which you and BLM agree. The royalty you pay on production of native
oil and gas from leased lands will be the royalty required by the
underlying lease(s).

Subpart 3135--Development Contracts

Development Contracts

Sec. 3135.10 What is a development contract?

A development contract is an agreement among two or more persons,
at least one of whom must be a Federal lessee. Under the contract, the
parties agree to jointly explore and develop a large area when the cost
of discovery, development, production and transportation would not
justify the development of the resources on a lease or unit basis. BLM
may not approve a development contract if it is more appropriate to
unitize.

Sec. 3135.11 When will BLM approve a development contract?

(a) BLM will approve a development contract on Federal lands for
exploration in areas that are less likely than other areas to be
explored due to geologic or other factors, or to provide for large
scale development. These contracts must--
(1) Promote conservation of natural resources;
(2) Serve Federal interests; or
(3) Be for the public convenience or necessity.
(b) In return for a commitment from the operator to explore and
develop these leases at an agreed rate or cost, BLM will exempt this
acreage from chargeability.

Sec. 3135.12 What lands may I include in a development contract?

Development contracts must be of sufficient size to justify the
costs of exploration, development, production, or transportation of oil
or gas. Boundaries of one development contract may overlap the
boundaries of another development contract. Producing fields are
excluded from development contracts, unless you are--
(a) Testing a new technology that can be applied to discover
resources which are otherwise hidden; or
(b) Conducting operations based on a new geologic model which is
untested within or below all other production.

Sec. 3135.13 How do I apply for a development contract?

Submit to BLM an application for a development contract and in it
include--
(a) A map showing the total area subject to the contract;
(b) A list of all owners of mineral rights (leased or unleased) and
lease interests (record title and operating rights) for all areas and
leases in the contract;
(c) Your plan for exploration with timetables and the financial
investment you will dedicate to that exploration. BLM will accept
carryover provisions allowing the expenditures made in excess of the
contract commitment for any year to be applied against the contract in
any succeeding year or years;
(d) The effective date and term of the contract; and
(e) Penalty provisions for failure to adhere to the contract.

Sec. 3135.14 How many Federal lessees must enter into a development
contract?

At least one Federal lessee must enter into the contract and
provisions must be made to address performance obligations should any
party default or withdraw from the contract.

Sec. 3135.15 May BLM be a party to the development contract?

BLM approves the development contract but may not be a party to it.

Sec. 3135.16 May existing development contracts be renegotiated?

Existing development contracts may be renegotiated if conditions
warrant a change.

Sec. 3135.17 What must I do to satisfy my obligations under a
development contract?

You must--
(a) Commit promised financial resources toward the exploration and
development of an area;
(b) Explore the area in your exploration plan; and
(c) Provide BLM annually with information obtained from exploration
and development during the preceding contract year.

Sec. 3135.18 What information in my proposal will be held
confidentially?

A development contract proposal is public information as of the
date you submit your application. However, your work and dollar
commitments are considered financial information and BLM will hold them
confidentially to the extent authorized by the Freedom of Information
Act, as implemented by 43 CFR part 2.

Sec. 3135.19 When does a development contract terminate?

(a) A development contract terminates--
(1) Under the terms of the agreement; or
(2) At the end of any contract year, if the parties have not
fulfilled their contract commitments, through work performed in that
year together with carryover credits from prior years;
(b) Termination of a development contract triggers the provisions
of Sec. 3105.28(a)(1), which requires you to reduce your acreage
holdings to the prescribed limitations within 90 calendar days after
termination of the development contract.

Subpart 3136--Drainage Compensation Agreements

Drainage Compensation Agreements

Sec. 3136.10 What is a drainage compensation agreement?

A drainage compensation agreement is an agreement between BLM and
any other person to pay BLM for oil and gas drained. If the--
(a) Federal oil or gas is drained from a Federal lease, the--
(1) Holders of record title or operating rights must be parties to
the agreement;
(2) Lease term is extended for the period during which payments are
received plus one year; and
(3) Payment to the United States cannot be less than what the
lessee would owe as compensatory royalty under Sec. [to be specified in
the final rule].
(b) Oil and gas is drained from an unleased Federal tract--
(1) BLM and the person causing the drainage are the only parties to
the agreement; and
(2) The payment to the United States for drainage will be
negotiated between the parties; or
(c) BLM orders you to pay compensatory royalty under your lease
terms, and you pay in accordance with that order, or if BLM makes any
other determination that you owe compensatory royalty under your lease,
your payment constitutes a drainage compensation agreement for the
purposes of paragraph (a) of this section.

Sec. 3136.11 How are the terms of a drainage compensation agreement
determined?

(a) BLM will negotiate the agreement with the other parties. The
terms must include--
(1) A statement that identifies the well that is causing drainage;

[[Page 66911]]

(2) A map and legal description of the lands to be included; and
(3) The terms for compensation the United States will receive for
the drainage.
(b) If the oil and gas is drained from a Federal lease, all record
title owners and operating rights owners must consent to the agreement.

Subpart 3137--Unit Agreements

Application

Sec. 3137.10 What agreements does this subpart cover?

This subpart covers exploratory and enhanced recovery unit
agreements.
(a) An exploratory unit agreement is a BLM-approved agreement--
(1) Among interest owners of Federal leases and owners of non-
Federal mineral interests;
(2) That provides for orderly and cooperative development of all or
part of an oil or gas pool, field or like area;
(3) That allocates production from wells in participating areas to
all tracts in the participating area without regard to well location;
and
(4) That provides Federal lessees with the benefits listed in
Sec. 3132.12.
(b) An enhanced recovery unit is a BLM approved agreement that--
(1) Has the same characteristics as paragraphs (a)(1), (a)(3) and
(a)(4) of this section; and
(2) Provides for the introduction of an artificial drive or
displacement mechanism into a reservoir underlying several tracts to
produce hydrocarbons that cannot be recovered by primary methods.

Sec. 3137.11 How are the terms of an exploratory unit agreement
determined?

BLM will negotiate with you on all terms of the proposed unit
agreement before you submit an application. BLM will accept any unit
agreement format as long as it protects the public interest and
conforms with all applicable laws and regulations. BLM will determine
whether the agreement protects the public interest and includes only
terms permitted by this subpart.

Sec. 3137.12 How are the terms of an enhanced recovery unit agreement
determined?

BLM will participate in the negotiation of terms in the proposed
unit agreement before you submit an application. BLM will accept any
unit agreement format as long as it protects the public interest and
conforms with all applicable laws and regulations. Including BLM as
part of the group you form to negotiate the participation and
allocation formulae will expedite the approval process.

Sec. 3137.13 What must I include in a unitization application?

(a) Submit three copies of the unitization application and in it
include--
(1) The proposed unit agreement;
(2) A map showing the unit area and committed leases and other
tracts;
(3) A list of committed leases and other tracts;
(4) An allocation schedule for--
(i) A proposed exploratory unit that has existing production; or
(ii) A proposed enhanced recovery unit that identifies the basis
for the allocation.
(b) You must also include a description of the lands you plan to
include in the unit agreement. When you describe the lands, follow the
principles of Sec. 3121.20.
(c) Do not submit any other material with the application unless
BLM requests it.

Sec. 3137.14 As the unit operator, what must I certify in my
unitization application?

In the unitization application, as the unit operator you must
certify--
(a) That you invited all owners of mineral rights (leased or
unleased) and lease interests (record title and operating rights) for
the area described in the application to join the unit;
(b) That there are sufficient leases or other tracts committed to
the unit agreement for reasonable control of the unit area;
(c) The commitment status of all leases and other tracts within the
area proposed for unitization; and
(d) That you accept unit obligations under Sec. 3137.81.

Sec. 3137.15 As the unit operator, must I provide BLM with evidence of
commitment status in my unitization application?

Do not submit documentation of commitment status with your
unitization application. However, you or your designated agent must
maintain documentation of results of invitations to join the unit. You
must make the documentation available to BLM when we request it. The
Bureau of Indian Affairs may require documentation of commitment status
of Indian lands.

Sec. 3137.16 When is a unit agreement effective?

(a) BLM will provisionally approve exploratory and enhanced
recovery unit agreements effective the date your application is
complete.
(b) Final BLM approval is effective retroactive to the date of
provisional approval, after you have fulfilled the public interest
requirements in Sec. 3137.51 or Sec. 3137.53, as appropriate. If you do
not meet the requirements of these sections, your unit agreement is not
approved.

Sec. 3137.17 How will the parties to the unit know if BLM
provisionally approves the unit agreement?

BLM will notify the unit operator in writing when we approve or
disapprove the proposed unit agreement. The unit operator must notify
all parties to the unit agreement.

Sec. 3137.18 Why would BLM reject a unitization application?

BLM will reject a unitization application that does not meet all of
the requirements of this subpart.

Mandatory Provisions

Sec. 3137.20 What must an exploratory unit agreement include?

(a) An exploratory unit agreement must define the--
(1) Unit area;
(2) Initial and continuing development obligations; and
(3) Productivity criteria and participating areas.
(b) The exploratory unit agreement must include--
(1) A provision which grants BLM the ability to set or modify the
quantity, rate and location of development and production; and
(2) Modifications to any or all terms and conditions of the
proposed unit agreement to which the parties agreed during negotiations
with BLM.

Sec. 3137.21 What must an enhanced recovery unit agreement include?

(a) The area in an enhanced recovery unit agreement must be fully
developed at the time you propose the unit agreement. Fully developed
means that the proposed unit area has been adequately drilled to
reasonably delineate the boundaries of the reservoir(s). Therefore, an
enhanced recovery unit agreement should not include terms related to
initial and continuing development obligations and productivity
criteria and participating area size. An enhanced recovery unit
agreement must define--
(1) The unit area;
(2) Enhancement obligations;
(3) A formula allocating production throughout the entire unit area
that may consider factors other than surface acreage; and
(4) The producing intervals covered.
(b) The enhanced recovery unit must include--
(1) A provision which grants BLM the ability to set or modify the
quantity, rate and location of development and production; and
(2) Modifications to any or all terms and conditions of the
proposed unit

[[Page 66912]]

agreement to which the parties agreed during negotiations with BLM.

Sec. 3137.22 Will BLM accept or approve other terms?

A unit agreement may include only terms identified in Sec. 3137.20,
Sec. 3137.21 or Sec. 3137.30. BLM will not approve an agreement
including any other terms or provisions. Provisions not included in
this subpart may be set out under separate agreements by the affected
parties.

Optional Provisions

Sec. 3137.30 Are there any optional provisions that I may include in a
unit agreement?

(a) Except as provided in paragraphs (b) and (c) of this section,
the agreement covers all producing intervals, requires unanimous
consent for modification, and allows for only one operator at a time.
(b) Your agreement may include provisions for multiple unit
operators, limiting coverage to certain producing intervals, and
authorizing modifications not requiring approval of all of the original
parties to the unit agreement. BLM will approve these optional topics
if they promote additional development or enhance production potential.
(c) You must specify the producing interval(s) covered by an
enhanced recovery unit.

Sec. 3137.31 What are the requirements for multiple unit operators?

BLM permits multiple unit operators for exploratory units only if
the unit agreement defines--
(a) The conditions under which additional unit operators are
acceptable;
(b) The responsibilities of each operator, including obtaining
approvals, reporting, paying royalties and conducting operations;
(c) The bonds covering the operations of each operator;
(d) The consequences if one or more unit operators default; and
(e) Which unit operator is responsible for unit obligations not
specifically assigned in the unit agreement.

Sec. 3137.32 How can parties modify their unit agreement?

(a) The parties may modify their unit agreement if--
(1) All of the original parties to the unit agreement (or their
successors) agree to the modification; or
(2) They meet the requirements of the modification provision in the
unit agreement which specifies who is authorized to modify the unit
agreement. That provision must identify which parties, and what
percentage of each class of parties, must consent to each type of
modification.
(b) The operator must certify that the necessary parties have
agreed to the change.
(c) BLM must approve any proposed modifications to the unit
agreement. BLM's approval is effective retroactive to the date your
application for modification was complete. However, BLM may approve a
different effective date if you request it and provide acceptable
justification.

Sec. 3137.33 What must I submit to BLM if I propose to modify a unit
area or change the commitment status of a lease?

If you propose to modify the unit area or change the commitment
status of any lease under Sec. 3137.32, you must submit to BLM a
revised--
(a) Map showing the unit area and committed leases;
(b) List of committed leases; and
(c) Allocation schedule, including any change in the basis for
allocation.

Sec. 3137.34 What effect do other BLM oil and gas agreements have on
the unit agreement?

(a) No other BLM oil and gas agreement modifies any of the
inconsistent terms and conditions of the unit agreement or relieves the
unit operator of any right or obligation established under the unit
agreement.
(b) In case of any inconsistency or conflict between the unit
agreement and any other agreement, the unit agreement governs.

Size and Shape

Sec. 3137.40 What are the size and configuration requirements for a
unit area?

(a) The unit area must consist of tracts that are contiguous at
least at one point.
(b) Areas of noncommitted tracts totally within the exterior
boundary of the unit (windows) are allowed.
(c) BLM may limit the size and shape of the unit considering the
type, amount, rate, and location of the proposed development.

Development

Sec. 3137.50 What initial unit obligations must I define in an
exploratory unit agreement?

In an exploratory unit agreement you must define--
(a) The number of wells necessary to determine the existence of oil
and gas resources in the area of the proposed unit;
(b) A primary target(s) for each well to a depth necessary to
penetrate anticipated producing intervals; and
(c) The time between the drilling of necessary wells to interpret
drilling results and comply with lease restrictions.

Sec. 3137.51 What must I do to meet initial unit obligations and
fulfill the public interest requirement in an exploratory unit?

On or before the time specified in your exploratory unit agreement,
you must--
(a) Diligently drill the required well(s) to the primary target(s);
or
(b) Have commenced drilling to a target and BLM agrees that further
drilling of the well(s) you began under paragraph (a) of this section,
or future well(s), is unwarranted or impracticable.

Sec. 3137.52 What enhancement obligations must I define in an enhanced
recovery unit agreement?

Your enhanced recovery unit agreement must define as enhancement
obligations--
(a) The amount and type of enhanced recovery operations; and
(b) The timeframe for completing the operations in paragraph (a) of
this section.

Sec. 3137.53 What must I do to meet enhancement obligations and
fulfill the public interest requirement in an enhanced recovery unit?

On or before the time specified in your enhanced recovery unit
agreement to meet the enhancement obligations and fulfill the public
interest requirement, you must--
(a) Diligently complete the work you defined as your enhancement
obligation in Sec. 3137.52; or
(b) Demonstrate to BLM's satisfaction that--
(1) Enhanced recovery operations have increased reservoir
performance; or
(2) Further enhanced recovery operations are unwarranted,
impracticable or uneconomical.

Sec. 3137.54 What happens if I do not meet initial unit obligations in
an exploratory unit or enhancement obligations in an enhanced recovery
unit?

If you do not meet the requirements of Sec. 3137.51 or
Sec. 3137.53, the unit agreement is invalid from the beginning, will
not receive final approval, and any Federal lease that was a part of
the unit agreement is ineligible for any benefits from unitization
described in Sec. 3132.12. Therefore, for example, if the expiration
date of your lease has passed, your lease is terminated.

Sec. 3137.55 What are continuing development obligations?

Continuing development obligations for an exploratory unit are a
program of development or operations you must conduct--

[[Page 66913]]

(a) That exceeds the rate of development and operation that would
have occurred in the area without unitization; and
(b) Which represents an investment commensurate with the size of
the area of the unit agreement.

Sec. 3137.56 How must I define continuing development obligations in
the unit agreement?

(a) Once you meet initial unit obligations prescribed in this
subpart, you must perform additional development or operations (see
Sec. 3137.80) in the amount and frequency specified in your unit
agreement. BLM will not consider work you did before unitization as
meeting continuing development obligations.
(b) You must define in the agreement the time between when you
start your first development or operations to the start of the next
development or operation. You must define the same time-frames for
subsequent development or operations.

Sec. 3137.57 Must I perform additional development outside established
participating areas to fulfill continuing development obligations?

Your additional development may be either inside or outside of a
participating area to fulfill your continuing development obligations,
depending on the terms of the unit agreement.

Sec. 3137.58 What happens if I do not meet a continuing development
obligation?

(a) The unit contracts when you do not meet a continuing
development obligation. Only established participating areas, whether
they are still productive or not, remain in the unit. BLM will
eliminate all portions of the unit outside participating areas at the
time of contraction. Contraction is effective the first day of the
month in which the unit agreement required the operations to begin.
(b) BLM may suspend or extend a development obligation under
Secs. 3137.90 and 3137.91. BLM may also modify your development
obligations under Sec. 3137.32.

Sec. 3137.59 What must I submit to BLM after I meet a continuing
development obligation?

Within 60 calendar days after you meet a continuing development
obligation, you must certify to BLM that you met the obligation. BLM
may require you to supply documentation supporting your certification.
If you establish production in a well that does not meet the
productivity criteria set out in the unit agreement, you must also
certify to BLM that you will operate, produce and report the well on a
lease basis, rather than as part of the unit.

Productivity Criteria and Participating Area

Sec. 3137.60 What are productivity criteria?

(a) Productivity criteria are characteristics of a well in an
exploratory unit that warrant including a defined area surrounding the
well in a participating area. The unit agreement must define these
criteria for each separate producing interval. You must be able to
determine whether you met the criteria when the well has been drilled
and well testing completed.
(b) To meet the productivity criteria the well must--
(1) Indicate future production potential sufficient to pay for the
costs of drilling, completing and operating the well on a unit basis;
and
(2) Be physically ready to produce unitized substances.

Sec. 3137.61 What is a participating area and what is its function?

(a) A participating area is the area which shares in the production
of unitized substances. Allocation to each committed lease or tract
within the participating area is in the same proportion as that lease's
surface acreage within the participating area.
(b) The approximate size and shape of all participating areas and
revisions must be defined in the unit agreement.

Sec. 3137.62 What establishes a participating area?

The first well you drill after unitization that meets the
productivity criteria establishes an initial participating area. When
you establish that initial participating area, lands which contain
previously existing wells that meet the productivity criteria will, in
accordance with Sec. 3137.63,--
(a) Be added to that initial participating area as a revision; or
(b) Become a separate participating area.

Sec. 3137.63 What happens to the participating area when new wells are
drilled that meet the productivity criteria?

If a new well is--
(a) Inside a participating area boundary and completed in the same
producing interval, the participating area will remain the same;
(b) Outside a participating area boundary and completed in the same
producing interval as the well in an existing participating area, the
participating area expands to include the new area; or
(c) In a different producing interval, inside or outside a
participating area, a new participating area is established for the
well. Participating areas for different producing intervals can overlap
each other.

Sec. 3137.64 What must I submit to BLM when I establish a
participating area or add to an existing participating area?

(a) When you establish a participating area under Sec. 3137.62 or
add to an existing participating area under Sec. 3137.63, within 60
calendar days after you establish unitized production, you must submit
to BLM--
(1) Certification that you established unitized production;
(2) A map showing the participating area and total acreage;
(3) A schedule showing the production allocation for each tract
participating in production; and
(4) Any other information BLM may require.
(b) BLM will review your submission and determine if you have met
the unit agreement terms for establishing a participating area.

Sec. 3137.65 Must additions to an existing participating area be the
same size as the initial participating area?

Additions to an existing participating area involving the same
producing interval must be approximately the same size as the initial
participating area for that producing interval.

Sec. 3137.66 Must participating areas for different producing
intervals be the same size?

Participating areas (both initial and additions) for different
producing intervals may be different sizes (see Sec. 3137.61) and may
overlay or underlie other participating areas.

Sec. 3137.67 How do I allocate participating area production when
there are unleased Federal lands in the participating area?

(a) For royalty purposes only, you must allocate production to
unleased Federal lands in the participating area as if the acreage were
committed to the participating area under Sec. 3137.61. You must pay
royalty in accordance with Sec. 3137.111.
(b) For purposes other than royalty, apply Sec. 3137.61, excluding
unleased Federal lands.

Sec. 3137.68 What if unleased Federal lands are leased after the
effective date of the unit agreement?

You must admit Federal tracts leased after the effective date of
the unit agreement into the agreement on the date the lease is
effective.

[[Page 66914]]

Sec. 3137.69 What happens when a well outside any participating area
does not meet the productivity criteria?

If a well outside any of the established participating areas does
not meet the productivity criteria, all operations on that well are
non-unit operations. No participating area is expanded and you must
notify BLM that non-unit operations have occurred. You must conduct
non-unit operations under the terms of the underlying lease, CA, or
drainage compensation agreement.

Sec. 3137.70 How does allocation of production occur from wells that
do not meet the productivity criteria?

(a) If a well that does not meet the productivity criteria was
drilled before the unit was formed, the production is allocated on a
lease, communitization or drainage compensation agreement basis.
Production from the well is not considered unitized substances and you
must pay and report the royalties from any such well as specified in
the underlying lease, CA or drainage compensation agreement.
(b) If a well was drilled after the unit was formed and the well is
completed within an existing participating area, the production is
added to and becomes a part of that participating area production. This
paragraph applies whether or not the well meets the productivity
criteria.
(c) If a well that does not meet the productivity criteria is
outside a participating area, the production is allocated the same as
under paragraph (a).

Sec. 3137.71 Who must operate wells that do not meet the productivity
criteria?

(a) If a well that does not meet the productivity criteria was
drilled before the unit was formed, the operator of the well at the
time the unit was formed continues as operator. The unit operator is
not required to operate the wells, but it may do so.
(b) As unit operator, you must operate wells drilled after unit
formation that do not meet the established productivity criteria, until
you change operators for that well.

Sec. 3137.72 May a well BLM previously determined to be a non-unit
well establish or revise a participating area?

If you, as the unit operator, complete sufficient work so that a
well BLM previously determined to be a non-unit well now meets the
productivity criteria and you demonstrate this to BLM, you must then
revise or establish a new participating area. When this occurs, you
must notify BLM (see Sec. 3137.64).

Sec. 3137.73 What is the effective date of an initial participating
area or revision to an existing participating area?

The effective date of a participating area or its revision is the
first day of the month in which a well is completed that causes the
participating area to be formed or revised, but no earlier than the
effective date of the unit.

Sec. 3137.74 How long does a participating area remain in effect?

(a) Until the unit contracts under Sec. 3137.58, all participating
areas remain in effect.
(b) After unit contraction, a participating area remains in effect
until BLM notifies you that there is insufficient production to meet
operating costs of the participating area. However, your participating
area will not terminate if, after you receive notice, you demonstrate
to BLM that--
(1) Operations to restore production or establish new production
are--
(i) In progress within 60 calendar days of BLM notification;
(ii) Being diligently carried out to completion; and
(iii) Successful in restoring or establishing production sufficient
to meet operating costs; or
(2) One or more wells within the participating area are capable of
producing in quantities sufficient to meet operating costs.

Unit Operations

Sec. 3137.80 What is unit development or operations?

Any of the following are unit development or operations--
(a) Drilling additional wells that test the primary target or
enhance production;
(b) Drilling additional wells that establish production of unitized
substances;
(c) Well recompletions or operations that establish new unitized
production or enhance existing production;
(d) Drilling existing wells to a deeper target; or
(e) Drilling, completing or recompleting wells that contribute to
the productivity of the unit.

Sec. 3137.81 As unit operator, what are my obligations?

(a) As a unit operator, you must comply with the terms and
conditions of the unit agreement, Federal laws and regulations,
applicable lease terms and stipulations not expressly waived by BLM,
and BLM orders.
(b) Once a unit is formed, you are responsible for all wells
drilled on lands committed to the unit unless--
(1) BLM approves multiple unit operators under Sec. 3137.31 and
another unit operator drills that well; or
(2) A well does not meet the productivity criteria and is not
operated as a unit well (see Sec. 3137.71).

Sec. 3137.82 What must I file with BLM to change the unit operator?

To change unit operators, the new unit operator must file--
(a) Statements that--
(1) It accepts unit obligations; and
(2) The percentage of interest owners required by the agreement
consented to a change of unit operator; and
(b) Evidence of acceptable bonding under subpart 3107.

Sec. 3137.83 When does my liability as unit operator end?

You are responsible for all duties and obligations of the unit
agreement until BLM approves a new unit operator. The change of the
unit operator does not release you from any liability for noncompliance
with obligations that accrued before the effective date of the change.

Sec. 3137.84 As a unit operator, what must I do to prevent or
compensate for drainage?

(a) You must take measures to prevent, or compensate for, drainage
of oil and gas from unitized land by wells--
(1) On tracts not committed to the unit; or
(2) Not operated as unit wells.
(b) Acceptable measures to prevent, or compensate for, drainage
include, but are not limited to, drilling a protective well, entering
into a CA, or paying drainage compensation.

Suspensions and Extensions of Development

Sec. 3137.90 As the unit operator, what happens if I cannot meet unit
requirements for reasons outside of my control?

BLM will suspend development obligations under the unit agreement
if you are prevented from complying with unit requirements, despite the
exercise of due care and diligence. BLM may approve suspensions of
drilling operations for all unitized lands or specific lands within the
unit.

Sec. 3137.91 Will BLM grant an extension of time to meet the initial
or continuing development obligations?

Under limited circumstances, such as inclement weather, rig
unavailability, or litigation, BLM may grant reasonable extensions of
time to meet the development obligations of your unit agreement. This
extension does not toll the running of any individual lease term. See
subpart 3141 for Federal lease suspensions.

[[Page 66915]]

Unit Termination

Sec. 3137.100 Under what circumstances will BLM approve a voluntary
unit termination?

BLM may approve the voluntary termination of the unit at any time--
(a) Before the unit operator discovers production sufficient to
establish a participating area; and
(b) The unit operator certifies that at least 75 percent of the
operating rights owners in the unit agreement, on a surface acreage
basis, agree to the termination.

Sec. 3137.101 What if I do not meet a continuing development
obligation before any participating area has been established in the
unit?

If you do not meet a continuing development obligation before any
participating area is established, the unit terminates automatically.
Termination is effective the day after you failed to meet a continuing
development obligation.

Sec. 3137.102 After participating areas are established, when does the
unit terminate?

After participating areas are established, the unit terminates when
the last participating area of the unit terminates.

Royalties

Sec. 3137.110 How is unit production from an exploratory unit
agreement allocated?

Allocate production within participating areas of an exploratory
unit agreement in proportion to each tract's share of the surface
acreage within the participating area.

Sec. 3137.111 What is the royalty rate for unleased Federal lands in a
participating area?

Whenever a participating area or enhanced recovery unit includes
unleased Federal lands, you must pay a royalty to the United States
based on a royalty rate not less than the highest royalty rate for any
Federal lease committed to the unit. Payment accrues from the later of
the dates--
(a) Committed leases in the participating area or enhanced recovery
receive a production allocation; or
(b) The Federal lands become unleased.

Sec. 3137.112 What is average daily production for a Federal lease
committed to a unit where the royalty rate depends on average daily
production?

For a Federal lease on which the royalty rate depends on the
average daily production per well (for example, sliding-scale or step-
scale leases), the unit operator must determine average production
according to subpart 3106, as though the participating area, or in the
case of an enhanced recovery unit, the entire unit area, were a single
Federal lease.

Sec. 3137.113 May the United States take an in-kind royalty share of
unit production?

(a) For a Federal lease committed to a unit agreement, the United
States may take its royalty in-kind at its election.
(b) The operator of the well from which the royalty is taken in-
kind must store and make deliveries of such production according to
applicable laws, lease terms and regulations.

Leases and Contracts Conformed and Extended

Sec. 3137.120 As the unit operator, must I develop and operate on
every tract in the unit to comply with the development obligations of
the underlying leases, contracts or agreements (other than unit
agreements)?

When BLM approves a unit agreement, the terms, conditions and
provisions of all committed Federal leases, subleases and other
contracts are amended to the extent necessary to conform to the
provisions of the unit agreement until the lease no longer is committed
to the unit. In all other respects they remain in full force and
effect. If you fully perform initial unit and continuing development
obligations, you have fully performed the development obligations of
the committed leases.

Change in Ownership

Sec. 3137.130 As a transferee of an interest in a unitized Federal
lease, am I subject to the terms and conditions of the unit agreement?

Any interest in a Federal lease committed to a unit agreement that
you acquire by transfer is subject to the terms and conditions of the
unit agreement.

PART 3140--[AMENDED]

8. Revise the authority citation for part 3140 to read as follows:

Authority: 30 U.S.C. 189, 351-359 and 43 U.S.C. 1732(b).

PART 3140--[REDESIGNATED as 3170]

9. Redesignate part 3140--Combined Hydrocarbon Leasing as part
3170.
10. Add new part 3140 to read as follows:

PART 3140--OIL AND GAS LEASE ADMINISTRATION

Subpart 3140--Extensions

Lease Extensions and Drilling Extensions

Sec.
3140.10 Will BLM extend my lease if I drill before the lease
expires?
3140.11 What are actual drilling operations?

Continuation by Production

3140.20 Does my lease continue in effect if I establish production
before the primary term expires?
3140.21 If my lease is in its extended term and I stop producing,
will it terminate?
3140.22 If my lease is in its extended term and capable of
production, and is shut-in, will it terminate?

Unit or Communitization Agreement Production

3140.30 Does my lease continue beyond its primary term if it is
committed to a CA or unit agreement under which production in paying
quantities has been established?

Unit Segregations

3140.40 What is the status of my lease if only part of it is
committed to a unit agreement?
3140.41 What is the effective date of the segregation?
3140.42 If my lease is segregated into two leases, is my segregated
lease extended?

Elimination from Agreements

3140.50 Will BLM extend my lease if it is eliminated from an
agreement?

Leases Segregated by Assignment

3140.60 What is the term of my lease if it is segregated into two
or more leases by a partial transfer?

Payment of Compensatory Royalty

3140.70 Will BLM extend my lease if I am paying compensatory
royalty on the lease?

Leases Used for Surface Storage of Oil or Gas

3140.80 Will BLM extend my lease if I am using it to store oil or
gas?

Subpart 3141--Suspensions

Suspensions of Operations For Production

3141.10 Under what circumstances will BLM suspend operations or
suspend production on my lease under 30 U.S.C. 226(i)?
3141.11 Under what circumstances will BLM approve my request under
30 U.S.C. 209 for a suspension of operations and production for my
lease?
3141.12 How do I apply for a suspension?
3141.13 When is a suspension effective?
3141.14 When is my next rental or minimum royalty payment due after
the effective date of my suspension of operations and production?
3141.15 When will my suspension terminate?

[[Page 66916]]

3141.16 What happens when my suspension terminates?

Suspension or Waiver of Lease Rights

3141.20 When may a suspension of my lease rights occur?
3141.21 How do I request a suspension of lease rights?
3141.22 How will suspension under this subpart affect my lease?
3141.23 When will my lease suspension end?

Subpart 3142--Terminations and Reinstatements

Lease Terminations and Reinstatements

3142.10 What happens if the Minerals Management Service (MMS) does
not receive my advance annual rental payment on or before the
anniversary date of my lease?
3142.11 Will my lease terminate if my rental payment is deficient?

Class I Reinstatements

3142.20 Under what circumstances will BLM reinstate my lease
without an increase in royalties and rentals (Class I)?
3142.21 What must I do before BLM will reinstate my lease under
Class I?

Class II Reinstatements

3142.30 Under what circumstances will BLM reinstate my lease with
an increase in royalty rate and rentals (Class II)?
3142.31 What must happen before BLM will reinstate my lease under
Class II?
3142.32 How much are the rentals or royalties under a Class II
reinstatement?
3142.33 Are there circumstances under which BLM will not consider
my petition for reinstatement?
3142.34 Will BLM extend the term of my lease if I do not have a
reasonable opportunity to begin or continue operations following a
reinstatement?

Class III Conversions from Unpatented Mining Claims

3142.40 Under what circumstances will BLM convert my unpatented oil
placer mining claim to an oil and gas lease?
3142.41 What must I include with my Class III petition for issuance
of a noncompetitive oil and gas lease?

Subpart 3143--Relinquishments

Relinquishments

3143.10 May I relinquish all or part of my lease?
3143.11 Where do I file a lease relinquishment?
3143.12 Is there a filing fee or official form I must use?
3143.13 Does a relinquishment entitle me to a return of any rental
payment on a pro rata monthly basis?
3143.14 Who must sign the relinquishment application?
3143.15 If I own only part of the record title (a co-lessee), may I
relinquish only my interest?
3143.16 If I own all or part of the operating rights in a lease,
but no record title, may I relinquish my operating rights to BLM?
3143.17 When is a relinquishment effective?
3143.18 What are my obligations after I file the relinquishment?

Subpart 3144--Cancellations

Cancellations

3144.10 Under what circumstances will BLM cancel my lease?
3144.11 May BLM cancel my lease if it issued it improperly?
3144.12 If I own or control an interest in a lease in violation of
the provisions of the Act, what will BLM do?

Bona Fide Purchasers

3144.20 Will BLM cancel my lease if I am a bona fide purchaser and
I purchased it from someone who acquired it in violation of the Act?
3144.21 What is a bona fide purchaser?

Authority: 16 U.S.C. 3150(b) and 668dd; 30 U.S.C. 189, 306 and
359; 43 U.S.C. 1733, 1734 and 1740; and 10 U.S.C.A. 7439.

Subpart 3140--Extensions

Lease Extensions and Drilling Extensions

Sec. 3140.10 Will BLM extend my lease if I drill before the lease
expires?

(a) BLM will extend the primary term of your lease for two years if
you are diligently conducting actual drilling operations described in
Sec. 3140.11 on the last day of the primary lease term and continue
thereafter to a depth sufficient to penetrate at least one formation
recognized in the area as potentially able to produce oil or gas. To
meet this obligation if you are reentering a well, you must either
drill it to a depth sufficient to penetrate at least one new and deeper
formation recognized in the area as potentially able to produce, or use
horizontal drilling to test any formation that is recognized as having
a potential for oil and gas production.
(b) If BLM determines that you were unable to conduct actual
drilling operations on the last day of your primary lease term, due to
severe weather or other justifiable cause, your lease is extended under
paragraph (a) of this section if you promptly resume and diligently
continue your drilling operations to completion when the reason for the
drilling cessation no longer exists.
(c) This section applies to leases committed to a unit or
communitization agreement if you conduct actual drilling operations in
the agreement area.

Sec. 3140.11 What are actual drilling operations?

Actual drilling operations are operations you conduct that are
similar to those that anyone looking for oil or gas could be expected
to conduct in that particular area, given the existing knowledge of
geologic and other facts pertinent to drilling for oil and gas. The
term includes the testing, completing, or equipping of the drill hole
(casing, tubing, packers, pumps, etc.) so that it is capable of
producing hydrocarbons.

Continuation by Production

Sec. 3140.20 Does my lease continue in effect if I establish
production before the primary term expires?

If you establish production in paying quantities before the end of
the primary lease term, your lease continues in effect for as long as
you produce oil or gas in paying quantities.

Sec. 3140.21 If my lease is in its extended term and I stop producing,
will it terminate?

Except as provided in Sec. 3140.22, if your lease is in its
extended term, it terminates when you stop producing unless, within 60
calendar days after you stop production, you restart production or you
conduct reworking or commence drilling operations with reasonable
diligence and restore the lease to production.

Sec. 3140.22 If my lease is in its extended term and capable of
production, and is shut-in, will it terminate?

If your lease is in its extended term and is capable of production,
but it is shut-in, your lease will not automatically terminate when you
stop producing. However, if BLM notifies you in writing by registered
or certified mail that you must resume production, you have 60 calendar
days from receipt of the notification to resume production or your
lease will terminate.

Unit or Communitization Agreement Production

Sec. 3140.30 Does my lease continue beyond its primary term if it is
committed to a CA or unit agreement under which production in paying
quantities has been established?

(a) If your lease is committed to a CA or unit agreement, your
lease continues beyond its primary term by production established
within the agreement area if--
(1) The CA or unit agreement contains a general provision for
allocation of oil or gas; and
(2) You established production in paying quantities under the
agreement before your lease expired.
(b) This section also applies to 20-year leases.

[[Page 66917]]

Unit Segregations

Sec. 3140.40 What is the status of my lease if only part of it is
committed to a unit agreement?

BLM will segregate any lease committed to a unit agreement if part
of the lands in the lease are outside the area covered by the
agreement. BLM will segregate your lease into two leases, one covering
lands committed to the agreement and the other covering lands outside
the unit area.

Sec. 3140.41 What is the effective date of the segregation?

The effective date of lease segregation is the effective date of
the unit agreement to which part of the lease is committed.

Sec. 3140.42 If my lease is segregated into two leases, is my
segregated lease extended?

If your lease is segregated under Sec. 3140.40, BLM will grant a
two-year lease term extension for the lands outside the unit, if the
original lease is due to expire less than two years from the effective
date of segregation. The two-year extension begins with the effective
date of segregation.

Elimination From Agreements

Sec. 3140.50 Will BLM extend my lease if it is eliminated from an
agreement?

If your lease is eliminated from a unit agreement or CA, and if the
term remaining in your lease is less than two years, BLM will grant a
two-year lease term extension from the effective date of--
(a) Termination of an agreement to which your lease was committed;
or
(b) Elimination of your lease from a unit agreement when it
contracts.

Leases Segregated by Assignment

Sec. 3140.60 What is the term of my lease if it is segregated into two
or more leases by a partial transfer?

(a) If a lease in its primary term is segregated into two or more
leases as a result of a partial transfer of record title, the term of
the original lease and the newly-designated leases is the term of the
original lease, except as provided in paragraph (b) of this section.
(b) If BLM determines after segregation that oil and gas is
discovered in paying quantities on either the original lease or the
newly-designated leases, the term of the leases in paragraph (a) of
this section cannot be less than two years after the date of BLM's
determination.
(c) If a lease issued--
(1) After September 2, 1960, in its extended term under
Sec. 3140.20 is segregated into two or more leases as a result of a
partial transfer of record title, the original lease and any newly-
designated leases not held by production on the date of transfer are
extended for two years after that date; or
(2) On or before September 2, 1960, is in its extended term for any
reason, paragraph (c)(1) of this section applies.
(d) If BLM extends your lease and you establish production, your
lease will continue so long as it is capable of production in paying
quantities.

Payment of Compensatory Royalty

Sec. 3140.70 Will BLM extend my lease if I am paying compensatory
royalty on the lease?

BLM will extend your lease for the period that BLM receives
compensatory royalty under Sec. 3136.10. Your lease also will be
extended for one year from the date BLM determines you are no longer
required to pay compensatory royalty.

Leases Used for Subsurface Storage of Oil or Gas

Sec. 3140.80 Will BLM extend my lease if I am using it to store oil or
gas?

BLM will extend your lease during the period of storage under an
approved subsurface oil or gas storage agreement. You must continue to
pay rental for your lease during the extended period.

Subpart 3141--Suspensions

Suspensions of Operations or Production

Sec. 3141.10 Under what circumstances will BLM suspend operations or
suspend production on my lease under 30 U.S.C. 226(i)?

(a) BLM will suspend operations or suspend production for your
lease under 30 U.S.C. 226(i) if, despite the exercise of due care and
diligence, you are prevented from operating or producing your lease due
to circumstances beyond your control. BLM either may direct a
suspension under this section or approve your request for a suspension.
(b) If BLM issues a suspension under paragraph (a) of this section,
the suspension stops the running of your lease term and thereby extends
it by the length of time the suspension is in effect. However, while
the suspension is in effect, you are not relieved of your obligation to
pay rent, royalty, or minimum royalty.

Sec. 3141.11 Under what circumstances will BLM approve my request
under 30 U.S.C. 209 for a suspension of operations and production for
my lease?

BLM will suspend operations and production for your lease under 30
U.S.C. 209, if BLM determines that it is in the interest of
conservation. BLM either may direct a suspension under this section or
approve your request for a suspension. If BLM suspends operations and
production under this section, the suspension--
(a) Stops the running of your lease term and thereby extends it by
the length of time the suspension is in effect;
(b) Relieves you of your obligation to pay rent or minimum royalty
during the suspension; and
(c) Does not allow you to operate on, produce from, or have any
other beneficial use of your lease during the suspension.

Sec. 3141.12 How do I apply for a suspension?

(a) To apply for a suspension, you must submit to BLM an
application that--
(1) States what type of suspension you are applying for (whether
you are applying for a suspension under Sec. 3141.10 or Sec. 3141.11);
and
(2) Identifies the circumstances that prevent you from operating or
producing your lease that are beyond your reasonable control or that
justify a suspension in the interest of conservation.
(b) Your suspension application must be signed by--
(1) All operating rights owners; or
(2) The operator on behalf of the operating rights owners of the
leases committed to an approved agreement.
(c) You must submit your application to BLM before your lease
expires.
(d) Your application must be for your entire lease.
(e) If your suspension application relates to your ability to
timely drill a new well or reenter an existing well, BLM will approve
your application only if you submitted an Application for Permit to
Drill or Reenter or Notice of Staking at least 31 calendar days before
the lease expires.

Sec. 3141.13 When is a suspension effective?

A suspension is effective--
(a) The date BLM specifies in a directed suspension; or
(b) The first day of the month in which you file an application for
suspension, unless BLM specifies a different date on the approval
document.

Sec. 3141.14 When is my next rental or minimum royalty payment due
after the effective date of my suspension of operations and production?

After BLM approves your suspension of operations and production
under Sec. 3141.11, the date your next rental or minimum royalty
payment is due is

[[Page 66918]]

extended by the length of the suspension.

Sec. 3141.15 When will my suspension terminate?

Your suspension under Sec. 3141.10 or Sec. 3141.11 terminates the
earlier of --
(a) The first day of the month in which you begin to produce on
your lease in the case of a suspension of production;
(b) The first day of the month in which actual operations begin in
the case of a suspension of operations; or
(c) A date BLM specifies.

Sec. 3141.16 What happens when my suspension terminates?

(a) Your lease term is extended by the length of time the
suspension was in effect.
(b) Your obligation to pay rental, royalty or minimum royalty
resumes the first day the termination of the suspension is effective.

Suspension or Waiver of Lease Rights

Sec. 3141.20 When may a suspension of my lease rights occur?

BLM may suspend your lease during a legal proceeding to cancel your
lease or to require forfeiture or divestiture of your interests as a
result of a violation of any of the provisions of the regulations in
this title or the lease terms. This suspension may occur when BLM
directs it or when you request it.

Sec. 3141.21 How do I request a suspension of lease rights?

(a) When you request a suspension of lease rights, you must file in
the BLM State Office with jurisdiction over the lands, a waiver of your
rights to--
(1) Drill under the lease; and
(2) Transfer your lease interests.
(b) All interest owners for a lease must sign the waiver request.

Sec. 3141.22 How will suspension under this subpart affect my lease?

A suspension under this subpart--
(a) Stops the running of your lease term. If your lease is not
canceled, your lease term is extended by the length of the suspension;
(b) Suspends your obligation to pay rental or minimum royalties
beginning the date the suspension is effective. The date your next
rental or minimum royalty payment is due is extended by the length of
the suspension;
(c) Prevents you from conducting any operations on the lease; and
(d) Prevents you from transferring your interest.

Sec. 3141.23 When will my lease suspension end?

The suspension of your lease under this subpart ends the first day
of the month following--
(a) The final decision in the legal proceeding described in
Sec. 3141.20; or
(b) When BLM revokes your suspension.

Subpart 3142--Terminations and Reinstatements

Lease Terminations and Reinstatements

Sec. 3142.10 What happens if the Minerals Management Service (MMS)
does not receive my advance annual rental payment on or before the
anniversary date of my lease?

If MMS does not receive your rental payment on or before the
anniversary date of your lease, your lease automatically terminates by
operation of law unless the lease is committed to a producing unit
agreement.

Sec. 3142.11 Will my lease terminate if my rental payment is
deficient?

(a) Your lease will terminate if your rental payment to MMS is
deficient unless--
(1) You paid your rental on or before its anniversary date, but the
amount you paid is deficient by not more than 10 percent or $200,
whichever is less;
(2) Your deficient payment was due to an incorrect billing
statement; or
(3) Your deficient payment was due to a decision from BLM that
contained an incorrect acreage or payment figure.
(b) You must submit the full balance due to MMS within 15 business
days from the date you receive notice to correct the deficiency. If you
do not correct the deficiency within the time allowed, your lease
automatically terminates as of the anniversary date of the lease.

Class I Reinstatements

Sec. 3142.20 Under what circumstances will BLM reinstate my lease
without an increase in royalties and rentals (Class I)?

(a) If MMS receives your rental payment after the due date, but the
envelope MMS receives containing your payment is postmarked by the
United States Postal Service, or is dated as received at a courier or
other delivery service on or before the lease anniversary date, you may
request BLM to reinstate your lease under the Class I reinstatement
provisions.
(b) If your rental is not paid by the lease anniversary date, but
is paid within 20 calendar days of the anniversary date, BLM may decide
to reinstate your lease. You must provide BLM with documentation
showing the late payment was justified or not due to a lack of
reasonable diligence. Reasons include, but are not limited to --
(1) An Act of God or natural disaster;
(2) A documented illness, hospitalization, or death which caused
the delay in payment; or
(3) A statement from your bank that nonpayment was due to bank
error.

Sec. 3142.21 What must I do before BLM will reinstate my lease under
Class I?

To request a lease reinstatement from BLM, submit to BLM a petition
for reinstatement and a $25 filing fee. When petitioning under
Sec. 3142.20, you must provide BLM with documentation supporting your
request for reinstatement.

Class II Reinstatements

Sec. 3142.30 Under what circumstances will BLM reinstate my lease with
an increase in royalty rate and rentals (Class II)?

(a) BLM will grant a Class II reinstatement with an increased
rental and royalty rate if you did not pay your rental within 20
calendar days of the anniversary date and your failure to pay was--
(1) Justifiable or not due to lack of reasonable diligence; or
(2) Due to inadvertence.
(b) Under paragraph (a) of this section, you must pay your rental
within 60 calendar days from receipt of BLM's Termination Notice issued
under Sec. 3106.23, or if BLM does not send you a Termination Notice,
you must pay within 15 months from the date of lease termination.

Sec. 3142.31 What must happen before BLM will reinstate my lease under
Class II?

(a) You must submit to BLM by the dates required for payment under
Sec. 3142.30(b)--
(1) A petition for reinstatement along with a $500 nonrefundable
administrative fee;
(2) Payment of back rentals and royalties and BLM's cost of
publishing the proposed reinstatement in the Federal Register under
Sec. 3142.30(a); and
(3) An agreement to the new lease terms signed by all record title
owners.
(b) BLM will publish in the Federal Register a notice that we
propose to reinstate your lease under Sec. 3142.30 at least 30 calendar
days before we reinstate it.

Sec. 3142.32 How much are the rentals or royalties under a Class II
reinstatement?

(a) After your first Class II reinstatement, rental for a
noncompetitive lease is $5 per acre or fraction of an acre and for a
competitive lease it is $10 per acre or fraction of an acre.

[[Page 66919]]

(b) For each subsequent reinstatement, BLM will increase rentals by
an additional $5 per acre or fraction of an acre for noncompetitive
leases and an additional $10 an acre or fraction of an acre for
competitive leases.
(c) BLM will increase the royalty rate to 16\2/3\ percent on
noncompetitive leases for the first reinstatement and two additional
percentage points for each succeeding reinstatement.
(d) BLM will increase your royalty rate no less than four
percentage points above the rate in the terms of competitive leases
(i.e., not less than 16\1/2\ percent), and will add two percentage
points for each succeeding reinstatement.
(e) The royalty rates required for reinstated leases under this
section do not affect your right to a royalty rate reduction under
subpart 3106.

Sec. 3142.33 Are there circumstances under which BLM will not consider
my petition for reinstatement?

BLM will not consider your petition for reinstatement if--
(a) You do not file your petition timely under Sec. 3142.30;
(b) BLM issues a valid lease to another person before you file a
petition for reinstatement; or
(c) The oil and gas interests in the lands have been disposed of or
are not available for leasing.

Sec. 3142.34 Will BLM extend the term of my lease if I do not have a
reasonable opportunity to begin or continue operations following a
reinstatement?

If BLM finds that the time remaining in your lease term after
reinstatement will not give you a reasonable opportunity to begin or
continue operations, BLM may extend the term. The extension will not
exceed the greater of--
(a) The period equal to the unexpired portion of the lease, or any
extension, remaining at the date of termination; or
(b) Two years beyond the date BLM reinstated the lease, if BLM
granted the reinstatement after the lease expired.

Class III Conversions from Unpatented Mining Claims

Sec. 3142.40 Under what circumstances will BLM convert my unpatented
oil placer mining claim to an oil and gas lease?

BLM will convert your unpatented oil placer mining claim to an oil
and gas lease for the lands covered by the claim if--
(a) Your placer mining claim is currently producing or is capable
of producing oil or gas;
(b) BLM determined that your placer mining claim was conclusively
abandoned for failure to timely file the required instruments to record
your claim as required by section 314 of the Federal Land Policy and
Management Act (43 U.S.C. 1744, as amended and supplemented);
(c) You file a Class III conversion petition within 120 calendar
days of receiving BLM's, or a court of competent jurisdiction's, final
notification that the oil placer mining claim has been determined to be
abandoned;
(d) You show to BLM's satisfaction that failure to timely file the
required instruments was inadvertent, justifiable, or not due to lack
of reasonable diligence on the part of the owner of the claim; and
(e) There is not a valid oil and gas lease affecting any of the
covered lands.

Sec. 3142.41 What must I include with my Class III petition for
issuance of a noncompetitive oil and gas lease?

Your petition for issuance of a noncompetitive oil and gas lease to
replace your unpatented oil placer mining claim must include--
(a) A nonrefundable administrative fee of $500;
(b) The location notices of all unpatented oil placer mining claims
and, if the petitioner is not the owner(s) of unpatented mining claims,
a copy of a power of attorney on behalf of the owner(s);
(c) The required annual rental of $5 per acre or royalty of 12\1/2\
percent, or both, including any back rental or royalty, or both,
accruing from the statutory date of abandonment of your claim; and
(d) A statement agreeing to reimburse BLM for the full costs
incurred for publishing the notice of the proposed conversion of the
oil placer mining claim to a noncompetitive oil and gas lease in the
Federal Register.

Subpart 3143--Relinquishments

Relinquishments

Sec. 3143.10 May I relinquish all or part of my lease?

You may relinquish all of your lease or any legal subdivision of
your lease. Identify the lands you do not want to retain by legal land
description as in Sec. 3121.20.

Sec. 3143.11 Where do I file a lease relinquishment?

You must file a lease relinquishment in the BLM State Office with
jurisdiction over the lands in your lease.

Sec. 3143.12 Is there a filing fee or official form I must use?

There is no filing fee or official form for a relinquishment.

Sec. 3143.13 Does a relinquishment entitle me to a return of any
rental payment on a pro rata monthly basis?

If you file your relinquishment--
(a) Before the next anniversary date of your lease, the Minerals
Management Service (MMS) will refund any rental you paid for the next
lease year; or
(b) After the anniversary date, MMS will not refund any rental for
the current year.

Sec. 3143.14 Who must sign the relinquishment application?

All record title owners must sign the relinquishment. BLM requires
original signatures.

Sec. 3143.15 If I own only part of the record title (a co-lessee), may
I relinquish only my interest?

BLM will not approve relinquishment of part of the record title
interest.

Sec. 3143.16 If I own all or part of the operating rights in a lease,
but no record title, may I relinquish my operating rights to BLM?

You may not relinquish operating rights interests to BLM.

Sec. 3143.17 When is a relinquishment effective?

(a) If there are no defects in your relinquishment request, it is
effective the date you file it at the BLM office with jurisdiction over
the lands in your lease.
(b) If there are defects in your relinquishment request, it will be
effective on the date you correct the defects.

Sec. 3143.18 What are my obligations after I file the relinquishment?

You must fulfill all obligations which accrued before you filed the
relinquishment, other than an obligation to drill, including the
obligations to--
(a) Pay all accrued rentals and royalties;
(b) Permanently plug and abandon all wells on the relinquished
lands, unless BLM approves otherwise; and
(c) Complete reclamation of the relinquished lands and any other
areas adversely affected by lease operations in a timely manner.

Subpart 3144--Cancellations

Cancellations

Sec. 3144.10 Under what circumstances will BLM cancel my lease?

BLM will cancel your lease if you do not comply with applicable
law, regulations, or lease terms. If your lease is--
(a) Not producing, or does not contain a well capable of production
in paying

[[Page 66920]]

quantities, or is not committed to an approved unit agreement or
communitization agreement that contains a well capable of production in
paying quantities, BLM will notify you in writing of the default or
violation and give you 30 calendar days to comply. If you do not comply
within the 30 calendar days, your lease is subject to cancellation
under 30 U.S.C. 188(b); or
(b) Producing, or contains a well capable of producing oil or gas
in paying quantities, or is committed to an approved unit agreement or
communitization agreement that contains a well capable of production in
paying quantities, BLM will initiate cancellation through judicial
proceedings under 30 U.S.C. 188(a).

Sec. 3144.11 May BLM cancel my lease if it issued it improperly?

BLM may administratively cancel your lease if we issued it
improperly.

Sec. 3144.12 If I own or control an interest in a lease in violation
of the provisions of the Act, what will BLM do?

If you own or control any lease interests in violation of the Act,
BLM may initiate judicial proceedings under 30 U.S.C. 184 to--
(a) Cancel or forfeit your lease interest; or
(b) Compel you to dispose of your lease interest.

Bona Fide Purchasers

Sec. 3144.20 What is a bona fide purchaser?

(a) A bona fide purchaser is a person who acquires a lease interest
in good faith, for valuable consideration, and without notice that a
violation of the regulations in parts 3100 through 3190 existed. To
receive protection from cancellation, you must have paid the valuable
consideration before you had notice of the violation.
(b) You do not qualify as a bona fide purchaser if you reasonably
could have determined from BLM records that your seller held its lease
interest in violation of the Act.

Sec. 3144.21 Will BLM cancel my lease if I am a bona fide purchaser
and I purchased it from someone who acquired it in violation of the
Act?

BLM will not cancel your lease interest if you are a bona fide
purchaser who bought it from someone who held the lease interest in
violation of the Act.
11. Add new part 3145--Oil and Gas Drilling to read as follows:

PART 3145--OIL AND GAS DRILLING

Subpart 3145--Drilling and Additional Well Operations

Application for Permit to Drill or Reenter

Sec.
3145.5 To what operations do the standards of this subpart apply?
3145.10 What approval must I obtain from BLM to begin developing
Federal or Indian leases or to drill through Federal or Indian
mineral interests?
3145.11 What other approvals do I need for drilling or additional
well operations that occur on lands managed by an agency other than
BLM?
3145.12 What must I submit to BLM in my Application for Permit to
Drill or Reenter (APD)?
3145.13 What requirements must I comply with during operations?
3145.14 What additional requirements apply to a well I propose to
drill on privately-owned surface?
3145.15 What additional requirements apply to a well I propose to
drill on a Federal oil and gas lease if the surface is held in trust
for an Indian tribe or an individual Indian?
3145.16 May I file a single plan for more than one well?
3145.17 Must I submit an APD to BLM to start the APD process and
the 30-day public posting period?
3145.18 What is a Notice of Staking (NOS) and what must I do under
the NOS process?
3145.19 What actions will BLM take after receiving my APD or NOS?
3145.20 When will my approved APD expire and may I extend the term
of an approved APD?
3145.21 Must my APD describe all of my proposed operations
connected to the well I intend to drill?
3145.22 What must I submit after I drill a well or suspend drilling
operations?
3145.23 What must I do when my well is an inactive well?

Technical Drilling Standards

3145.30 What are the design and operational requirements for well
control?
3145.31 What additional requirements apply when I drill using gas,
air, or mist?
3145.32 How must I design and drill my well?
3145.33 What integrity tests and corrective measures must I perform
on my well?
3145.34 When may I conduct drill stem testing?

Drilling Operations in a Hydrogen Sulfide (H2S) Environment

3145.40 When must I follow BLM hydrogen sulfide (H2S)
requirements?
3145.41 What additional requirements apply when I drill in an
H2S environment?
3145.42 How do I calculate the radius of exposure?
3145.43 What if I encounter H2S in concentrations of 100
ppm or more in the gas stream that was not anticipated at the time
BLM approved my APD?
3145.44 What training and equipment must I provide personnel at the
wellsite for H2S operations?

Additional Well Operations

3145.50 What requirements must I satisfy for additional well
operations?
3145.51 What additional well operations require BLM approval?
3145.52 What additional well operations do not require BLM
approval?
3145.53 What happens when BLM receives my application for
additional well operations?
3145.54 What reports must I submit after I complete additional well
operations?
3145.55 What must I do to reclaim surface disturbance that results
from operations on my well or lease?

Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359 and
1751; and 43 U.S.C. 1732(b), 1733 and 1740.

Subpart 3145--Drilling and Additional Well Operations

Application for Permit To Drill or Reenter

Sec. 3145.5 To what operations do the standards of this subpart apply?

You must conduct all operations on Federal and Indian leases,
including those that do not require BLM approval, according to the
surface use and drilling standards of this subpart.

Sec. 3145.10 What approval must I obtain from BLM to begin developing
Federal or Indian leases or to drill through Federal or Indian mineral
interests?

(a) For each new well you drill or abandoned well you reenter to
develop Federal or Indian minerals, before you disturb the surface or
begin drilling operations, BLM must approve your Application for Permit
to Drill or Reenter (APD). For additional well operations that an APD
does not cover, you must receive BLM approval under Sec. 3145.53.
(b) You must file your APD in the BLM field office with
jurisdiction over the lands. Forest Service (FS) requirements must be
satisfied before BLM will approve your application for National Forest
System lands.

Sec. 3145.11 What other approvals do I need for drilling or additional
well operations that occur on lands managed by an agency other than
BLM?

(a) On National Forest System (NFS) lands--
(1) The FS must approve surface use operations on lands it
administers before BLM will approve your APD. You must obtain
information on processing and requirements for your surface use

[[Page 66921]]

proposals on NFS lands from the FS (see 36 CFR part 228, subpart E).
Submit surface use plans directly to the FS, along with an
informational copy to BLM. On NFS lands, the FS will schedule and
conduct predrill and other site inspections.
(2) The surface use plan is not part of the APD or application for
additional well operations. The FS will make a decision on your surface
use plans. The FS will determine when an approved surface use plan for
NFS lands expires or whether it may be extended. BLM will make a
decision on your APD and the portions of additional well operations
that affect down-hole concerns.
(b) If the proposed well or additional well operations are on lands
managed by an agency other than the FS, include a surface use plan with
your APD or your application for other well operations. BLM will
approve your surface use plan after we coordinate our review of your
proposal with the surface management agency.
(c) You must obtain approval from the U.S. Fish and Wildlife
Service (FWS) for surface use on land the FWS manages in Alaska. The
FWS must approve the surface use plan before BLM makes a decision on
your APD.

Sec. 3145.12 What must I submit to BLM in my APD?

In your APD, you must describe the procedures, equipment, and
materials you will use in the proposed operations in sufficient detail
to permit a complete review of the surface and subsurface effects
associated with the proposed project, including--
(a) Form 3160-3, APD, for each new well you drill or abandoned well
you reenter;
(b) Topographic maps and well plats that show the surveyed and
staked areas of proposed construction activity, access routes, and
areas of surface use. Well plats must be certified by a registered
surveyor;
(c) A surface use plan, or on FS lands, an informational copy of
the surface use plan you submitted to the FS, that completely describes
the--
(1) Road and drill pad and production facility (if known);
(2) Construction methods and interim and final reclamation
measures; and
(3) How you will contain and dispose of all waste material;
(d) A drilling plan that completely describes--
(1) Pressure control systems (including casing weights and grades
and cement types and additives) and circulation mediums (including
additives);
(2) Pertinent geologic data including usable water zones,
hydrocarbon bearing zones, anticipated maximum pressures, and other
potential hazards; and
(3) Testing and evaluation programs; and
(e) The bond coverage for your proposed activity.

Sec. 3145.13 What requirements must I comply with during operations?

During operations you must comply with lease terms, stipulations,
and applicable Federal, State and local laws and regulations. Your APD
(or your surface use plan for NFS lands) must show how you will--
(a) Provide adequate safeguards for surface and subsurface
resources and uses, including impacts to adjacent lands and waters;
(b) Properly reclaim disturbed lands to a stable, revegetated state
similar to adjacent undisturbed land;
(c) Complete recontouring and seedbed preparation in time to plant
approved seed mixtures by the next available period for establishing
vegetation;
(d) Protect and prevent waste of valuable hydrocarbons and other
minerals;
(e) Protect riparian areas, flood plains and wetlands;
(f) Prevent degradation of surface waters and subsurface usable
waters;
(g) Protect public health and safety, threatened, endangered, and
sensitive species and their habitats, and cultural and historic
resources, according to existing laws and regulations;
(h) Minimize the generation of wastes; and
(i) Properly contain, handle and dispose of solid and fluid wastes
and hazardous materials.

Sec. 3145.14 What additional requirements apply to a well I propose to
drill on privately-owned surface?

(a) If you propose to drill on privately-owned surface, you must
certify that the surface owner agrees to your use of the surface as
proposed in your APD and provide a copy of the surface owners agreement
if BLM requests it; or
(b) If you are unable to reach an agreement with a private surface
owner, BLM will make a final determination on surface use, considering
the views of the surface owner. BLM will only approve the permit if--
(1) You demonstrate that you made a good faith effort to reach an
agreement with the surface owner;
(2) Your bond is adequate to pay for required reclamation and
damage to surface improvements, crops and other surface uses; and
(3) You certify that there are no legal obstacles to conducting
operations without surface owner consent, including, but not limited
to, restraining orders or pending lawsuits.

Sec. 3145.15 What additional requirements apply to a well I propose to
drill on a Federal oil and gas lease if the surface is held in trust
for an Indian tribe or an individual Indian?

If the wellsite or access road is proposed on split-estate lands
where the surface is held in trust for an Indian tribe or an individual
Indian and the mineral estate is Federal, you must obtain a surface use
agreement with the tribe or an individual Indian surface owner(s).
However--
(a) A surface use agreement is not necessary for allotted lands in
Alaska under the Native Allotment Act of May 17, 1906, as amended (34
Stat. 197);
(b) You do not need a surface use agreement if your lease predates
the transfer to Indian ownership or the land transfer document or
legislation affords the United States access rights to exercise its
mineral rights; or
(c) Except as provided in paragraph (b) of this section, if you are
unable to reach an agreement with the surface owner(s), BLM will not
approve your APD.

Sec. 3145.16 May I file a single plan for more than one well?

Your drilling plan or surface use plan may cover an individual well
or multiple wells within areas of geological and environmental
similarity. If you combine plans for multiple wells, you must submit
Form 3160-3 to BLM for each well you propose to drill.

Sec. 3145.17 Must I submit an APD to BLM to start the APD process and
the 30-day public posting period?

To start the APD process and the 30-day public posting period, you
may file either an APD or a NOS under Sec. 3145.18.

Sec. 3145.18 What is a Notice of Staking (NOS) and what must I do
under the NOS process?

(a) A Notice of Staking (NOS) is a way you and BLM select an
acceptable drilling location before you submit an APD. Under the NOS
process, you must submit to BLM--
(1) Your, or your designated contact's, name, address, and
telephone number;
(2) A topographical or other acceptable map showing location,
access road, and lease boundaries;
(3) The name of the surface management agency, Indian or private
surface owner;

[[Page 66922]]

(4) The well name and number, lease number, and legal description
of the well location; and
(5) The well type, estimated well depth, and formation objectives.
(b) You must stake your well location and flag the access route
before the predrill inspection required in Sec. 3145.19(a)(4).
(c) You must submit an APD within 90 calendar days after the date
of the predrill inspection.

Sec. 3145.19 What actions will BLM take after receiving my APD or NOS?

(a) BLM will--
(1) For Federal leases, post the NOS or APD for public inspection
for 30 calendar days;
(2) Provide a copy of the NOS or APD to the appropriate Federal or
State surface management agency, if other than BLM;
(3) Notify you whether--
(i) BLM will process your NOS or APD or whether BLM needs
additional information to process your application; or
(ii) Whether you must contact another surface management agency;
and
(4) Schedule and conduct an on-site predrill inspection. The
purpose of the predrill inspection is to resolve on-site resource
concerns that may affect size, location, or design of the pad, access
road or facility. If necessary, BLM will recommend additional measures
that you must address in your APD.
(b) BLM will return your NOS or your incomplete APD if you do not
submit a complete APD within 90 calendar days of either the date of
predrill inspection or the date you receive BLM's notice under
paragraph (a)(3) of this section, whichever occurs last.
(c) Following receipt of a complete APD, and the posting period for
Federal lands, BLM will either--
(1) Approve the APD as submitted or with appropriate modifications
or conditions;
(2) Reject the APD and advise you in writing of the reasons; or
(3) Advise you in writing of the reasons why BLM will delay the
decision and when you can expect a final decision.

Sec. 3145.20 When will my approved APD expire and may I extend the
term of an approved APD?

(a) Your approved APD is valid for one year from the date of BLM's
approval, or your lease expiration date, whichever is sooner.
(b) BLM may extend a drilling permit for up to two additional 12
month periods, if you request an extension before each approval
expires, but not beyond the termination of the lease.

Sec. 3145.21 Must my APD describe all of my proposed operations
connected to the well I intend to drill?

(a) You must include with your APD plans for access roads and other
drilling, completion and production related activities, if known, that
are on the same lease as your well proposal; and
(b) You must obtain a right-of-way (R/W) authorization for the use
of BLM lands located off of your lease according to part 2800 of this
chapter. You have the option of using the APD package to furnish the
information BLM requires to process an R/W instead of filing a separate
R/W plan of development. If you choose this option, the APD will serve
as an R/W application, even though BLM will issue two separate approval
documents (APD and R/W grant).
(c) If your proposal involves off-lease activities on surface
managed by an agency other than BLM, or on private or Indian surface,
you must include this information with your APD and contact the
appropriate agency and/or surface owner for additional surface use
authorization.
(d) If you do not include plans for production activities,
including pipelines, storage facilities and measurement sites, with
your APD, you must submit plans before construction and installation of
these facilities, according to Secs. 3145.50 through 3145.55.

Sec. 3145.22 What must I submit after I drill a well or suspend
drilling operations?

Within 30 calendar days after you drill a well or suspend drilling
operations, you must submit to BLM--
(a) Reports, well logs, and test data;
(b) A Well Completion Report, Form 3160-4; and
(c) Other information BLM requires.

Sec. 3145.23 What must I do when my well is an inactive well?

Within 30 calendar days after your well becomes inactive (see
Sec. 3107.52), you must--
(a) Put the well into production or service;
(b) Submit to BLM plans to conduct well-work to restore production
or service;
(c) Submit plans to plug and abandon the well and reclaim areas
disturbed or contaminated by your well operations; or
(d) Comply with the requirements of Sec. 3107.56.

Technical Drilling Standards

Sec. 3145.30 What are the design and operational requirements for well
control?

You must--
(a) Design your blowout prevention equipment system (BOP) to
control known or anticipated pressures, taking into account the
geologic conditions, accepted engineering practices, and the surface
environment;
(b) Use a BOP with a working pressure that exceeds the maximum
anticipated surface pressure, assuming a pressure gradient of 0.22 psi/
foot for a wildcat well or the appropriate pressure gradient for known
geologic environments;
(c) Configure and maintain your BOP according to the guidelines in
the ``American Petroleum Institute (API) Recommended Practice 53,
Recommended Practice for Blowout Prevention Equipment Systems for
Drilling Wells'', Third Edition, March 1997 (RP 53);
(d) Use a BOP that can completely close the wellbore;
(e) Install and pressure test the BOP before you drill the surface
casing shoe (unless BLM specifies otherwise) and before you perform
other post-drilling well operations that require control of known or
anticipated pressures;
(f) Unless BLM approves otherwise, pressure test the BOP to the
recommended high pressure test standards in Section 17 of API RP 53,
except you must not--
(1) Test the annular preventer in excess of 50 percent of its
working pressure; or
(2) Expose the casing to pressures exceeding 70 percent of its
minimum internal yield;
(g) Functionally test the pipe rams daily and the blind rams each
time you pull the drill string to change the drill bit, but not more
than once per day;
(h) Document all tests in the driller's log;
(i) Ensure that the wellbore is closed when it is unattended; and
(j) Take immediate steps to restore control of your well, when
necessary.

Sec. 3145.31 What additional requirements apply when I drill using
gas, air, or mist?

You must follow the standards for gas, air, or mist drilling
operations contained in Section 17 of ``American Petroleum Institute
(API) Recommended Practice 54, Recommended Practices for Occupational
Safety for Oil and Gas Well Drilling and Servicing Operations'', Second
Edition, May 1, 1992 (RP 54).

Sec. 3145.32 How must I design and drill my well?

Design and drill your well so that--
(a) The collapse, burst, and tensile strengths of the casing(s) are
sufficient to withstand anticipated pressures;

[[Page 66923]]

(b) The surface casing is cemented along its entire length with
centralizers located on at least the bottom three joints;
(c) The casing(s) is set in a competent formation(s) that will
withstand anticipated pressure and is cemented so that all useable
water and other minerals are protected;
(d) Cement placement procedures minimize contamination and maximize
cement bonding;
(e) Cement is uniformly distributed around the casing(s) to ensure
an adequate casing-to-formation bond;
(f) Cement curing time is adequate to ensure a minimum compressive
strength of 500 psi or to maintain well bore integrity;
(g) The tubular steel properties are appropriate for the type of
conditions (e.g., hydrogen sulfide, corrosives, temperature) in which
it is used;
(h) Any geologic formations of concern are adequately isolated to
prevent fluid or gas migration;
(i) The drilling circulation system is monitored and ensures well
control; and
(j) Liners overlap at least 100 feet.

Sec. 3145.33 What integrity tests and corrective measures must I
perform on my well?

(a) During drilling operations you must--
(1) Conduct a pressure test of all casing strings, including liner
overlaps, below the conductor pipe before you set the next string of
casing;
(2) Perform a mud weight equivalency test of each casing shoe
before you drill 20 feet of new hole on all exploratory wells and on
part of any well approved for a 5K BOP (as defined in Section 6, API RP
53) system or greater; and
(3) Correct pressure loss problems before you continue drilling
operations, unless drilling ahead is necessary for well control.
(b) You must test all repairs and alterations of your wellbore to
demonstrate mechanical integrity.

Sec. 3145.34 When may I conduct drill stem testing?

(a) You may initiate and conduct drill stem testing (DST) without
BLM's prior approval only during daylight hours. You must follow the
recommended practices of Section 14, API RP 54.
(b) If you start the DST during daylight hours, you may continue
testing at night if--
(1) The rate of flow is stabilized; and
(2) You provide safe, adequate lighting.
(c) You may release packers, but must not begin tripping before
daylight, unless you have BLM's approval.
(d) You may conduct closed chamber DST's day or night.

Drilling Operations in a Hydrogen Sulfide (H2S)
Environment

Sec. 3145.40 When must I follow BLM hydrogen sulfide (H2S)
requirements?

You must follow BLM H2S requirements when you drill, complete,
test, or rework in zones known, or reasonably expected, to contain
H2S in concentrations of 100 parts per million (ppm) or more
in the gas stream.

Sec. 3145.41 What additional requirements apply when I drill in an
H2S environment?

When you drill in an H2S environment--
(a) Your plans and operations must follow the standards contained
in API ``Recommended Practice 49, Recommended Practices for Safe
Drilling of Wells Containing Hydrogen Sulfide'', Second Edition, April
15, 1987 (RP 49);
(b) You must submit an H2S plan as part of your APD that
shows how you will--
(1) Provide for safety of personnel that are essential to maintain
control of the well;
(2) Conduct general rig operations and drill stem testing;
(3) Handle special rig problems in an H2S environment;
and
(4) Alert and protect the public if a potentially hazardous volume
of H2S is released from your operation when--
(i) The 500 parts per million (ppm) radius of exposure is greater
than 50 feet and includes any part of a road or highway principally
maintained for public use;
(ii) The 100 ppm radius of exposure is greater than 50 feet and
includes any occupied residence, school, church, park, school bus stop,
place of business, or other area where the public could reasonably be
expected to frequent; or
(iii) The 100 ppm radius of exposure is equal to or greater than
3,000 feet where facilities or roads are principally maintained for
public use.
(c) You may submit a single plan for multiple wells within a single
field.

Sec. 3145.42 How do I calculate the radius of exposure?

(a) You must use one of the following methods to calculate the
radius of exposure, as appropriate--
(1) If the H2S concentration in the gas stream is less
than 10 percent, calculate--
(i) The 100 ppm radius of exposure using the formula--

X=[(1.589)(H2S concentration)(Q)](^0.6258); or

(ii) The 500 ppm radius of exposure using the formula--

X=[(0.4546)(H2S concentration)(Q)]^(0.6258)

Where--

X=radius of exposure in feet.
H2S Concentration = decimal equivalent of the mole or volume
fractions of H2S in the gaseous mixture.
Q=maximum volume of gas determined to be available for escape in cubic
feet per day (at standard condition of 14.73 pounds per square inch
absolute (psia) and 60 deg. Fahrenheit).

(2) If the H2S concentration in the gas stream is 10
percent or greater, you must calculate the 100 ppm or the 500 ppm
radius of exposure using a dispersion technique that takes into account
atmospheric stability, complex terrain, wind speed and direction, and
other dispersion features. You may use one of the computer models
outlined in the Environmental Protection Agency's ``Guidelines on Air
Quality Models (Revised) (EPA-450/2-78-027R)'', July 1986; or
(3) Another method if BLM approved it.
(b) You must assume a radius of at least 3,000 feet for a well you
are drilling in an area where you have insufficient data to calculate a
radius of exposure, but where you could reasonably expect
H2S to be present in concentrations of 100 ppm or more.
(c) Use a field-wide radius of exposure or calculate the radius of
exposure for each component part of the drilling, completion, workover,
and production system where multiple H2S sources (i.e.,
wells, treatment equipment, flowlines, etc.) are present.

Sec. 3145.43 What if I encounter H2S in concentrations of
100 ppm or more in the gas stream that was not anticipated at the time
BLM approved my APD?

(a) If you encounter H2S in concentrations of 100 ppm or
more in the gas stream that was not anticipated at the time BLM
approved your APD, you must immediately ensure control of the well,
suspend drilling ahead (unless you need it for well control), and
obtain materials and safety equipment so that your operations comply
with the regulations in this part; and
(b) You must notify BLM within 24 hours of encountering
H2S in concentrations of 100 ppm and describe the steps you
took, or are taking, to control the situation.

Sec. 3145.44 What training and equipment must I provide personnel at
the wellsite for H2S operations?

(a) You must train all personnel working at the wellsite with the
general training requirements outlined in Section 2 of API RP 49.

[[Page 66924]]

(b) For drilling operations, you must complete the initial training
session either--
(1) Three business days before drilling into known or probable
H2S zones; or
(2) Before reaching a depth 500 feet above known or probable
H2S zones.
(c) On a drilling, completion, or workover site, all personnel
(including service company personnel) essential to maintain or regain
control of the well, and visitors, must have, or have access to, escape
or pressure-demand type breathing apparatus. You must not allow anyone
onto the location without the proper equipment.
(d) Your respiratory protection equipment program must follow the
standards of Section 3 of API RP 49.

Additional Well Operations

Sec. 3145.50 What requirements must I satisfy for additional well
operations?

For additional well operations that require BLM approval under
Sec. 3145.51, you must submit Sundry Notice, Form 3160-5, or other
filing instrument acceptable to BLM, that describes the proposed
surface use and downhole procedures. You must include details similar
to those required when filing an APD (e.g., maps, construction methods,
pressure control systems, and when BLM does not manage the surface,
resource protection measures, standards for occupancy of the surface,
and reclamation measures).

Sec. 3145.51 What additional well operations require BLM approval?

(a) You must request and receive BLM approval, before you--
(1) Plug, plug back, squeeze, deepen, complete in a different zone,
temporarily abandon a well, convert a well to injection, dispose of
produced water or commingle production;
(2) Conduct downhole operations that affect valuable hydrocarbons
and other mineral deposits, oil and gas resource recovery, production
accountability, subsurface usable waters, or public health and safety;
(3) Use bioremediation methods or other measures to reclaim lands
contaminated by spills and accidents;
(4) Disturb the surface off the existing access road, wellpad, or
approved facility sites, or disturb areas previously reclaimed; or
(5) Construct new pits or enlarge existing pits except for those
constructed for routine well maintenance on the existing well pad or
approved facility sites, or on sites that are not reclaimed.
(b) BLM may give oral approval whenever the regulations in this
part require you to obtain BLM approval before starting operations. BLM
may require you to file a written request on Sundry Notices and Reports
on Wells (SN), Form 3160-5, within five business days of the oral
approval.

Sec. 3145.52 What additional well operations do not require BLM
approval?

You do not need BLM approval to--
(a) Perform only surface disturbing activities on NFS lands;
(b) Perform operations that are included in a plan BLM previously
approved;
(c) Return fluids from the well bore to a closed system for
transport and disposal according to existing laws and regulations;
(d) Take actions to correct or contain an emergency situation.
However, you must notify BLM no later than 48 hours after the
occurrence; or
(e) Perform activities that will not disturb the surface off the
existing access road, wellpad, facility sites or disturb areas
previously reclaimed, when you perform--
(1) Routine well maintenance;
(2) Any modification to surface production equipment not covered
under Sec. 3151.10; or
(3) Downhole operations that will not affect valuable hydrocarbons
and other mineral deposits, oil and gas resource recovery, subsurface
usable waters, or public health and safety.

Sec. 3145.53 What happens when BLM receives my application for
additional well operations?

(a) When BLM receives your application for additional well
operations, SN, Form 3160-5, BLM will--
(1) Schedule and conduct a site inspection, if needed to evaluate
your proposal; and
(2) Notify you whether--
(i) BLM will process your application, or whether BLM needs
additional information to process your application; or
(ii) Whether you must contact another surface management agency;
(b) After we receive a complete application, BLM will --
(1) Approve the application as submitted or with appropriate
modifications or conditions;
(2) Reject the application and advise you of the reasons why; or
(3) Advise you of the reasons why BLM will delay the decision and
when you can expect a final BLM decision.

Sec. 3145.54 What reports must I submit after I complete additional
well operations?

Within 30 calendar days after you complete additional well
operations, you must submit to BLM--
(a) A Well Completion Report, Form 3160-4, if you complete your
well in a new formation;
(b) Reports, well logs, and test data;
(c) A SN, Form 3160-5, if--
(1) You alter the existing wellbore configuration; or
(2) BLM requests it; and
(d) Other information BLM requires.

Sec. 3145.55 What must I do to reclaim surface disturbance that
results from operations on my well or lease?

To reclaim surface disturbance that results from operations on your
well or lease, you must--
(a) Complete recontouring and seedbed preparation in time to plant
approved seed mixtures by the next available period for establishing
vegetation;
(b) Reclaim all of the excess pad, facility, and road areas,
pipeline or utility corridors, pits, contaminated areas, and areas
disturbed during emergencies, to a stable, revegetated state similar to
adjacent undisturbed land; and
(c) Comply with any reclamation conditions of your approved permit
or lease.
11. Revise part 3150--Onshore Oil and Gas Geophysical Exploration
to read as follows:

PART 3150--OIL AND GAS MEASUREMENT AND OPERATIONS

Subpart 3151--Production, Storage and Measurement

Production, Storage and Measurement--General

Sec.
3151.10 What Federal and Indian oil or gas production activities
require BLM approval?
3151.11 How do I get BLM approval for production activities
involving Federal and Indian oil or gas?
3151.12 What are the standards for lease production operations?
3151.13 How must I handle Federal royalty-in-kind oil?
3151.14 On what oil and gas must I pay royalty?
3151.15 On what oil and gas am I not required to pay royalty?
3151.16 When may I vent or flare Federal or Indian gas without BLM
approval without paying royalty?

Production Operations With Hydrogen Sulfide (H\2\S)

3151.20 What precautions must I take if there is any possibility
for H2S at my production facility or storage tank?
3151.21 When must I take additional precautions?
3151.22 What precautions must I take if my storage tank has a vapor
accumulation with an H2S concentration greater than 500
ppm?

[[Page 66925]]

3151.23 What precautions must I take if my production facility has
an H2S concentration of 100 ppm or more in the gas
stream?
3151.24 What precautions must I take when the sustained ambient
concentration of H2S exceeds acceptable limits?

Subpart 3152--Site Security

General

3152.10 What are BLM's site security requirements for production
facilities?

Storage and Sales Facilities--Seals

3152.20 What oil and condensate measurement system components must
I seal for site security?
3152.21 When must I seal a valve?

Oil and Gas Meters

3152.30 How must I secure metering systems?

Federal Seals

3152.40 What will BLM do if I do not seal a valve or component of a
measurement system where BLM requires a seal?

Plans and Facility Diagrams

3152.50 What is a site security plan?
3152.51 What is a site facility diagram?
3152.52 For what production facilities must I prepare a site
facility diagram?

Well and Facility Identification

3152.60 How must I identify wells and production facilities?

Transporter Documentation

3152.70 What information must I have when transporting oil and gas
production that is produced from or allocated to my lease?

Theft

3152.80 What if I discover theft or mishandling of oil, condensate
or gas produced from my wells?

Subpart 3153--Oil Measurement

General

3153.10 How must I measure Federal and Indian oil?

Tank Gauging

3153.20 How do I determine the quantity and quality of oil that I
sell by tank gauging?

Leasing Automatic Custody Transfer

3153.30 How must I install and operate my Lease Automatic Custody
Transfer (LACT) unit?
3153.31 How do I determine oil gravity and sediment and water
content of oil measured through my LACT?
3153.32 How do I determine the composite meter factor for my LACT
meter?
3153.33 What requirements apply to the meter prover I use to
determine the LACT composite meter factor?
3153.34 When must I determine the composite meter factor for my
LACT meter?
3153.35 What tolerance does BLM require for the LACT composite
meter factor?
3153.36 What if the LACT composite meter factor changes more than
0.0025 between provings?
3153.37 What notices and reports must I provide to BLM about
operation of my LACT system?
3153.38 How do I correct volumes if my composite meter factor
changes between LACT provings?

Measurement Tickets

3153.40 How must I document the sale or removal of oil from my
production facility?

Subpart 3154--Gas Measurement

Gas Measurement

3154.10 How do I measure and report gas production from Federal and
Indian lands?

Orifice Meter--Primary Element

3154.20 How must I install, operate, and maintain an orifice meter?
3154.21 How must I determine the volume of gas that passes through
my orifice meter?

Orifice Meter--Secondary Element

3154.30 How must I record the differential and static pressures on
a chart recorder?
3154.31 What additional requirements must I follow when using
electronic flow computers ?
3154.32 How must I calibrate the secondary element of an orifice
meter?
3154.33 When must I calibrate the secondary element?

Orifice Meters--Low Volume Exemptions

3154.40 What measurement standards apply if I use an orifice meter
and measure an average of 100 Mcf of gas, or less, per producing day
on a monthly basis?

Other Metering Systems

3154.50 What standards must I follow if I measure gas by a metering
system other than an orifice meter?

Volume Corrections

3154.60 How do I correct volumes if my meter did not measure
accurately?

Gas Quality Measurements

3154.70 How do I determine the quality of my gas stream?

Subpart 3155--Produced Water Disposal

Produced Water Disposal

3155.10 Why must I obtain approval from BLM to dispose of water
produced from my lease?
3155.11 When do I need BLM approval to dispose of produced water?
3155.12 When may I dispose of produced water without BLM approval?
3155.13 What type of water disposal will BLM allow?
3155.14 What BLM forms and Environmental Protection Agency, State
or Indian Tribe permits must I submit to BLM if I plan to dispose of
produced water?
3155.15 What additional requirements must I follow for water
disposal into pits?
3155.16 When may I use an unlined pit for produced water disposal?
3155.17 If the quantity and quality of my produced water changes,
do I need a new approval from BLM to continue using an unlined pit?
3155.18 What must I submit to BLM for surface discharge that
requires a National Pollution Discharge Elimination System permit?
3155.19 What if the EPA, State, or Indian Tribe cancels or suspends
the permit for a disposal facility I am using?

Subpart 3156--Spills and Accidents

Spills and Accidents

3156.10 What action must I take after an accident or spill that
involves Federal or Indian production?
3156.11 How soon after a spill or accident must I report it to BLM?
3156.12 When must I submit a written report on spills and accidents
to BLM?
3156.13 What must I include in my report of a spill or accident?
3156.14 When must I submit follow-up written reports to BLM about a
spill or accident?

Subpart 3159--Well Abandonment

Temporary Abandonment

3159.10 How do I obtain BLM approval to temporarily abandon all or
a portion of a Federal or Indian well?
3159.11 How do I temporarily abandon a well?

Permanent Abandonment

3159.20 When must I permanently plug and abandon my well?
3159.21 How do I obtain BLM approval to permanently plug and
abandon my well?
3159.22 How must I permanently plug and abandon a well?
3159.23 When must I test plug placement?
3159.24 What must I do if the surface owner or surface management
agency requests that I convert a well I plan to plug and abandon
into a water well?
3159.25 What if my approved plans for well abandonment change after
I receive BLM approval?
3159.26 What must I submit to BLM after I permanently abandon my
well and complete reclamation measures?

Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359 and
1751; and 43 U.S.C. 1732(b), 1733 and 1740.

[[Page 66926]]

Subpart 3151--Production, Storage and Measurement

Production, Storage and Measurement--General

Sec. 3151.10 What Federal and Indian oil or gas production activities
require BLM approval?

Before you begin production activities involving Federal or Indian
oil or gas, you must have BLM approval to --
(a) Measure gas by a method other than that authorized under
subpart 3154;
(b) Measure oil by a method other than tank gauging or positive
displacement metering system, or by a method that you can demonstrate
to BLM is equivalent in accuracy and accountability to either of those
two systems;
(c) Measure oil and gas at a location off your lease;
(d) Commingle production; or
(e) Vent or flare gas, unless Sec. 3151.16 applies.

Sec. 3151.11 How do I get BLM approval for production activities
involving Federal and Indian oil or gas?

The following table lists application requirements for those
production activities for Federal or Indian oil or gas that require BLM
approval. For each of the listed activities, request approval from the
BLM using Sundry Notice, Form 3160-5, and provide the documentation
indicated--

------------------------------------------------------------------------
Activity Documentation--
------------------------------------------------------------------------
(a) Measure gas by a method Show that your method of measuring will
other than that authorized not adversely affect royalty income or
in subpart 3154. production accountability.
(b) Measure oil by a method Show that your method of measuring will
other than tank gauging or not adversely affect royalty income or
positive displacement production accountability.
metering system.
(c) Measure oil and gas at a Identify where you want to measure
location off your lease. production; and Why you must measure off-
lease; and Show that your proposed
location will not adversely affect
surface resources, royalty income or
production accountability.
(d) Commingle Federal or Indicate the volume, quality, and source
Indian oil or gas. of the products you want to commingle;
and Show how you will allocate
production back to the source; and Show
that commingling will not adversely
affect royalty income or production
accountability.
(e) Vent or flare gas in Identify the volume, composition and
situations other than those source of the gas you want to vent or
described in Sec. 3151.16. flare; and Show why it is not economical
for you to market the gas at the time of
application or use it on lease.
------------------------------------------------------------------------

Sec. 3151.12 What are the standards for lease production operations?

(a) You must conduct production operations in accordance with
accepted industry practices to--
(1) Put all oil, other hydrocarbons, gas and sulphur that you
produce into a marketable condition, if economically feasible;
(2) Prevent any oil going to a pit or open tank except in an
emergency. If oil goes to a pit, you must remove it within 48 hours,
unless BLM directs otherwise;
(3) Prevent avoidable loss of oil and gas; and
(4) Protect the mineral resource, other natural resources and
environmental quality.
(b) You must report to BLM not later than the fifth business day
after a well first begins production or resumes production after being
shut-in for 90 calendar days or more under Sec. 3103.10(r). For
purposes of this paragraph, production begins or resumes--
(1) For an oil well, on the date on which you first sell or ship
liquid hydrocarbons from a temporary storage facility, such as test
tanks, or the date on which you first produce liquid hydrocarbons into
a permanent storage facility, whichever occurs first; or
(2) For a gas well, on the date on which you first measure gas
through a sales metering facility or the date on which you first sell
or ship associated liquid hydrocarbons from a temporary storage
facility, whichever occurs first. For purposes of this paragraph, a gas
well is shut-in only if it is incapable of production.

Sec. 3151.13 How must I handle Federal royalty-in-kind oil?

If the lessor elects to take its royalty in-kind, you must store
the amount of oil equal to the royalty volume from or allocated to your
Federal lease at a location agreed to by you and BLM for up to 30
calendar days at no cost to the lessor.

Sec. 3151.14 On what oil and gas must I pay royalty?

You must pay royalty on--
(a) Oil and gas produced from or allocated to your lease that you
sell or remove from your lease;
(b) Gas you vent or flare without BLM approval, or that exceeds an
amount exempted under Sec. 3151.16; or
(c) Oil and gas which is avoidably lost.

Sec. 3151.15 On what oil and gas am I not required to pay royalty?

You are not required to pay royalty on--
(a) Oil and gas used for beneficial purposes;
(b) Waste oil;
(c) Gas you vent or flare with BLM approval or as provided in
Sec. 3151.16; or
(d) Oil and gas which is unavoidably lost.

Sec. 3151.16 When may I vent or flare Federal or Indian gas without
BLM approval without paying royalty?

(a) You are not required to have BLM approval or pay royalty when
you vent or flare gas during--
(1) Emergency situations (e.g., equipment failures or relief of
abnormal system pressures) that do not exceed 24 hours per incident or
144 hours total for a lease during any calendar month;
(2) Initial production tests, provided you do not test for more
than 30 calendar days or produce more than 50,000 Mcf of gas;
(3) Unloading or clean up of your well, up to 24 hours per event;
(4) Drill stem testing up to 24 hours or special well evaluation
tests up to 72 hours;
(5) Routine preventive maintenance of production equipment, up to
24 hours per month; or
(6) Routine well maintenance operations.
(b) BLM may approve requests for longer periods for any of the
situations listed in paragraph (a) of this section.
(c) You are not required to obtain approval to vent or flare gas
from Federal oil wells which produce less than 10 Mcf of gas per day as
part of normal oil production, unless it is economic to capture that
gas. You must flare or vent gas in a safe manner

[[Page 66927]]

according to applicable laws, regulations, and accepted industry
practice.

Production Operations With Hydrogen Sulfide (H2S)

Sec. 3151.20 What precautions must I take if there is any possibility
for Hydrogen Sulfide (H2S) at my production facility or
storage tank?

If there is any possibility for H2S at your production
facility or storage tank, you must--
(a) Test each production facility and tank for H2S
concentration in the gas stream, tank vapors, and sustained ambient air
when you install a new facility or modify your production or operation
method;
(b) Notify BLM within five calendar days whenever concentrations of
20 parts per million (ppm) or greater are encountered. You do not need
to notify BLM if your modification(s) to your production or operation
method changes the previously reported H2S concentration by
5 percent or less; and
(c) Design and maintain your facility to keep the sustained ambient
concentration below 10 ppm H2S or 2 ppm sulphur dioxide
(SO2) within a 50-foot radius and at any occupied residence,
school, church, park, playground, school bus stop, place of business,
or other area that the public could reasonably be expected to frequent.

Sec. 3151.21 When must I take additional precautions?

You must take the additional precautions described in
Secs. 3151.22, 3151.23, and 3151.24 at your well or production facility
when--
(a) Your storage tank(s) operates at or near atmospheric pressure
and contains produced fluids which accumulate vapor resulting in an
H2S concentration greater than 500 ppm in the tank;
(b) You have an H2S concentration of 100 ppm or more in
the gas stream; or
(c) The sustained ambient H2S concentration is more than
10 ppm at 50 feet from the production facility or storage tank(s), as
measured at ground level under calm (1 mph) conditions.

Sec. 3151.22 What precautions must I take if my storage tank has a
vapor accumulation with an H2S concentration greater than
500 ppm?

If your storage tank has a vapor accumulation with an
H2S concentration greater than 500 ppm you must--
(a) Restrict entry to all stairs or ladders leading to the top of
storage tank;
(b) Post danger signs on or within 50 feet of each storage tank to
alert the public of the potential H2S hazard;
(c) Install at least one permanent wind direction indicator so
someone at, or approaching, the storage tank(s) can easily determine
wind direction; and
(d) Install a fence and gate(s), and lock all gates when you are
not at the site, to restrict public access if storage tanks are
located--
(1) Within \1/4\ mile of, or inside, a city or incorporated limits
of a town;
(2) Within \1/4\ mile of an occupied residence, school, church,
park, playground, school bus stop, place of business; or
(3) Where the public could reasonably be expected to frequent.

Sec. 3151.23 What precautions must I take if my production facility
has an H2S concentration of 100 ppm or more in the gas
stream?

If your production facility has an H2S concentration of
100 ppm or more in the gas stream, you must--
(a) Take all the precautions required by Sec. 3151.22 for storage
tanks. If your tank is next to your facility, you do not need to
duplicate precautions;
(b) Design and construct your facility in conformance with American
Petroleum Institute (API) RP 55, ``Recommended Practices for Conducting
Oil and Gas Producing and Gas Processing Plant Operations Involving
Hydrogen Sulfide'', Second Edition, February 15, 1995 (API RP 55,
1995);
(c) Calculate your 100 and 500 ppm radii of exposures using the
formulae or methods listed in Sec. 3145.42;
(d) Develop, implement, and update at least annually, a public
protection plan that details how you will alert and protect the
potentially affected public in the event of a potentially hazardous
release of H2S and SO2. The plan must follow the
contingency planning procedures of the API RP 55 1995, if--
(1) The 500 ppm radius of exposure is greater than 50 feet and
includes any part of a road or highway principally maintained for
public use;
(2) The 100 ppm radius of exposure is greater than 50 feet and
includes any occupied residence, school, church, park, school bus stop,
place of business, or other area which the public could reasonably be
expected to frequent; or
(3) The 100 ppm radius of exposure is equal to or greater than
3,000 feet where facilities or roads are principally maintained for
public use.
(e) Post danger signs at locations where well flowlines and lease
gathering lines that carry H2S gas cross public or lease
roads. You are not required to install fencing or wind direction
indicators around your flowlines;
(f) Install on all wells, except for those you produce by
artificial lift, a secondary means of immediate well control that
allows you to reenter under pressure for permanent well control
operations; and
(g) For wells you produce by artificial lift, and where the 100 ppm
radius of exposure for H2S includes any occupied residence,
place of business, school, other inhabited structure or any area that
the public may reasonably be expected to frequent, install automatic
shut-in controls that are set to activate in the event of a potentially
hazardous release of H2S.

Sec. 3151.24 What precautions must I take when the sustained ambient
concentration of H2S exceeds acceptable limits?

If the sustained ambient concentration exceeds the limit specified
in Sec. 3151.20(c), you must collect or reduce vapors from the system.
All vapor you collect must be--
(a) Sold;
(b) Used on the lease;
(c) Reinjected; or
(d) Flared, if terrain and conditions permit and will not result in
SO2 concentrations that exceed 2 ppm within a 50-foot
radius.

Subpart 3152--Site Security

General

Sec. 3152.10 What are BLM's site security requirements for production
facilities?

You must configure and secure all production facilities where
Federal and Indian production or allocable production is produced or
stored to ensure production accountability for that oil and gas.

Storage and Sales Facilities--Seals

Sec. 3152.20 What oil and condensate measurement system components
must I seal for site security?

(a) You must seal each valve, combination of valves and measurement
system component(s) that, if altered, could substantially and adversely
affect royalty income or production accountability. You must use a
uniquely numbered seal to detect unauthorized or undocumented access to
oil or condensate;
(b) For each valve requiring a seal, you must place the seal so
that it would be destroyed if the position of the valve changes; and
(c) For each component in a measuring system requiring a seal, you
must place the seal so that it would be destroyed if a component is
accessed.

[[Page 66928]]

Sec. 3152.21 When must I seal a valve?

(a) During the production phase, you must seal closed all valves
that provide access to oil or condensate production; and
(b) Before taking the top gauge for sale, you must seal closed all
valves that would allow unmeasured production to enter or leave the
sales tank.

Oil and Gas Meters

Sec. 3152.30 How must I secure metering systems?

(a) During normal operation of your Lease Automatic Custody
Transfer system (LACT), you must seal all components that could affect
the volume or quality determination of the oil passing through the
LACT;
(b) You must seal LACT components by following the requirements of
Sec. 3152.20; and
(c) You must not have bypasses around meters that could permit any
person to remove oil or gas from the lease or facility without
measuring it, unless BLM approved a bypass.

Federal Seals

Sec. 3152.40 What will BLM do if I do not seal a valve or component of
a measurement system where BLM requires a seal?

If BLM discovers a missing seal, BLM will require you to place a
seal or BLM will place a Federal seal on the valve or component to
secure production if you are not at the site when BLM makes the
discovery.

Plans and Facility Diagrams

Sec. 3152.50 What is a site security plan?

(a) A site security plan is a document that details how you will
secure your production facilities. Your site security plan must specify
which leases and production facilities are covered by your plan and
describe how you will--
(1) Implement a self-inspection program to periodically monitor
production volumes, and production and measurement equipment;
(2) Seal appropriate valves at storage and production facilities;
(3) Prepare and maintain records of sales;
(4) Prepare and maintain records of seals;
(5) Identify and report potential theft or mishandling of
production; and
(6) Update your plan when you change or add production facilities.
(b) You must maintain all of your production facilities to comply
with your site security plan.
(c) You must provide BLM a copy of the plan when we request it.

Sec. 3152.51 What is a site facility diagram?

A site facility diagram is a schematic of your production facility
that--
(a) Accurately reflects the conditions at the site;
(b) Commencing with the header (if applicable), clearly identifies
the vessels, piping, metering system, and pits, if any, which apply to
the handling and disposal of oil, gas, and water;
(c) Indicates which valves you must seal and the position of the
valve during the production and sales phases;
(d) Identifies where your production facility is located and the
lease it serves; and
(e) States where you keep the site security plan that applies to
your production facility.

Sec. 3152.52 For what production facilities must I prepare a site
facility diagram?

(a) You must prepare and submit to BLM a site facility diagram for
all production facilities you use to handle or to store oil or
condensate produced from, or allocable to, Federal or Indian lands.
(b) You do not need a site facility diagram for--
(1) A dry gas production facility where you do not produce or store
oil or condensate; or
(2) A production facility where a single tank is used for
collecting 15 barrels a day or less of oil or condensate produced from
a single well.

Well and Facility Identification

Sec. 3152.60 How must I identify wells and production facilities?

(a) For every unplugged well on a Federal or Indian lease or within
an agreement BLM approved, you must place a legible sign in a
noticeable place, that identifies the well name or number, ownership,
legal description of the location, and lease name or number;
(b) On every production facility you use to store Federal or Indian
production, you must place a legible sign in a noticeable place that
identifies the facility name or number, ownership, legal description of
the location, and lease name or number. You also must place a unique
number on each storage tank; and
(c) If you have one tank battery servicing one well at a common
location, you may use one sign for both, if it includes the information
required for both wells and production facilities.

Transporter Documentation

Sec. 3152.70 What information must I have when transporting oil and
gas production that is produced from or allocated to my lease?

(a) If you transport oil from your lease by motor vehicle or
pipeline, the driver or transporter must have a measurement ticket,
trip log or other documentation showing--
(1) The quantity and quality of oil transported;
(2) The property and production facility identification number from
which the oil came; and
(3) The intended first purchaser of the oil.
(b) If you transport gas by pipeline, it must be reported according
to the requirements in subpart 3154.

Theft

Sec. 3152.80 What if I discover theft or mishandling of oil,
condensate or gas produced from my wells?

If you discover theft or mishandling of oil, condensate or gas
produced from your wells--
(a) You must provide BLM a written or oral report of the incident
no later than the next business day after you discover the apparent
theft or mishandling; and
(b) If you report the incident orally, you must follow up the oral
notice with a written report to BLM describing the details of the
incident within 10 business days.

Subpart 3153--Oil Measurement

General

Sec. 3153.10 How must I measure Federal and Indian oil?

You must measure Federal and Indian oil by tank gauging, a positive
displacement metering system such as a lease automatic custody transfer
system (LACT), or a method that you can demonstrate to BLM to be
equivalent in accuracy and accountability to tank gauging or a LACT.

Tank Gauging

Sec. 3153.20 How do I determine the quantity and quality of oil that I
sell by tank gauging?

The following table lists the American Petroleum Institute (API)
standards and practices that you must follow to achieve accurate oil
measurement by tank gauging--

[[Page 66929]]

------------------------------------------------------------------------
You must follow the standards and
When you-- practices of--
------------------------------------------------------------------------
(a) Set and equip storage API RP 12R1, ``Recommended Practice for
tanks. Setting, Maintenance, Inspection,
Operation and Repair of Tanks in
Production Service'', Fifth Edition,
October 1, 1997.
(b) Calibrate a storage tank. API MPMS Chapter 2.2A, ``Measurement and
Calibration of Upright Cylindrical tanks
by the Manual Tank Strapping Method'',
First Edition, dated February 1995; or
API MPMS Chapter 2.2B, ``Calibration of
Upright Cylindrical Tanks Using the
Optical Reference Line Method'', First
Edition, March 1989 (Reaffirmed May
1996).
(c) Transfer custody of oil.. API MPMS Chapter 18.1, ``Measurement
Procedures for Crude Oil Gathered from
Small Tanks by Truck'', Second Edition,
April 1997.
(d) Sample oil from a tank... API MPMS Chapter 8.1, ``Standard Practice
for Manual Sampling of Petroleum and
Petroleum Products'', Third Edition,
October 1995 (ASTM D4057) or Chapter
8.2, ``Sampling of Liquid Petroleum and
Petroleum Products'', Second Edition,
October 1995 (ANSI/ASTM D4177).
(e) Gauge a tank............. API MPMS Chapter 3.1A, ``Standard
Practice for the Manual Gauging of
Petroleum and Petroleum Products'',
First Edition, December 1994 or API MPMS
Chapter 3.1 B, ``Standard Practice for
Level Measurement of Liquid Hydrocarbons
in Stationary Tanks by Automatic Tank
Gauging'', First Edition, April 1992
(Reaffirmed January 1997).
(f) Determine oil gravity.... API MPMS Chapter 9.1, ``Hydrometer Test
Method for Density, Relative Density
(Specific Gravity) or API Gravity of
Crude Petroleum and Liquid Petroleum
Products'' (ANSI/ASTM D 1298), June 1981
(Reaffirmed October 1992) (API MPMS
Chapter 9.1 1992).
(g) Determine oil temperature API MPMS Chapter 7.1, ``Static
Temperature Determination Using Mercury-
in-Glass Tank Thermometers'', First
Edition, February 1991 (Reaffirmed
November 1996).
(h) Determine sediment and API MPMS Chapter 10.4, ``Determination of
water in oil. Sediment and Water in Crude Oil by the
Centrifuge Method (Field Procedure)''
Second Edition, May 1988 (ASTM D96-88)
(Reaffirmed December 1993) (API MPMS
Chapter 10.4 1993).
------------------------------------------------------------------------

Lease Automatic Custody Transfer

Sec. 3153.30 How must I install and operate my LACT unit?

(a) Your LACT unit must be installed with all of the non-optional
primary components shown in Figure 1 of API MPMS Chapter 6.1, ``Lease
Automatic Custody Transfer (LACT) Systems'', Second Edition, May 1991
(Reaffirmed July 1996) (API MPMS Chapter 6.1, July 1996) and include
the following optional equipment--
(1) A positive displacement meter;
(2) An air/gas eliminator; and
(3) An automatic temperature/gravity compensator (ATC or ATG) or
electronic temperature averaging device.
(b) For all LACT units installed after [effective date of the final
rule], you must design, install, operate, and maintain your LACT system
to meet the specifications and requirements of--
(1) API Specification 11N, ``Specification for Lease Automatic
Custody Transfer (LACT) Equipment'', Fourth Edition, November 1, 1994;
and
(2) API MPMS Chapter 6.1, July 1996.
(c) If you installed your LACT system before [effective date of the
final rule] according to earlier versions of API references, you are
not required to retrofit to meet the API standards of this section.

Sec. 3153.31 How do I determine oil gravity and sediment and water
content of oil measured through my LACT?

You must determine oil gravity and sediment and water for the
sample obtained from the LACT sample container by following API MPMS
Chapter 9.1, 1992 (oil gravity) and API MPMS Chapter 10.4, 1993
(sediment and water).

Sec. 3153.32 How do I determine the composite meter factor for my LACT
meter?

(a) Prove your LACT meter with a pipe or tank prover, master meter,
or other API recognized meter prover so that you--
(1) Follow the applicable proving procedures of API MPMS Chapter
6.1, July 1996; and
(2) Make at least six proving runs when proving your meter, with
five consecutive proving runs within a span of 0.0005 (0.05 percent)
and compute the average of the five consecutive runs.
(b) If you cannot achieve five consecutive runs within 0.05 percent
during proving, you must--
(1) Use five consecutive runs that most accurately reflect
operation of your meter;
(2) Determine a malfunction meter factor using the procedures in
paragraph (d) of this section; and
(3) Immediately remove the meter from service and have it repaired.
(c) If your LACT system is equipped with an electronic temperature
averaging device, check its accuracy during the meter proving at
operating conditions with a mercury thermometer and adjust it if a
discrepancy in excess of 0.5 deg. F is observed.
(d) Calculate the composite meter factor using the procedures and
correction factors from--
(1) API MPMS Chapter 12.2, ``Calculation of Liquid Petroleum
Quantities Measured by Turbine or Displacement Meters'', First Edition,
September 1981 (Reaffirmed May 1996);
(2) API MPMS Chapter 11.1, Volume I, ``Table 5A-Generalized Crude
Oils and JP-4, Correction of Observed API Gravity to API Gravity at
60 deg.F'' and ``Table 6A--Generalized Crude Oils and JP-4, Correction
of Volume to 60 deg.F Against API Gravity at 60 deg.F'' (ANSI/ASTM D
1250-80) (IP 200) (API Standard 2540), August 1980 (Reaffirmed October
1993); and
(3) API MPMS Chapter 11.2.1, ``Compressibility Factors for
Hydrocarbons: 0-90 deg. API Gravity Range'', First Edition, August 1984
(Reaffirmed November 1995).

Sec. 3153.33 What requirements apply to the meter prover I use to
determine the LACT composite meter factor?

You must ensure that the meter prover you use to determine the LACT
composite meter factor has a certificate of calibration available for
review on site that shows--
(a) It was calibrated according to API standards within the last--
(1) 90 calendar days for master meters;
(2) 36 months for portable tank and pipe provers; or
(3) 60 months for stationary tank and pipe provers.
(b) The certified volume, as determined by the water draw method,
if the meter prover is a pipe or tank prover; or
(c) It is a master meter and has an operating factor within 0.9900
to 1.0100 and had five consecutive prover runs within 0.0002.

[[Page 66930]]

Sec. 3153.34 When must I determine the composite meter factor for my
LACT meter?

You must determine the composite meter factor for your LACT meter--
(a) Immediately after you install or repair it;
(b) Monthly, if more than 100,000 barrels of oil per month are
measured through the LACT;
(c) Quarterly, if between 10,000 and 100,000 barrels of oil per
month are measured through the LACT; or
(d) Semiannually, if less than 10,000 barrels of oil per month are
measured through the LACT.

Sec. 3153.35 What tolerance does BLM require for the LACT composite
meter factor?

Your composite meter factor must not change more than
0.0025 between provings.

Sec. 3153.36 What if the LACT composite meter factor changes more than
0.0025 between provings?

If the LACT composite meter factor changes more than
0.0025 between provings, you must repair or replace the
meter unless you can justify to BLM that the composite meter factor
change will not affect accurate oil measurement.

Sec. 3153.37 What notices and reports must I provide to BLM about
operation of my LACT system?

(a) You must notify BLM, orally or in writing, within five business
days--
(1) Prior to proving your LACT meter; and
(2) After you discover failure or malfunction of a LACT system
component that adversely affects accurate oil measurement.
(b) Within 10 business days after a required proving, you must
submit to BLM a completed meter proving report that contains--
(1) The information shown in one of the model forms of API MPMS
Chapter 12.2, 1996; and
(2) Information for BLM to identify the lease(s) and facility your
LACT meter services.

Sec. 3153.38 How do I correct volumes if my composite meter factor
changes between LACT provings?

(a) If your composite meter factor changes between LACT provings,
you must--
(1) Calculate an arithmetic average of the new and previous
composite meter factors and apply it to the volume metered between
provings; and
(2) Report volume corrections as required by MMS on the Monthly
Report of Operations, Form MMS-3160.
(b) If you conduct monthly LACT proving, you must make the required
volume correction and report on Form MMS-3160 for that month.

Measurement Tickets

Sec. 3153.40 How must I document the sale or removal of oil from my
production facility?

(a) Before oil is removed from your production facility, you must
complete a uniquely numbered measurement ticket with the following
information--
(1) Information to identify the seller and facility from which you
are selling;
(2) Start and stop totalizer readings (for LACT units) or opening
and closing gauge readings, oil temperatures, quality test results, and
the total volume of the oil sold (for tank gauging);
(3) Names and signatures of the gauger and the operator's
representative (for tank gauging); and
(4) Numbers of seals removed and installed.
(b) Maintain measurement tickets and provide them to BLM when
requested.

Subpart 3154--Gas Measurement

Gas Measurement

Sec. 3154.10 How do I measure and report gas production from Federal
and Indian lands?

(a) To measure and report gas production from Federal and Indian
lands, you must use a measurement system that--
(1) Has an established industry standard (i.e., American Petroleum
Institute (API), American Gas Association (AGA), American Society of
Testing and Materials (ASTM), American National Standard Institute
(ANSI)) for the accuracy, installation, operation, and maintenance of
the meter;
(2) Is designed, installed, operated, and maintained to--
(i) Follow the manufacturer's specifications and the applicable
industry standard;
(ii) Achieve an overall uncertainty of 3 percent of
reading, or better, over the normal operating range of the meter; and
(iii) Provide either a continuous mechanical recording or an
electronic record of the measured parameters at a sampling interval of
one hour or less;
(3) Displays all measured parameters in a location accessible to
BLM during normal working hours; and
(4) Is capable of being calibrated or proved using equipment
traceable to national standards.
(b) You must report the volume of gas that you produce to the
Minerals Management Service (MMS) on Form MMS-3160 under the
regulations in 30 CFR part 210. For reporting purposes, you must use a
base pressure of 14.73 psia and a base temperature of 60 deg. F; and
(c) You may estimate the amount of gas used for beneficial purposes
using--
(1) The equipment manufacturer's specification for consumption;
(2) The allocation based on the gas/oil ratio; or
(3) Other methods acceptable to BLM.

Orifice Meter--Primary Element

Sec. 3154.20 How must I install, operate, and maintain an orifice
meter?

(a) Your orifice meter must meet the specification and installation
requirements of--
(1) API Manual of Petroleum Measurement Standards (MPMS) Chapter
14.3, ``Orifice Metering of Natural Gas and Other Related Hydrocarbon
Fluids'', Second Edition, September 1985 (ANSI/API 2530), if it was
installed before [effective date of final rule]; and
(2) API MPMS Chapter 14.3, Part 2, ``Specification and Installation
Requirements'', Third Edition, February 1991 (ANSI/API 2530, Part 2,
1991) if it was installed after [effective date of final rule].
(b) If your orifice meter measures more than 100 Mcf of gas per
actual producing day on a monthly basis you must--
(1) Remove and inspect, and replace, if necessary, the orifice
plate at least once every six months; and
(2) Use a continuous temperature recorder to measure the flowing
gas temperature.
(c) If your orifice meter measures less than 100 Mcf of gas per
actual producing day on a monthly basis, some requirements in this
subpart may be different (see Sec. 3154.40).

Sec. 3154.21 How must I determine the volume of gas that passes
through my orifice meter?

You must calculate gas volumes that pass through your orifice meter
using the flow equations specified in API MPMS Chapter 14.3, Part 3,
``Natural Gas Applications'', Third Edition, August 1992.

Orifice Meter--Secondary Element

Sec. 3154.30 How must I record the differential and static pressures
on a chart recorder?

If your meter measures more than an average of 100 Mcf per actual
producing day, on a monthly basis, you must--
(a) Maintain the differential pressure in the upper 80 percent of
the chart, measured from zero, for the majority of the flowing periods,
unless well

[[Page 66931]]

conditions (e.g., erratic flow patterns) will not permit you to do so;
and
(b) Maintain the static pressure in the upper two thirds of the
physical distance on the chart, measured from zero, for the majority of
the flowing periods.

Sec. 3154.31 What additional requirements must I follow when using
electronic flow computers (EFC)?

Your EFC must--
(a) Display the instantaneous values of the static pressure,
differential pressure, and temperature; and
(b) Have a back up power device to allow the EFC to retain
collected data for a minimum of 35 calendar days.

Sec. 3154.32 How must I calibrate the secondary element of an orifice
meter?

(a) Follow the recommended practices for on-site calibrations of
orifice meters in Section 1.14 of the API MPMS, Chapter 20.1,
``Allocation Measurement'', First Edition, September 1993 (API MPMS
Chapter 20.1, 1993);
(b) In addition to the recommended test points in Section 1.14 of
API MPMS Chapter 20.1, 1993, test the differential and static elements
at 100 percent of the element range; and
(c) Document the calibration/inspection with a complete report of
station and meter data, test procedures, test results, corrective
actions, involved persons, dates, and signatures.

Sec. 3154.33 When must I calibrate the secondary element?

(a) You must calibrate the secondary element when--
(1) You install it;
(2) After you make any repairs to it; and
(3) Quarterly, if your meter measures more than an average of 100
Mcf per actual producing day, on a monthly basis.
(b) Submit a copy of the calibration report to BLM within five
business days after we request it.

Orifice Meters--Low Volume Exemptions

Sec. 3154.40 What measurement standards apply if I use an orifice
meter and measure an average of 100 Mcf of gas, or less, per producing
day on a monthly basis?

If you use an orifice meter and measure an average of 100 Mcf of
gas, or less, per producing day on a monthly basis--
(a) You are not required to maintain your beta ratio within the
range specified in ANSI/API 2530, Part 2, 1991;
(b) You are not required to measure flowing gas temperature with a
continuous temperature recorder. Instead, you must use a temperature
that reasonably represents the average flowing temperature of the gas
stream in your volume calculations;
(c) You may record the differential pressure on any portion of the
chart range if you use a chart recorder;
(d) You may record the static pressure on any portion of the chart
range for the majority of the flowing periods if you use a chart
recorder;
(e) You are not required to inspect your meter tube more than once
every six years; and
(f) You are not required to calibrate your meter and inspect your
orifice plate more than annually unless BLM requires more frequent
calibration or inspection.

Other Metering Systems

Sec. 3154.50 What standards must I follow if I measure gas by a
metering system other than an orifice meter?

If you measure gas by a metering system other than an orifice
meter, you must--
(a) Meet the requirements of Sec. 3154.10;
(b) Use a system that either directly measures the temperature of
the gas stream or compensates for temperature; and
(c) Calibrate or prove your system semiannually or at such times as
BLM otherwise requires.

Volume Corrections

Sec. 3154.60 How do I correct volumes if my meter did not measure
accurately?

(a) If a meter calibration or proving shows that a volume error
occurred, you must correct the volume back to when the error occurred,
if known. If you do not know when the error occurred, correct the
volume for the last half of the time period that elapsed since the last
calibration or proving;
(b) If your measuring equipment is out of service or malfunctions
so that you do not know the quantity of gas delivered, you must
estimate the volume by the most accurate method available; and
(c) You must report volume corrections under this section as
required by MMS on Form MMS-3160.

Gas Quality Measurements

Sec. 3154.70 How do I determine the quality of my gas stream?

(a) Conduct a test to determine the specific gravity and the
heating value of the gas stream at least annually, or as otherwise
required by BLM. Testing procedures and results must be provided to BLM
upon request.
(b) Collect a gas sample at the measurement point on the lease or
at another location BLM approved.
(c) Follow the sample collection and handling procedures in API
MPMS Chapter 14.1, ``Collecting and Handling of Natural Gas Samples for
Custody Transfer'', Fourth Edition, August 1993.
(d) Determine the specific gravity of your sample by--
(1) Continuous recording gravitometer; or
(2) Compositional analysis through at least the normal hexane
(C⁶H¹⁴) component of a spot or cumulative gas
sample.
(e) Determine the heating value of your sample by--
(1) A recording calorimeter; or
(2) Compositional analysis through at least the normal
C⁶H¹⁴ component of a spot or cumulative gas
sample.

Subpart 3155--Produced Water Disposal

Produced Water Disposal

Sec. 3155.10 Why must I obtain approval from BLM to dispose of water
produced from my lease?

You must obtain BLM's approval to dispose of water produced from
your lease to ensure that--
(a) Disposal of produced water does not adversely affect Federal or
Indian lands and resources, or public health and safety;
(b) Removal of produced water from a Federal or Indian oil and gas
lease does not adversely affect Federal or Indian lands and resources,
or public health and safety; and
(c) Facilities used for the disposal of produced water are
authorized and operating in compliance with the terms of their permits.

Sec. 3155.11 When do I need BLM approval to dispose of produced water?

Except for the conditions described in Sec. 3155.12, you must
obtain BLM's approval before you--
(a) Dispose of produced water from a Federal or Indian well on a
Federal or Indian lease;
(b) Remove produced water from a Federal or Indian well for
disposal--
(1) Off of the lease it is produced from, regardless of the
physical location of the disposal facility; or
(2) On State or privately owned land within the same communitized
or unitized area; or
(c) Remove produced water from a communitized or unitized private
or State well, if disposal occurs on Federal or Indian land within the
same communitized or unitized area.

[[Page 66932]]

Sec. 3155.12 When may I dispose of produced water without BLM
approval?

BLM approval is not required to dispose of produced water if you--
(a) Inject it into the same formation from which it is produced as
part of an enhanced recovery project approved by BLM or Bureau of
Indian Affairs;
(b) Inject it into an approved disposal well on the same Federal or
Indian lease; or
(c) Inject it or dispose of it in the same well bore and formation
from which it is produced.

Sec. 3155.13 What type of water disposal will BLM allow?

BLM will allow water disposal by methods including, but not limited
to--
(a) Injection into the subsurface;
(b) Discharge into lined or unlined pits;
(c) Surface discharge under a National Pollution Discharge
Elimination System (NPDES) permit;
(d) Discharge to commercial pits or open top tanks designed for
containing produced water; or
(e) Disposal to facilities designed to reuse or treat produced
water.

Sec. 3155.14 What BLM forms and Environmental Protection Agency, State
or Indian Tribe permits must I submit to BLM if I plan to dispose of
produced water?

(a) When BLM approval for produced water disposal is necessary
under Sec. 3155.11, you must submit a Sundry Notice and Report on Wells
(SN), Form 3160-5, or other filing instrument acceptable to BLM, that
describes your disposal method and location of disposal facilities.
(b) If you intend to dispose of produced water within the same
Federal or Indian lease or communitized or unitized area, in
conjunction with construction of disposal facilities on a Federal or
Indian lease, your SN must include your construction plans following
the additional well operation requirements of subpart 3145, if you
intend to--
(1) Convert an existing well to an injection well;
(2) Construct an earthen pit or an NPDES facility; or
(3) Construct roads or pipelines.
(c) If you intend to dispose of produced water within the same
Federal or Indian lease or communitized or unitized area, in
conjunction with drilling a new well or reentering an abandoned well on
a Federal or Indian lease, you must submit an Application for Permit to
Drill or Reenter (APD), Form 3160-3, following the requirements of
subpart 3145.
(d) You must obtain a right-of-way (R/W) authorization for the use
of BLM lands according to part 2800 of this chapter if you--
(1) Drill, convert, construct or operate disposal facilities, or
construct roads and pipelines off of your lease but on BLM managed
surface; or
(2) Operate disposal facilities on your lease where you dispose of
produced water from operations off of your lease.
(e) You may attach to your APD, SN or R/W application the
information that you prepare to obtain an Underground Injection Control
Permit (UIC), earthen pit disposal, or NPDES permit(s) in its original
form. BLM will accept this information toward fulfilling the
requirements of subpart 3145 and this subpart.
(f) Include with your SN, APD or R/W either--
(1) Copies of UIC, earthen pit, or NPDES permits you have received
for the disposal facilities you intend to use; or
(2) The location of these existing or proposed disposal facilities
and their permit name/number.
(g) You may use the APD or SN package to furnish the information
BLM requires to process a R/W instead of filing a R/W plan of
development. If you choose this option, the APD or SN will serve as a
R/W application even though BLM will issue two separate approval
documents (APD or SN and R/W grant).
(h) If your proposal involves off-lease activities on surface BLM
does not manage, you must contact the appropriate surface management
agency or surface owner for surface use permits.
(i) Follow the requirements of subpart 3145 for drilling and
additional well operations if you drill or convert a well under a BLM
R/W grant.

Sec. 3155.15 What additional requirements must I follow for water
disposal into pits?

(a) For produced water disposal into lined and unlined pits, you
must submit to BLM information on the--
(1) Daily quantity of water you plan to dispose of;
(2) Quality of the produced water, unless specifically waived by
BLM for lined pits. If the volume of produced water disposed of does
not exceed more than an average of five barrels of produced water per
day, based on the amount of produced water expected per month, you are
not required to submit a water quality analysis unless BLM requests it;
(3) Source of your produced water; and
(4) How you intend to handle emergencies, if BLM requests it.
(b) Your use of a lined pit must follow the standards in this
paragraph and your application must show how you will--
(1) Ensure adequate storage capacity considering climatic factors
that affect fluid levels;
(2) Ensure stability of the pit and its levees;
(3) Include periodic and proper disposal of precipitated solids;
(4) Use an impermeable liner that will withstand the effects of
weather, contained liquids and solids, and other characteristics of
your site;
(5) Provide safe containment of produced water, and associated
liquids and solids, to prevent pit leakage and contamination of soils,
surface waters, groundwater and intermittent drainage;
(6) Prevent discharges of liquid hydrocarbons to the pit;
(7) Prevent access by livestock and wildlife, unless otherwise
approved by BLM, the surface management agency, Indian, or private
surface owner;
(8) Deter entry by birds, if liquid hydrocarbons discharge to the
pit or if water contained in the pit could injure birds; and
(9) Include a leak detection system that adequately detects
leakage, and plans to monitor it.
(c) Your use of unlined pits must follow all of the objectives for
lined pits except for paragraphs (b)(3), (b)(4), and (b)(9) of this
section, and your application must show how you will meet these
conditions.

Sec. 3155.16 When may I use an unlined pit for produced water
disposal?

You may use an unlined pit for produced water disposal, if you can
meet the requirements of Sec. 3155.15(c), and you can demonstrate to
BLM in your application that your produced water--
(a) Is of equal or better quality than existing surface and
subsurface water sources, and State or Federal water quality standards,
including standards for toxic constituents;
(b) Will primarily be used for beneficial purposes, such as
irrigation, livestock, or wildlife, and meets minimum water quality
standards for such uses;
(c) Will not exceed an average of five barrels of produced water
per day based on the amount of produced water expected per month; or
(d) Will not degrade the quality of surface or subsurface waters,
and soils in the area.

Sec. 3155.17 If the quantity and quality of my produced water changes,
do I need a new approval from BLM to continue using an unlined pit?

You must submit an amended proposal for BLM's approval if your
produced water does not satisfy the

[[Page 66933]]

standard used to obtain the original approval to use an unlined pit.

Sec. 3155.18 What must I submit to BLM for surface discharge that
requires NPDES permit?

For surface discharge that requires a NPDES permit you must submit
to BLM--
(a) A SN, Form 3160-5, including a description of site facilities;
(b) A current water quality analysis;
(c) Your plans for surface use from the origin of the produced
water to the point of discharge;
(d) A copy of the NPDES permit or the location of the existing or
proposed NPDES facility and its permit name or number; and
(e) Information that supported obtaining the NPDES permit, if BLM
requests it.

Sec. 3155.19 What if the EPA, State, or Indian Tribe cancels or
suspends the permit for a disposal facility I am using?

If the EPA, State, or Indian Tribe cancels or suspends the permit
for a disposal facility you are using, BLM will terminate your water
disposal permit immediately and you must submit a new proposal to BLM.

Subpart 3156--Spills and Accidents

Spills and Accidents

Sec. 3156.10 What action must I take after an accident or spill that
involves Federal or Indian production?

After an accident or spill that involves Federal or Indian
production--
(a) Take immediate corrective actions to control the spill or
accident; and
(b) Report spills and accidents to BLM that could affect the public
health and safety or adversely affect lease or off-lease resources to--
(1) Allow BLM to determine if--
(i) Your loss of oil or gas is subject to royalty collection;
(ii) Corrective orders are needed; or
(iii) A contingency plan is needed to address potential future
events.
(2) Provide BLM the opportunity to approve your reclamation and
remediation plans and monitor the results of these operations.

Sec. 3156.11 How soon after a spill or accident must I report it to
BLM?

You must notify BLM within 24 hours of--
(a) Oil and saltwater spills that individually or in combination
result in the discharge of 100 or more barrels of liquid during a
single event;
(b) Equipment failures or other accidents that release 500 Mcf or
more of gas;
(c) Any fire that consumes volumes in the ranges described in
paragraphs (a) or (b) of this section;
(d) Any spill, venting, or fire, regardless of the volume involved,
which occurs in or near a sensitive area, such as parks, recreation
sites, threatened and endangered species habitat, riparian areas, water
bodies, or urban or suburban areas;
(e) Each accident that involves a major, life-threatening, or fatal
injury;
(f) Every time loss of well control occurs; or
(g) Releases of hazardous substances of a quantity that is
reportable under Environmental Protection Agency regulations at 40 CFR
part 302.

Sec. 3156.12 When must I submit a written report on spills and
accidents to BLM?

You must submit a written report to BLM within 10 business days, or
such longer period BLM may approve, for events listed in Sec. 3156.11
and for--
(a) Spills that individually or collectively involve between 10 and
100 barrels of liquid during a single event;
(b) Releases that involve between 50 and 500 Mcf of gas; and
(c) Fires that consume volumes in the ranges described in
paragraphs (a) and (b) of this section.

Sec. 3156.13 What must I include in my report of a spill or accident?

(a) In addition to a description of the facility involved, the
applicable lease name or number and your official contact for the
event, your report to BLM of a spill or accident must include--
(1) When and where the spill or accident occurred;
(2) Whether sensitive areas are affected;
(3) The direct and indirect causes of the event;
(4) An estimate of volumes of material discharged and lost;
(5) A description of any injuries, damage, or contamination;
(6) What you or response teams are doing to control and clean up
the spill or accident, including using emergency pits;
(7) Your plans for reclaiming or remediating areas affected by the
spill or accident; and
(8) Your plans to prevent a repeat of the incident.
(b) If BLM requests it, you must also submit a--
(1) Copy of the Spill Prevention Control and Countermeasure Plan
required by the Environmental Protection Agency according to the
regulations at 40 CFR part 112, or a contingency plan that completely
describes your plans to prevent and control future occurrences; and
(2) Reclamation or remediation plan that follows the requirements
for additional well operations in subpart 3145.

Sec. 3156.14 When must I submit follow-up written reports to BLM about
a spill or accident?

You must submit follow-up written reports of a spill or accident
if--
(a) You do not document clean up in the first report you submit;
(b) BLM requests additional reports to monitor ongoing efforts to
control or investigate a spill or an accident; or
(c) BLM requests additional reports to document progress and
completion of reclamation or remediation.

Subpart 3159--Well Abandonment

Temporary Abandonment

Sec. 3159.10 How do I obtain BLM approval to temporarily abandon all
or a portion of a Federal or Indian well?

You must--
(a) Receive BLM approval before you temporarily abandon all or a
portion of a well for more than 30 calendar days;
(b) Submit an application for temporary abandonment of a well to
BLM on Sundry Notices and Reports on Wells (SN) Form 3160-5. In it you
must--
(1) Explain the reasons for temporarily abandoning, rather than
permanently abandoning, utilizing, or producing your well or zone; and
(2) Describe your plans for securing the wellbore and describe any
additional surface disturbance or partial reclamation not previously
approved in your Application for Permit to Drill or Deepen (APD); and
(c) If your well is located on Forest System lands, follow the
requirements of Sec. 3145.11(a).

Sec. 3159.11 How do I temporarily abandon a well?

You must design and perform your temporary abandonment using
acceptable industry practices so that--
(a) It does not prevent proper permanent abandonment;
(b) The well bore or zone(s) is secured to prevent fluid migration
within or out of the well bore; and
(c) The wellhead is secured at the surface, as appropriate.

Permanent Abandonment

Sec. 3159.20 When must I permanently plug and abandon my well?

(a) You must promptly plug and abandon each well you operate in
which oil or gas is no longer capable of being

[[Page 66934]]

produced in paying quantities, unless BLM approves your well for some
other use or delays your permanent abandonment.
(b) You must have BLM approval before you begin plugging operations
on your well.
(c) BLM may approve temporary abandonment and delay the permanent
abandonment of your well for up to 12 months.
(d) BLM may approve additional delays, up to 12 months for each
delay approved, if BLM determines that additional delays are in the
interest of conservation.
(e) BLM will require you to post additional bond in accordance with
Secs. 3107.55 and 3107.56, as a condition of delaying permanent
abandonment of your well.

Sec. 3159.21 How do I obtain BLM approval to permanently plug and
abandon my well?

(a) You must submit to BLM a Notice of Intent to Abandon (NIA) on a
SN, that describes the--
(1) Current downhole condition of your well, if you have not
already provided it to BLM;
(2) Type, size, and placement of plugs you proposed for use in your
well to isolate zones of concern and protect surface and subsurface
useable waters;
(3) Casing you will recover from your well;
(4) Cement slurry design, including necessary additives for
specific downhole conditions; and
(5) Methods you will use to maintain well control of your well when
you anticipate high pressure or hydrogen sulfide.
(b) Unless BLM previously approved the following activities in your
APD, your NIA must also describe--
(1) How you will handle and dispose of pit and other wastes;
(2) When and how you will remove structures, equipment, and other
materials;
(3) When you will schedule dirtwork and seeding; and
(4) How you will address any special aspect of reclamation, such as
recontouring and requirements of surface management agencies or private
surface owners.
(c) If the well you propose to plug and abandon is located on
National Forest System lands, you must comply with applicable Forest
Service requirements; and
(d) BLM may orally approve a request to begin plugging dry holes or
drilling failures in emergency situations. You must submit an NIA to
BLM within five business days to confirm the oral approval.

Sec. 3159.22 How must I permanently plug and abandon a well?

To permanently plug and abandon a well, you must--
(a) Design and perform your plugging operations according to the
standards in Section 2 of American Petroleum Institute's (API) Bulletin
E3, ``Well Abandonment and Inactive Well Practices for U.S. Exploration
and Production Operations, Environmental Guidance Document'', First
Edition, January 1993, to--
(1) Protect or isolate all formations containing useable quality
water;
(2) Prevent fluid and gas migration within and out of the well
bore; and
(3) Protect all prospectively valuable deposits of oil, gas,
geothermal resources, or other minerals;
(b) Use a minimum of 10 percent excess cement per 1000 feet of
depth for each plug placed in the well;
(c) Use a minimum of 25 sacks of cement for any plug placed through
tubing, except for the surface plug;
(d) Fill each of the intervals between plugs with a fluid of
sufficient density to prevent formation fluid from entering the
wellbore and to prevent plug movement;
(e) Test for placement of critical plugs;
(f) Reclaim the disturbed surface in a timely manner according to
your approved reclamation plan and comply with Secs. 3145.11, 3145.13,
3145.14, 3145.15, and 3145.55; and
(g) Permanently inscribe the operator name, lease identification,
well name/number and legal location on the permanent well marker (for
wells cut off below ground level only the lease identification and well
name/number must be inscribed on the cover plate). The well marker
should be of size and design so as not to be visually intrusive and
must be securely attached to the well.

Sec. 3159.23 When must I test plug placement?

You must perform a plug placement test by tagging the plug with the
working pipe string or other method BLM approved when--
(a) The cement plug(s) is the only isolating medium for a usable
water zone or a prospectively valuable mineral deposit and the fluid
level will not remain static; or
(b) Plug integrity is questionable.

Sec. 3159.24 What must I do if the surface owner or surface management
agency requests that I convert a well I plan to plug and abandon into a
water well?

If the surface owner or surface management agency requests that you
convert a well you plan to plug and abandon into a water well--
(a) The surface owner or surface managing agency must notify BLM in
writing that it will assume responsibility for the portion of the well
bore used for the water well;
(b) You must not begin any action to convert to a water well until
BLM approves your NIA application; and
(c) You may perform the additional work needed to complete the
conversion to a water well by an agreement between you and the surface
owner or surface managing agency, but at a minimum you must--
(1) Plug your well from total depth to the base of the usable water
zone; and
(2) Complete reclamation of the disturbed area as approved.

Sec. 3159.25 What if my approved plans for well abandonment change
after I receive BLM approval?

You must request approval, either orally or by SN, before
performing any changes from your approved plan. If BLM gives you oral
approval, you must document the changes on the Subsequent Report of
Abandonment (SRA), SN Form 3160-5, as required in Sec. 3159.26(a).

Sec. 3159.26 What must I submit to BLM after I permanently abandon my
well and complete reclamation measures?

After you permanently abandon your well and complete reclamation
measures, you must--
(a) Submit the SRA to BLM within 30 calendar days after you
complete well plugging operations. The SRA must document in detail the
plugging process, including any changes BLM approved orally;
(b) Document the estimated timetable for completing recontouring
and reclamation procedures on the SRA; or
(c) Submit a separate Final Abandonment Notice (FAN) on a SN when
you complete all reclamation and the site is ready for final
inspection.
12. Revise part 3160--Onshore Oil and Gas Operations to read as
follows:

PART 3160--OIL AND GAS INSPECTION AND ENFORCEMENT

Subpart 3161--Inspections

Inspections

Sec.
3161.10 Will BLM inspect my operations on Federal and Indian
leases?
3161.11 Who may inspect my lease operations?
3161.12 Can BLM inspect motor vehicles that transport oil produced
from or allocated to my Federal or Indian lease?

[[Page 66935]]

Subpart 3162--Enforcement

Enforcement

3162.10 What action will BLM take if I do not comply with
applicable laws, the regulations in this part, the terms of any
lease or permit, or the requirements of any notice or order?
3162.11 How will BLM notify me of violations and enforcement
actions?
3162.12 May BLM shut down my operations for any violation?

Subpart 3163--Assessments

Assessments

3163.10 Will BLM assess me if I do not correct a violation?
3163.11 What violations will subject me to an immediate assessment?
3163.12 May BLM reduce assessments?
3163.13 Under what circumstances will BLM enter my lease to correct
violations?
3163.14 May BLM charge me for any loss or damage that results from
my noncompliance?

Subpart 3164--Civil Penalties

Civil Penalties

3164.10 What civil penalties may BLM assess?
3164.11 Will BLM notify me if I do not comply with any statute,
regulation, order, Notice to Lessee, lease, or permit relating to my
obligations under this part?
3164.12 What must I do after I receive an Incident of Noncompliance
notice (INC)?
3164.13 Are there any violations for which I will be subject to an
immediate penalty?
3164.14 What action will BLM take if I do not correct the
violations listed in Sec. 3164.13?
3164.15 May BLM reduce the amount of proposed civil penalties?
3164.16 May I request a hearing on the record if I am served with
an INC for a serious violation?
3164.17 If I request a hearing on the record, do penalties accrue?
3164.18 If I requested a hearing on the record under
Sec. 3164.12(a)(3) or Sec. 3164.16, may I appeal that decision?
3164.19 If I requested a hearing under Sec. 3164.12 or
Sec. 3164.16, may I appeal a final order to a U.S. District Court?

Payment of Assessments and Civil Penalties

3164.20 When must I pay assessments and civil penalties under the
regulations in this subpart?
3164.21 What if I do not pay, or I underpay, an assessment or civil
penalty?
3164.22 Will BLM require me to pay both assessments and civil
penalties?
3164.30 If I violate the regulations in this part, am I liable for
both civil and criminal penalties?

Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359, and
1751; and 43 U.S.C. 1732(b), 1733 and 1740.

Subpart 3161--Inspections

Inspections

Sec. 3161.10 Will BLM inspect my operations on Federal and Indian
leases?

BLM will inspect your lease to ensure your operations comply with--
(a) Applicable laws and regulations;
(b) Terms of the lease;
(c) Terms and conditions of permits and other approvals;
(d) Notices to Lessees; and (e) Written orders or other BLM
instructions.

Sec. 3161.11 Who may inspect my lease operations?

(a) You must allow authorized, properly identified representatives
of the Secretary and BLM access to your lease sites, secured
facilities, and records, without advance notice, to conduct inspections
and investigations.
(b) For the purpose of making any inspection or investigation,
authorized, properly identified representatives of the Secretary and
BLM may have access to any site where you store oil and gas that was
produced from or allocated to Federal or Indian leases.

Sec. 3161.12 Can BLM inspect motor vehicles that transport oil
produced from or allocated to my Federal or Indian lease?

(a) On any lease site on Federal or Indian lands, an authorized,
properly identified representative of the Secretary or BLM may stop and
inspect any motor vehicle (see 30 U.S.C. 1718), which he or she has
probable cause to believe is carrying oil either produced from or
allocable to a Federal or Indian lease, to determine whether the driver
has the documentation required by Sec. 3152.70.
(b) Off your lease site, an authorized, properly identified
representative of the Secretary or BLM, accompanied by a law
enforcement officer, or a law enforcement officer alone, may stop and
inspect any motor vehicle (see 30 U.S.C. 1718), which he or she has
probable cause to believe is carrying oil either produced from or
allocable to a Federal or Indian lease, to determine whether the driver
has the documentation required by Sec. 3152.70.

Subpart 3162--Enforcement

Enforcement

Sec. 3162.10 What action will BLM take if I do not comply with
applicable laws, the regulations in this part, the terms of any lease
or permit, or the requirements of any notice or order?

(a) If you failed to comply with applicable laws, the regulations
in this part, the terms of any lease or permit, or the requirements of
any notice or order, BLM will--
(1) Notify you of the violation unless immediate action is
warranted under Sec. 3162.12
(2) Give you a reasonable period to correct the violation. The
period BLM allows you to comply will depend on the seriousness of the
violation; and
(3) Take other enforcement actions as described in this part to
ensure you correct the violation.
(b) If you discover and report a violation to BLM, we will confirm
your report in writing and establish a reasonable period to correct it.
(c) BLM will extend the compliance period if you provide acceptable
justification for an extension before the end of the compliance period.

Sec. 3162.11 How will BLM notify me of violations and enforcement
actions?

(a) BLM will notify you of any requirements or enforcement
actions--
(1) Verbally, followed in writing; or
(2) In writing, delivered by registered mail or by personal
service.
(b) You are served with notice on the date you receive written
notice from BLM, or within seven business days after BLM mails it to
your last known address in BLM records, whichever is earlier.

Sec. 3162.12 May BLM shut down my operations for any violation?

(a) BLM may require you to shut down your operations if--
(1) You are not in compliance with any requirements of Sec. 3163.11
(a) through (e); or
(2) Continued operations could have an immediate, substantial and
adverse impact on public health and safety, the environment, production
accountability, or royalty income.
(b) BLM may require you to shut down your operations only after
giving you written notice under Sec. 3162.11, except in emergencies, in
which case BLM may require you to shut down your operations immediately
without notice.
(c) You must not resume operations without BLM approval.

Subpart 3163--Assessments

Assessments

Sec. 3163.10 Will BLM assess me if I do not correct a violation?

Except as provided in Sec. 3163.11, if you do not correct a
violation within the time BLM gives you to correct it under
Sec. 3162.10--
(a) BLM will assess you up to $250 per day for each day each
violation continues, beginning on the first day after the end of the
compliance period and ending when the violation(s) is corrected; and

[[Page 66936]]

(b) You may be liable for proposed civil penalties under subpart
3164.

Sec. 3163.11 What violations will subject me to an immediate
assessment?

BLM will immediately charge you the indicated assessment upon
discovery of each of the following violations, regardless of when the
violation actually occurred and whether you subsequently correct the
violation--

--------------------------------------------------------------------------------------------------------------------------------------------------------
If you-- The assessment amount is--
--------------------------------------------------------------------------------------------------------------------------------------------------------
(a) Fail to install blowout preventer or $5,000.
equivalent well control equipment, as
required by the approved drilling or
operating plan.
(b) Begin drilling operations without 10,000.
approval.
(c) Disturb the surface, regardless of 5,000.
surface ownership, without approval to
conduct operations for Federal or Indian
wells.
(d) Begin plugging and abandonment 2,500.
operations without approval.
(e) Commingle production from different 500.
formations, leases, communitized areas,
units, and/or unit participating areas
without BLM approval.
(f) Have been cited for the same type of 500 for the fifth and each subsequent violation within 12 months.
violation four times on the same lease
within a 12 month period.
(g) Destroy or remove a Federal seal without 500.
approval.
(h) Fail to notify BLM of H2S concentrations 500.
as required by Sec. 3151.20.
--------------------------------------------------------------------------------------------------------------------------------------------------------

Sec. 3163.12 May BLM reduce assessments?

BLM may waive or reduce assessments authorized under this subpart.
You must submit to BLM written justification why your assessment should
be reduced within 30 calendar days after you receive notice of the
assessment.

Sec. 3163.13 Under what circumstances will BLM enter my lease to
correct violations?

(a) When necessary for compliance, BLM may occupy your lease and
perform, or have performed, operations that you were directed in
writing to perform, at your risk and expense.
(b) BLM will charge you for the actual cost of performing the work,
plus an additional 25 percent for administrative costs.

Sec. 3163.14 May BLM charge me for any loss or damage that results
from my noncompliance?

BLM will charge you the value of any actual loss or damage that
results from your noncompliance.

Subpart 3164--Civil Penalties

Civil Penalties

Sec. 3164.10 What civil penalties may BLM assess?

BLM may assess civil penalties under the Federal Oil and Gas
Royalty Management Act of 1982 (30 U.S.C. 1719). These civil penalties
are in addition to any assessment you may be liable for under subpart
3163.

Sec. 3164.11 Will BLM notify me if I do not comply with any statute,
regulation, order, Notice to Lessee, lease term, or permit relating to
my obligations under this part?

(a) If you do not comply with any statute, regulation, order,
Notice to Lessee, lease term, or permit relating to your obligations
under this part, BLM may issue a Notice of Incident of Noncompliance,
Form 3160-9 (INC).
(b) BLM must serve the INC by personal service by an authorized BLM
representative or by registered mail. Service by registered mail occurs
when received or seven business days after the date it is mailed,
whichever is earlier.
(c) The notice will set out the--
(1) Violation and the remedial action required;
(2) Amount of the penalty applicable for each day the violation
continues; and
(3) Length of time for which the penalty will be assessed.

Sec. 3164.12 What must I do after I receive an Notice of Incident of
Noncompliance (INC)?

(a) When BLM issues you an INC under this subpart--
(1) You must correct the violation within 20 calendar days (or such
longer time as the notice specifies) from the date that the notice is
served, or you are liable for a penalty of up to $500 per violation for
each day the violation continues, dating from the date you were served
notice;
(2) You must correct the violation within 40 calendar days (or such
longer time as the notice specifies) from the date that the notice is
served, or you are liable for a penalty of up to $5,000 per violation
for each day the violation continues, dating from the date you were
served notice; or
(3) If you do not correct the violation within 20 calendar days (or
such longer time as the notice specifies) from the date that the notice
is served, you may, by that date, request a hearing on the record by
filing a written request with the Hearings Division (Departmental),
Office of Hearings and Appeals, U.S. Department of the Interior, 4015
Wilson Boulevard, Arlington, Virginia 22203.
(b) If you correct the violation within 20 calendar days (or such
longer time as the notice specifies) from the date that the notice is
served, BLM will not assess penalties under this subpart and you are
not entitled to a hearing on the record provided for in paragraph
(a)(3) of this section. You may appeal the INC or other disputed BLM
decision or order under Sec. 3101.22.

Sec. 3164.13 Are there any violations for which I will be subject to
an immediate penalty?

BLM may issue you an INC for a serious violation. You will receive
notice in the same manner as Sec. 3164.11. Penalties for serious
violations begin to accrue on the date the violation occurred according
to the following table--

----------------------------------------------------------------------------------------------------------------
Violation Civil penalty amount
----------------------------------------------------------------------------------------------------------------
(a) Any person transporting oil from your Up to $500 per violation per day.
lease who does not permit BLM to review the
documentation required under Sec. 3152.70.
(b) You or your representative fails or Up to $10,000 per violation per day.
refuses to allow lawful entry or inspection.
(c) You knowingly or willfully fail to notify Up to $10,000 per violation per day.
BLM before the fifth business day after your
well begins production or resumes production
after being off production for more than 90
calendar days.

[[Page 66937]]

(d) You or your representative knowingly or Up to $25,000 per violation per day.
willfully prepares, maintains or submits
false, inaccurate or misleading reports,
notices, affidavits, records, data or other
written information.
(e) You or your representative knowingly or Up to $25,000 per violation per day.
willfully takes or removes, transports, uses
or diverts any oil or gas from or allocable
to any Federal or Indian lease site, without
having the authority to do so.
(f) You or your representative purchases, Up to $25,000 per violation per day.
accepts, sells, transports or conveys to
another, any oil or gas, having reason to
know that the oil or gas was stolen or
unlawfully removed or diverted from any
Federal or Indian lease site or a lease site
with oil or gas allocable to a Federal or
Indian lease.
----------------------------------------------------------------------------------------------------------------

Sec. 3164.14 What action will BLM take if I do not correct the
violations listed in Sec. 3164.13?

(a) For transporters that do not produce the documentation required
under Sec. 3152.70,--
(1) BLM will issue an INC under Sec. 3164.11;
(2) BLM will order Federal and Indian oil and gas producers in the
area to prohibit the transporter from removing crude oil or other
liquid hydrocarbons from all Federal or Indian leases or from any
facility which receives or stores production allocable to a Federal or
Indian lease; and
(3) BLM's order will remain in effect until the transporter
complies and pays the assessed civil penalty.
(b) For violations listed in Sec. 3164.13 (b) through (f), BLM may
begin procedures to cancel your lease under either subpart 3144, or in
the case of Indian lands, recommend to BIA that it initiate lease
cancellation procedures.

Sec. 3164.15 May BLM reduce the amount of proposed civil penalties?

BLM may waive or reduce civil penalties under the regulations in
this subpart. You must justify in writing why your proposed civil
penalty should be reduced and submit your justification to BLM within
30 calendar days after you receive notice of the proposed civil
penalty.

Sec. 3164.16 May I request a hearing on the record if I am served with
an INC for a serious violation?

If you are served with an INC for a serious violation under
Sec. 3164.13, you have 20 calendar days from the date of service to
file a written request for a hearing on the record with the Hearings
Division (Departmental), Office of Hearings and Appeals, U.S.
Department of the Interior, 4015 Wilson Boulevard, Arlington, Virginia
22203.

Sec. 3164.17 If I request a hearing on the record, do penalties
accrue?

If you request a hearing on the record under Sec. 3164.12(a)(3) or
Sec. 3164.16, penalties will accrue each day until you correct the
violations in the INC. BLM may suspend the requirement to correct the
violations pending completion of the hearings provided for in this
subpart.

Sec. 3164.18 If I requested a hearing on the record under
Sec. 3164.12(a)(3) or Sec. 3164.16, may I appeal that decision?

If you request a hearing on the record under Sec. 3164.12(a)(3) or
Sec. 3164.16, the hearing will be conducted by an Administrative Law
Judge (ALJ) (Departmental), Office of Hearings and Appeals. After the
hearing, the ALJ will issue a decision in accordance with the evidence
presented and applicable law. Any party to a case adversely affected by
a decision of the ALJ may appeal that decision to the Interior Board of
Land Appeals under part 4 or part 1840 of this title.

Sec. 3164.19 If I requested a hearing under Sec. 3164.12 or
Sec. 3164.16, may I appeal a final order to a U.S. District Court?

If you timely requested a hearing under Sec. 3164.12 or
Sec. 3164.16, and are aggrieved by a final order, you may seek review
of the order in the U.S. District Court for the judicial district in
which the violation allegedly took place. Review by the District Court
will be only on the administrative record and not de novo. Such action
will be barred unless filed within 90 calendar days after the final
order.

Payment of Assessments and Civil Penalties

Sec. 3164.20 When must I pay assessments and civil penalties under the
regulations in this subpart?

(a) You must pay--
(1) Assessments within 30 calendar days of receipt of a Bill for
Collection, Form 1371-22. If sent by certified mail, BLM will consider
you to have received the Bill for Collection on the date you received
it, or within seven business days after BLM mailed it, whichever comes
first; and
(2) Civil penalties within 30 calendar days of the final order BLM
issues or in the case of an appeal of a BLM decision to the District
Court, as specified in the final order of the Court.
(b) Civil penalties you owe under these regulations may be deducted
from any monies that the United States may owe you.

Sec. 3164.21 What if I do not pay, or I underpay, an assessment or
civil penalty?

(a) For assessments, BLM will charge you interest on the balance
due at the current interest rate stated by the Department of Treasury
as the ``Treasury Current Value of Funds Rate.'' Interest will be
calculated from the date your assessment is due through the date
payment is received.
(b) For civil penalties, the Court may impose sanctions for
nonpayment or underpayment.

Sec. 3164.22 Will BLM require me to pay both assessments and civil
penalties?

(a) BLM may require you to pay both assessments and civil
penalties. However, BLM will deduct any assessment amount you paid from
the amount of civil penalties you owe.
(b) Any civil penalties you are assessed under this subpart are in
addition to any penalties or assessments you are charged for your acts
of noncompliance under provisions of other laws.

Sec. 3164.30 If I violate the regulations in this part, am I liable
for both civil and criminal penalties?

You may be liable for both civil and criminal penalties under 30
U.S.C. 1720 for violating these regulations.
[FR Doc. 98-31671 Filed 12-2-98; 8:45 am]
BILLING CODE 4310-84-P

Visit the Official Version

Document Information

Published:: 12/03/1998
Department:: Land Management Bureau
Entry Type:: Proposed Rule
Action:: Proposed rule.
Document Number:: 98-31671
Dates:: Comments: Commenters must submit comments by April 5, 1999. BLM will consider comments received or postmarked on or before this date in the preparation of the final rule.
Pages:: 66840-66937 (98 pages)
Docket Numbers:: WO-310-1310-00-2I-IP
RINs:: 1004-AC94: Oil and Gas Leasing and Operations
RIN Links:: https://www.federalregister.gov/regulations/1004-AC94/oil-and-gas-leasing-and-operations
PDF File:: 98-31671.pdf
CFR: (677): 43 CFR 3105.20); 43 CFR 3129.37); 43 CFR 3137.80); 43 CFR 3107.52); 43 CFR 3142.30(a); More ...