[Federal Register Volume 59, Number 14 (Friday, January 21, 1994)]
[Unknown Section]
[Page 0]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 94-1487]
[[Page Unknown]]
[Federal Register: January 21, 1994]
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DEPARTMENT OF ENERGY
Pick-Sloan Missouri Basin Program-Eastern Division--Notice of
Rate Order No. WAPA-60
AGENCY: Western Area Power Administration, DOE.
ACTION: Notice of Rate Order--Pick-Sloan Missouri Basin Program-Eastern
Division (P-SMBP-ED) firm electric service rate adjustment.
-----------------------------------------------------------------------
SUMMARY: Notice is given of the confirmation and approval by the Deputy
Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-60
and Rate Schedules P-SED-F6 and P-SED-FP6 placing increased firm power
and firm peaking power rates for the P-SMBP-ED into effect on an
interim basis. The interim rates, called the provisional rates, will
remain in effect on an interim basis until the Federal Energy
Regulatory Commission (FERC) confirms, approves, and places them into
effect on a final basis or until they are replaced by other rates. A
comparison of existing and provisional rates follows:
Eastern Division Provisional Rate Changes
--------------------------------------------------------------------------------------------------------------------------------------------------------
Provisional rates February 1, Provisional rates October 1,
Type of service Existing rates 1994, and percent change 1994, and percent change
--------------------------------------------------------------------------------------------------------------------------------------------------------
FIRM COMMERCIAL:
Composite Rate...................................... 12.16 (mills/kWh)............. 13.31 (mills/kWh) 9.5%........ 14.23 (mills/kWh) 7.0%.
Firm Energy......................................... 7.09 (mills/kWh).............. 7.76 (mills/kWh) 9.5%......... 8.32 (mills/kWh) 7.2%.
Firm Capacity....................................... $2.74/kW-month................ $3.00/kW-month, 9.5%.......... $3.20/kW-month 6.7%.
Tiered > 60 percent L.F............................. 3.38 (mills/kWh).............. 3.38 mills/kWh................ 3.38 mills/kWh.
Firm Peaking:
Peaking Capacity.................................... $2.74/kW-month................ $3.00/kW-month, 9.5%.......... $3.20/kW-month, 6.7%.
Peaking Energy...................................... 7.09 mills/kWh................ 7.76 (mills/kWh) 9.5%......... 8.32 (mills/kWh) 7.2%.
--------------------------------------------------------------------------------------------------------------------------------------------------------
DATES: Rate Schedules P-SED-F6 and P-SED-FP6 will be placed into effect
on an interim basis on the first day of the first full billing period
beginning on or after February 1, 1994, and will be in effect until
FERC confirms, approves, and places the rate schedules into effect on a
final basis for a 5-year period, or until the rate schedules are
superseded.
FOR FURTHER INFORMATION CONTACT:
Mr. James D. Davies, Area Manager, Billings Area Office, Western
Area Power Administration, P.O. Box 35800, Billings, MT 59107-5800,
(406) 657-6532;
Ms. Deborah M. Linke, Director, Division of Marketing and Rates,
Western Area Power Administration, P.O. Box 3402, Golden, CO 80401-
3398, (303) 231-1545;
Mr. Joel Bladow, Assistant Administrator for Washington Liaison,
Western Area Power Administration, Room 8G-061, Forrestal Building,
1000 Independence Avenue SW., Washington, DC 20585-0001, (202) 586-
5581.
SUPPLEMENTARY INFORMATION: By Amendment No. 3 to Delegation Order No.
0204-108, published November 10, 1993 (58 FR 59716), the Secretary of
Energy delegated (1) the authority to develop long-term power and
transmission rates on a nonexclusive basis to the Administrator of
Western Area Power Administration (Western); (2) the authority to
confirm, approve, and place such rates into effect on an interim basis
to the Deputy Secretary; and (3) the authority to confirm, approve, and
place into effect on a final basis, to remand, or to disapprove such
rates to FERC. Existing DOE procedures for public participation in
power rate adjustments (10 CFR part 903) became effective on September
18, 1985 (50 FR 37835).
These power rates are established pursuant to section 302(a) of the
DOE Organization Act, 42 U.S.C. 7152(a), through which the power
marketing functions of the Secretary of the Interior and the Bureau of
Reclamation (Reclamation) under the Reclamation Act of 1902, 43 U.S.C.
371 et seq., as amended and supplemented by subsequent enactments,
particularly section 9(c) of the Reclamation Project Act of 1939, 43
U.S.C. 485h(c), and other acts specifically applicable to the project
system involved, were transferred to and vested in the Secretary of
Energy (Secretary).
Discussions on the proposed rate adjustments were initiated on
January 26, 1993, when a letter announcing the preliminary informal
customer meetings was mailed to all firm power customers and other
interested persons. These meetings were conducted at four different
locations on February 5, 8, 9, and 10, 1993. At these preliminary
meetings, Western representatives explained the need for the rate
increases and answered questions from those attending.
The consultation and comment period was initiated on July 8, 1993,
with publication of a Federal Register notice (58 FR 36684) that
officially announced the proposed rate adjustments and procedures for
public participation. The Federal Register notice announced a series of
public information forums that were held on July 20, and August 9-11,
1993, in Northglenn, Colorado; Sioux Falls, South Dakota; Fargo, North
Dakota; and Billings, Montana. Public comment forums were held in
Northglenn, Colorado, and Sioux Falls, South Dakota, on August 30 and
31, 1993, respectively. The consultation and comment period concluded
October 6, 1993.
During the comment period, Western received 10 comment letters on
the Pick-Sloan Missouri Basin Program (P-SMBP) rate adjustment. At the
August 30 and 31, 1993, public comment forums, one person commented
orally. All comments were considered in preparation of the rate order.
Western has concluded that the P-SMBP rate adjustments are needed to
meet cost-recovery criteria.
The proposed rate adjustments are based upon the fiscal year (FY)
1992 power repayment study (PRS). To prepare the ratesetting PRS,
Western considered projections which will be used in the final FY 1993
PRS. Western's objective is to mitigate the rapidly increasing deficits
due to reduced surplus sales revenue and increasing purchased power
expense resulting from the drought on the P-SMBP. Using this concept,
Western developed a two-step rate adjustment. The first step is based
upon the FY 1992 PRS with 5 future years of purchased power expense and
1 future year of reduced surplus sales revenue. The second step is
based on the FY 1992 PRS utilizing 5 years of projected increased
purchased power expense and reduced surplus sales revenue for 1 year.
In the second step, Western also included expected increases in
operations and maintenance (O&M) expenses and 1 additional year of
power investment. By implementing this two-step rate adjustment,
Western is providing P-SMBP customers with a more accurate basis for
budgeting their future power costs as well as mitigating the impact of
the rate increases.
In Rate Order No. WAPA-60, results of the ratesetting PRS are being
compared to the FY 1990 PRS, which was the basis for the existing P-
SMBP rates. The comparison shows the following differences:
1. The projected O&M expenses, including the integrated projects,
for the 100-year period have increased a total of $10.2 million per
year.
2. Purchased power projected over the future 6-year period is $113
million. These costs are partially attributable to the extended drought
which necessitated the Bureau of Reclamation and the Corp of Engineers
to draw down the reservoirs to an extremely low level. This has caused
Western to project future purchased power expenses for the next few
years until the reservoirs are full again. Although FY 1993 was an
above-average water year, purchased power expenses are continuing to be
projected because the flooding in the Midwest severely restricted water
releases and therefore severely curtailed power generation.
3. Reduced surplus sales and increased purchased power costs
appearing historically in the study, as a result of the drought in the
Missouri Basin, have now accumulated $126 million in unpaid annual
expenses, which have been capitalized. These and expected unpaid annual
expenses over the next 2 years are projected to be repaid by 2002.
4. The power investments projected over the future 6-year period
are $286 million. New power investments, other than replacements, are
not projected beyond the 6-year period.
Of the above factors, the one item with the greatest rate impact is
the drought, which is reflected in the purchased power expenses and
capitalized unpaid annual expenses. The second greatest impact comes
from O&M expenses, which are increasing due to inflation as well as
responding to programmatic and administrative requirements, such as
safety programs and environmental compliance.
Rate Order No. WAPA-60, confirming, approving, and placing the
proposed P-SMBP-ED rate adjustments into effect on an interim basis, is
issued, and the new Rate Schedules P-SED-F6 and P-SED-FP6 will be
submitted promptly to FERC for confirmation and approval on a final
basis.
Issued in Washington, DC, January 6, 1994.
Bill White,
Deputy Secretary.
Order Confirming, Approving, and Placing the Pick-Sloan Missouri Basin
Program-Eastern Division Firm Power Service Rates Into Effect on an
Interim Basis
In the matter of: Western Area Power Administration Rate
Adjustments for Pick-Sloan Missouri Basin Program-Eastern Division,
Rate Order No. WAPA-60
January 6, 1994.
These power rates are established pursuant to section 302(a) of the
Department of Energy (DOE) Organization Act, 42 U.S.C. 7152(a), through
which the power marketing functions of the Secretary of the Interior
and the Bureau of Reclamation (Reclamation) under the Reclamation Act
of 1902, 43 U.S.C. 371 et seq., as amended and supplemented by
subsequent enactments, particularly section 9(c) of the Reclamation
Project Act of 1939, 43 U.S.C. 485h(c), and other acts specifically
applicable to the Pick-Sloan Missouri Basin Program (P-SMBP), were
transferred to and vested in the Secretary of Energy.
By Amendment No. 3 to Delegation Order No. 0204-108, published
November 10, 1993 (58 FR 59716), the Secretary of Energy delegated (1)
the authority to develop long-term power and transmission rates on a
nonexclusive basis to the Administrator of the Western Area Power
Administration (Western); (2) the authority to confirm, approve, and
place such rates into effect on an interim basis to the Deputy
Secretary; and (3) the authority to confirm, approve, and place into
effect on a final basis, to remand, or to disapprove such rates to the
Federal Energy Regulatory Commission. Existing DOE procedures for
public participation in power rate adjustments (10 CFR part 903) became
effective on September 18, 1985 (50 FR 37835).
Acronyms and Definitions
As used in this rate order, the following acronyms and definitions
apply:
$/kW-month: Monthly charge for capacity (usage - Sec. per kilowatt-
month).
BAO: Western's Billings Area Office.
Corps: U.S. Army Corps of Engineers.
Criteria: Post-1989 General Power Marketing and Allocation Criteria;
Pick-Sloan Missouri Basin Program-Western Division, 51 FR 4012
(January 31, 1986) and Eastern Division Pick-Sloan Missouri Basin
Program Final Post-1985 Marketing Plan, 45 FR 71860 (October 30,
1980).
CROD: Contract Rate of Delivery.
Customer Brochure: A document prepared for public distribution
explaining the background of the rate proposal contained in this
rate order.
DOE: Department of Energy.
DOE Order RA 6120.2: An order dealing with power marketing
administration financial reporting.
FERC: Federal Energy Regulatory Commission.
Fry-Ark: Fryingpan-Arkansas Project.
FY: Fiscal year.
Interior: U.S. Department of the Interior.
kW: Kilowatt.
kW-month: The greater of (1) the highest 30-minute demand measured
during the month, not to exceed the contract obligation, or (2) the
contract rate of delivery.
kWh: Kilowatthour.
LAO: Western's Loveland Area Office.
LAP: Loveland Area Projects.
M&I: Municipal and industrial.
mills/kWh: Mills per kilowatthour.
MW: Megawatt.
O&M: Operation and maintenance.
pinch-point: The FY in which the level of the rate is set as
dictated by a revenue requirement in that future year to meet
relatively large annual costs or to repay investments which come
due.
PMA: Power marketing administration.
PRS: Power repayment study.
P-SED-F5: Pick-Sloan Eastern Division's existing rate schedule for
firm power service.
P-SED-F6: Pick-Sloan Eastern Division's provisional rate schedule
for firm power service.
P-SED-FP5: Pick-Sloan Eastern Division's existing rate schedule for
firm peaking service.
P-SED-FP6: Pick-Sloan Eastern Division's provisional rate schedule
for firm peaking service.
P-SMBP: Pick-Sloan Missouri Basin Program.
P-SMBP-ED: Pick-Sloan Missouri Basin Program-Eastern Division.
P-SMBP-WD: Pick-Sloan Missouri Basin Program-Western Division.
Reclamation: Bureau of Reclamation, U.S. Department of the Interior.
Treasury: Secretary of the Department of the Treasury.
Western: Western Area Power Administration, U.S. Department of
Energy.
Effective Date
The new rates will become effective on an interim basis on the
first day of the first full billing period beginning on or after
February 1, 1994, and will be in effect pending FERC's approval of
them, or substitute rates, on a final basis for a 5-year period, or
until superseded.
Public Notice and Comment
The procedures for public participation in power and transmission
rate adjustments and extensions, 10 CFR part 903, have been followed by
Western in the development of these firm power rates. These firm power
rates represent an increase of more than 1 percent in total P-SMBP-ED
revenues; therefore, it is a major rate adjustment as defined at 10 CFR
903.2(e) and 903.2(f)(1). The distinction between a minor and a major
rate adjustment is used only to determine the public procedures for the
rate adjustment.
The following summarizes the steps Western took to ensure
involvement of interested parties in the rate process:
1. Discussion of the proposed rate adjustments was initiated on
January 26, 1993, when a letter announcing informal customer meetings
was mailed to all firm power customers and other interested parties.
The 1993 meetings were held on the following dates: February 5 in
Billings, Montana; February 8 in Sioux Falls, South Dakota; February 9
in Denver, Colorado; and February 10 in Fargo, North Dakota. At these
informal meetings, Western representatives explained the need for the
increase and answered questions from those attending.
2. On March 9, 1993, a customer brochure was mailed to all
customers and other interested persons. This mailing also included a
letter announcing the four public information forums and two comment
forums.
3. On March 11, 1993, a letter was mailed to all customers and
other interested persons on the delay of the publishing of the Federal
Register notice. The public information forums and comment forums were
also delayed.
4. A Federal Register notice was published on July 8, 1993 (58 FR
36684), officially announcing the proposed firm power rate adjustments,
initiating the public consultation and comment period, announcing the
information and comment forums, and presenting procedures for
participation.
5. On July 14, 1993, letters were mailed to all P-SMBP-ED customers
and interested persons announcing the publication of the Federal
Register notice of July 8, 1993. This mailing also included a letter
announcing four public information forums and two comment forums.
6. The public information forums were conducted on the following
dates: July 20 in Northglenn, Colorado; August 9 in Billings, Montana;
August 10 in Sioux Falls, South Dakota; and August 11 in Fargo, North
Dakota. At these forums, Western representatives explained the need for
the rate increases in greater detail and answered questions.
7. Western received an extensive request for information from one
customer group. We responded by providing data and background
information for the ratesetting PRS.
8. The comment forums were held on August 30, 1993, at Northglenn,
Colorado, and August 31, 1993, at Sioux Falls, South Dakota, to give
the public an opportunity to comment for the record. One person
representing a customer and customer group made oral comment at the
August 30, 1993, forum. Western received no comments at the August 31,
1993, forum.
9. Ten comment letters were received during the 91-day consultation
and comment period. The consultation and comment period ended October
6, 1993. All formally submitted comments have been considered in the
preparation of this rate order.
Project History
The initial stages of the Missouri River Basin Project were
authorized by section 9 of the Flood Control Act of 1944 (58 Stat. 877,
891). The Missouri River Basin Project, later renamed the P-SMBP to
honor its two principal authors, has been under construction since
1944. The P-SMBP encompasses a comprehensive program of flood control,
navigation improvement, irrigation, M&I water development, and
hydroelectric production for the entire Missouri River Basin.
Multipurpose projects have been developed on the Missouri River and
its tributaries in Colorado, Montana, Nebraska, North Dakota, South
Dakota, and Wyoming.
Power Repayment Studies
PRSs are prepared each FY to determine if power revenues will be
sufficient to pay, within the prescribed time periods, all costs
assigned to the power function. Repayment criteria are based on law,
policies, and authorizing legislation. DOE Order RA 6120.2, section
12b, requires that:
In addition to the recovery of the above costs (operation and
maintenance and interest expenses) on a year-by-year basis, the
expected revenues are at least sufficient to recover (1) each dollar
of power investment at Federal hydroelectric generating plants
within 50 years after they become revenue producing, except as
otherwise provided by law; plus, (2) each annual increment of
Federal transmission investment within the average service life of
such transmission facilities or within a maximum of 50 years,
whichever is less; plus, (3) the cost of each replacement of a unit
of property of a Federal power system within its expected service
life up to a maximum of 50 years; plus, (4) each dollar of assisted
irrigation investment within the period established for the
irrigation water users to repay their share of construction costs;
plus, (5) other costs such as payments to basin funds, participating
projects, or States.
Existing and Provisional Rates
Eastern Division
The existing firm power rates and the provisional firm power rates
necessary to meet the revenue requirements for the P-SMBP-ED are listed
below. The provisional rates will be implemented in two steps. Step 1
rates are to become effective on an interim basis on the first day of
the first full billing period beginning on or after February 1, 1994.
Step 2 rates are to become effective on the first day of the first full
billing period beginning on or after October 1, 1994.
A comparison of the existing and provisional rates follows:
Eastern Division Provisional Rate Changes
----------------------------------------------------------------------------------------------------------------
Provisional rates, Provisional rates,
Type of service Existing rates February 1, 1994 October 1, 1994
----------------------------------------------------------------------------------------------------------------
Firm Power Service Rate Schedule:
Composite Rate................ 12.16 mills/kWh\1\...... 13.31 mills/kWh\2\...... 14.23 mills/kWh.\2\
Firm Capacity................. $2.74/kW-month\1\....... $3.00/kW-month\2\....... $3.20/kW-month.\2\
Firm Energy................... 7.09 mills/kWh\1\....... 7.76 mills/kWh\2\....... 8.32 mills/kWh.\2\
Tiered > 60 percent L.F....... 3.38 mills/kWh\1\....... 3.38 mills/kWh\2\....... 3.38 mills/kWh.\2\
Firm Peaking Power Service Rate
Schedule:
Peaking Capacity.............. $2.74/kW-month\3\....... $3.00/kW-month\4\....... $3.20/kW-month.\4\
Peaking Energy................ 7.09 mills/kWh\3\....... 7.76 mills/kWh\4\....... 8.32 mills/kWh.\4\
----------------------------------------------------------------------------------------------------------------
\1\P-SED-F5.
\2\P-SED-F6.
\3\P-SED-FP5.
\4\P-SED-FP6.
Western Division
The LAP rate will be designed to recover the P-SMBP-WD revenue
requirements for P-SMBP and the revenue requirements for Fry-Ark. The
adjustment to the LAP rates is a separate formal procedure which is
documented in Rate Order No. WAPA-61. Rate Order No. WAPA-61 is also
scheduled to go into effect on the first day of the first full billing
period beginning on or after February 1, 1994. The LAP rates will yield
the revenue requirements for FY 1994-98 for the P-SMBP-WD.
Certification of Rate
Western's Administrator has certified that the P-SMBP-ED firm power
rates placed into effect on an interim basis herein are the lowest
possible consistent with sound business principles. The rates have been
developed in accordance with administrative policies and applicable
laws.
Discussion
Although the P-SMBP is considered a single entity for financial and
repayment purposes, the power generated by the P-SMBP is marketed in
two separate and distinct areas. These are known as the Eastern
Division and the Western Division, and each has its own marketing plan
and method of designing rates to collect required revenue from power
sales.
The existing and provisional revenue requirements for the Eastern
and Western Divisions for the P-SMBP are as follows:
P-SMBP Firm and Peaking Revenue Requirement
[In millions]
------------------------------------------------------------------------
First Second
adjustment adjustment
Current February October
1994 1994
------------------------------------------------------------------------
Eastern Division Firm Commercial. $103.1 $112.9 $120.8
Eastern Division Peaking......... 12.3 13.5 14.4
--------------------------------------
Total Eastern Division
Revenue Requirement....... $115.4 $126.4 $135.2
======================================
Western Division Firm Commercial. 28.0 30.3 31.4
--------------------------------------
Total P-SMBP Firm and
Peaking Revenue
Requirement............... $143.4 $156.7 $166.6
------------------------------------------------------------------------
The revenue increases are necessary to satisfy the cost-recovery
criteria set forth in DOE Order RA 6120.2.
Statement of Revenue and Related Expenses
The following table provides a summary of revenue and expense data
through the 5-year provisional rate approval period.
Pick-Sloan Missouri Basin Program--Comparison of 5-Year Rate Approval
Period
[Revenues and Expenses ($1,000)]
------------------------------------------------------------------------
FY 1990 PRS Ratesetting
1994-98 PRS 1994-98 Difference
------------------------------------------------------------------------
Total Revenues................... $1,064,628 $1,199,151 $134,523
Revenue Distribution:
O&M.......................... $540,919 $678,407 $137,488
Purchased Power.............. 9,300 75,000 65,700
Interest..................... 307,913 422,954 115,041
Investment Repayment......... 143,233 53,363 (89,870)
Capitalized Expenses......... 0 (30,573) (30,573)
Integrated Projects.......... 63,263 0 (63,263)
--------------------------------------
Total.................... $1,064,628 $1,199,151 $134,523
------------------------------------------------------------------------
Basis for Rate Development--P-SMBP-ED
The P-SMBP-ED rates were designed to continue to maintain an
approximate 50/50 split between revenue earned from the demand and
energy charges as a basis for the rate design. The revenue yield will
vary among customers because of a customer's individual load
characteristics.
The interim rates contain a $3.00/kW-month firm capacity charge and
a 7.76 mills/kWh firm energy charge in FY 1994 which will yield the
necessary revenue for the first year of the rate-approval period,
effective on the first day of the first full billing period on or after
February 1, 1994. To provide the additional necessary revenue, an
increase to $3.20/kW-month firm capacity charge and an 8.32 mills/kWh
firm energy charge will be in effect on the first day of the first full
billing period beginning on or after October 1, 1994. The rate-approval
period terminates on January 31, 1999.
Comments
During the 91-day comment period, Western received 10 letters
containing written comments pertaining to this rate adjustment. In
addition, one person representing a group of customers commented during
the August 30, 1993, public comment forum. We received no comments at
the August 31, 1993, forum. All comments were reviewed and considered
in the preparation of this rate order.
Written comments were received from the following sources:
Loveland Area Customer Association (Colorado, Wyoming, Kansas,
Nebraska)
Tri-State Generation and Transmission Association, Inc. (CO, WY, NE)
City of Litchfield (Minnesota)
Lower Brule Sioux Tribe (South Dakota)
Nebraska Public Power District (Nebraska)
City of Lincoln (Nebraska)
Missouri Basin Municipal Power Agency (SD, ND, MN, and IA)
Basin Electric Power Cooperative (ND, SD, MN, IA, MT, WY, and CO)
East River Electric Power Cooperative (South Dakota)
A representative of the following organizations made an oral
comment:
Loveland Area Customer Association
Tri-State Generation and Transmission Association, Inc.
Comments received at the public meetings and in correspondence
dealt with controlling costs, Eastern Division firm peaking power rate
design, and projections of revenue and expenses. The comments and
responses, paraphrased for brevity, are discussed below. Direct quotes
from comment letters are used for clarification where necessary.
Issue: Customers suggested that Western should not participate in
new transmission projects whose cost will affect firm power rates,
unless the facilities are needed to reliably meet its firm power
obligations or the facilities will result in net financial savings to
the firm power revenue requirement.
Response: Proposals for new facilities must first pass one of three
criteria before we will consider construction: increased revenues from
the new facility must exceed the annual cost, or customers must benefit
sufficiently to support the project in spite of a possible rate
increase, or the project will be funded from non-Federal sources. We
will continue our construction program as necessary to ensure we
provide reliable service.
Issue: Customers are concerned with the rate at which O&M expenses
have increased and are projected to increase in the PRS.
Response: Western received several comments concerned with
controlling costs related to O&M expenses. One recognized that costs
appear to be supportable, one asked for mitigation of the rate impact,
and one suggested an opportunity for review and comment on expenditures
of Western, the Bureau, and the Corps. Presently, Western has such an
interaction with the customer group in the Eastern Division of Pick-
Sloan. This comment is from a Western Division customer group. There
are several Western Division customers who do participate in the
Eastern Division interaction; the majority of the Western Division
customer group do not. We propose to extend an invitation to the
Western Division customer groups to participate in the Eastern Division
interaction or we will provide a similar opportunity specifically for
the Western Division.
One commenter observed that P-SMBP O&M costs have increased at a
rate that is far greater than the Consumer Price Index (CPI). O&M
expenses are increasing due to inflation which is reflected in the CPI
as well as responding to programmatic and administrative requirements,
such as safety and environmental compliance. These expenses have been
reviewed both internally by Western and with power customer
representatives. Western continues to share the power customers'
concerns with Reclamation and the Corps and has received assurances
from each agency that each will participate in the cost-containment
programs associated with O&M functions. Western remains committed to
cost containment while striving for efficiency and providing customer
service. Western plans to continue its O&M expense review process with
power customers and involve customer representatives in its cost-
containment discussions.
Issue: Customers of firm peaking power have stated that the Eastern
Division firm peaking rate is arbitrary, unfair, and discriminatory in
light of the type of service provided by this commodity.
Response: We received comments from two customers expressing this
concern. They observed that the capacity charge for firm peaking is
keyed to the seasonal CROD. That is, the firm peaking customers pay for
the capacity reserved for them in each month as opposed to the method
used for the firm commercial customers who pay only for the maximum
capacity delivered to them each month. They questioned the cost of
providing capacity for peaking customers vs. firm commercial customers.
Logic tells us that the costs for providing or reserving capacity
in the system are the same for each class of service. If we were to
assume that all fixed costs in a hydro-based system are to be recovered
by the capacity charge, and since hydro-based systems do not have fuel
costs, the purchased energy costs are the only variable costs to be
recovered by the energy charge. This means that the firm commercial and
firm peaking capacity charge must recover all costs except the
purchased energy costs which are to be recovered by the energy charge.
Western traditionally recovers 50 percent of its firm revenue
requirements from capacity charges and 50 percent from the energy
charges. Western has chosen this methodology to balance the impact of
allocating the costs for firm service between customers with a high
load factor and customers with a low load factor.
We received comments from a customer supporting the present rate
design for peaking capacity. One customer stated that they were
satisfied with the peaking product, but urged Western in its FY 1995
rate review process to revise its methodology of applying the rate to
peaking service. In interactions between peaking customers and Western,
we have discussed several options to make the peaking product more
flexible to better meet the customers' needs. Many of the options
discussed would have added more costs to providing the product or
limited the flexibility of the P-SMBP generating system and, therefore,
could not be supported by Western.
Western is not changing the peaking rate methodology at this time.
However, in the next rate adjustment, we will consider other methods of
applying the peaking rate or modifying the product.
Issue: Several customers commented that the second adjustment
should not be implemented by this rate adjustment process and a second
rate adjustment process should be performed next year after more facts
are known.
Response: In discussions with various customer groups prior to this
rate adjustment process, we were urged to find a method to limit the
number of times we proceed through the rate process. This two-step
process reduces both Western's and its customers' expense associated
with proceeding through multiple rate adjustment processes. Our
response to this request is to determine the first rate and project the
second step. Therefore, assuming our projections are accurate, we will
have saved the expense of one of two rate adjustment processes. Even
though we do not expect to process a rate adjustment in the second
year, we will test our rate and our assumptions in the second year. If
the projection falls short of repaying the cost of the project, in
accordance with DOE Order RA 6120.2, we would initiate a rate
adjustment process. This calls for the question, ``What if the rate is
too high in the second year?'' The P-SMBP has capitalized $126 million
of annual expenses through the end of FY 1992. Until that amount is
repaid, revenues which are surplus to the immediate annual needs of the
project will be applied to these deficits.
This two-step rate adjustment has allowed Western's customers to
better budget and provides a longer-term planning window. When Western
is not processing a rate adjustment, Western shares the results of its
annual PRS and supporting data with its customer groups and thoroughly
reviews the underlying assumptions and results.
For these reasons, Western is proceeding with the two-step rate
adjustment.
Issue: It was suggested by one customer group that Western should
divide Pick-Sloan revenue requirements between the Eastern and Western
Divisions on the basis of the firm capacity and energy of each Division
rather than energy alone, and that this should be done on the basis of
total revenue requirements rather than the incremental basis presently
used.
Response: The different bases for the two marketing plans do not
readily permit an across-the-board comparison of the capacity available
from P-SMBP-WD and P-SMBP-ED. It was determined by LAO and BAO that the
most appropriate method to distribute costs was on the basis of
contributed energy from each division. This has permitted an ``apples-
to-apples'' comparison of the relative contribution of each division's
resources while continuing to pool resources and expenses.
The marketing plans of P-SMBP-ED and LAP were prepared
independently and take different approaches to the way that capacity is
marketed. For LAP, capacity is marketed on a fixed basis, with ``take-
or-pay'' amounts for monthly capacity. This capacity is marketed with
energy at less than the average customer load factor. P-SMBP-ED
marketed capacity on a proportional basis; that is, capacity is
marketed as a percentage of each customer's total monthly demand. This
method is commonly referred to as the ``X/Y'' method. Also, capacity
for the Eastern Division was marketed with ``load factor'' energy, with
any remaining capacity resources being marketed as peaking capacity
without energy.
Western recognizes that there are numerous ways to market power,
divide expenses, compute available resources, and forecast future
impacts. The method chosen to share costs and revenues between the
Eastern and Western Divisions of P-SMBP is consistent with the
marketing criteria and represents a fair and equitable solution to the
customers of both areas. This decision was made with careful
consideration given to the relative contribution of resources,
investments, and expenses of each division to the total project.
Western does not propose to revise the allocation of firm power revenue
requirements for Eastern and Western Divisions in this rate adjustment.
Western will continue to observe its revenue-distribution methodology
to determine if future circumstances necessitate a change, and will
continue to work with customers to better understand and address these
concerns.
Issue: Several customers commented that Western's proposal to
decrease the amount of firm sales used in the electric service rate
calculation for LAP was inappropriate and that amount should be
reallocated, and that there were inconsistencies in the projected level
of power purchases.
Response: This issue is applicable only to LAP and, accordingly, is
discussed in Rate Order No. WAPA-61.
Issue: Several customers commented that Western's provisional firm
power rate is too high.
Response: Several individual customer comments requested mitigation
of the rate and one customer indicated that although the rate
adjustments are significant, the adjustments were understandable and
supportable. A customer group commented that the firm power rate was
overstated and pointed to several areas where either expense
projections should be reduced or projections of revenues should be
increased. We have addressed each of the identified areas as a separate
issue, and the decision on each is reflected in the response.
Issue: Western could reduce its purchased power projection by
utilizing the hydrology projections to forecast purchased power
requirements.
Response: Western uses hydrology projections coupled with
historical experience to project purchased power expense. This
projection has been increasingly difficult to do in recent years
because of the drought, as well as the ensuing flood and the endangered
species operating restrictions. We have found that the purchased power
expense can be underestimated when the hydrology projections alone are
used to project purchased power expense. If Western had ignored
historical purchased power trends and used only hydrology projections
to forecast purchased power, we would have again underestimated that
expense. There was so much water downstream, causing the floods in the
Midwest, the P-SMBP water releases were greatly curtailed, thus
reducing its generating ability. Western will continue to review its
projection methods as suggested. The purchased power projection in this
study, which uses a combination of factors, follows the historical
trend better than the projection utilizing the hydrology data alone;
therefore, Western is not revising the projections at this time.
Issue: Western should update its generation projections to reflect
the storage condition incurred as a result of the above-average inflows
for FY 1993.
Response: The Corps is presently preparing and revising generation
projections for this very reason. Those projections will be used in
preparing the next FY's PRS. At that time we will also have a record of
the additional costs incurred and reduced generation in FY 1993 as a
result of flood mitigation accomplished by reduced water releases from
the dams on the Pick-Sloan Missouri Basin System. We believe it is
premature to revise only the generation projections without considering
all impacts to the system. The generation projections in the
ratesetting study correspond to the budget projections used in that
study. The next year's PRS will consider all of these effects. At this
time, it is our position that the additional costs incurred as a result
of the flooding will offset the short-term benefits from nearly full
reservoirs.
Issue: Western should monitor actual losses on the transmission
system and update the loss factors used in its PRS in the future.
Response: We agree with this suggestion and will do this in the PRS
for the next FY.
Issue: Western should not use projected depletions beyond the cost
evaluation period.
Response: The position presented by the commenter points to the
fact the Bureau and Corps recognize projections of stream-flow
depletions which are unreliable. The quotes from the Bureau and the
Corps have been taken out of context. The statements made by the Bureau
and Corps are related to the short-term. During a drought, depletions
are higher than forecast, and during wet years, depletions are lower
than forecast. The long-term projections of depletions are based upon
normal usage. If we accept long-term development of future projects, we
must consider these depletions. Normal depletions would seem most
reasonable. We do not agree that projection of depletions can be
ignored when future projects are known to impact depletions.
Issue: Western should revise its other revenue projections in the
PRS to include additional revenues.
Response: The commenters pointed to three areas where they saw a
possibility of change:
1. Second-year revenues--The commenter had questioned the reduction
of special sales by approximately $7.5 million and the increased
Western Division transmission revenues of $1.7 million in the second-
year revenue projections.
The reduction of special sales revenues is an estimate based upon
the impact of reduced generation in the second year, which was an
expectation at the time of the estimate. Western feels it's appropriate
to leave the estimated projection. The second item is the projected
Western Division transmission revenue increases expected from the
proposed rate adjustment. We agree with this in principle; however, if
the rate adjustment is implemented as proposed, it has no significant
impact on the overall rate adjustment. It would reduce only the first
step of the rate adjustment by a few hundredths of a mill/kWh. Western
is not proposing to make the change for this rate adjustment; however,
in the future, when a transmission rate adjustment is being proposed at
the same time as a firm power rate adjustment, we will reflect proposed
changes in transmission revenues on a prospective basis rather than
after the fact.
2. Irrigation pumping rate--The commenter suggested that Western
should actively encourage Reclamation to promptly complete the studies
which could lead to a revision of the project-use pumping rates.
Western has been in contact with Reclamation concerning the
revision of their project-use rate. They have budgeted funds in FY 1994
to perform the ``ability to pay studies'' for their irrigation pumping
customers. We have provided study data which could define the rate
required to cover O&M and annual replacement expenses associated with
the power system. Western will continue to actively pursue this issue
with Reclamation.
3. Revenue from monthly sales over 60-percent load factor--The
future revenues from the ``tiered'' energy rate are not reflected in
the PRS. This is correct; however, the expense for purchasing this
energy is also not projected in the PRS. If Western were to project the
revenue for the monthly sales over 60-percent load factor, we would
need to project offsetting purchased power costs. Therefore, adding
these elements to the PRS is not rate impacting. We propose not to add
the elements to the current ratesetting study but to add them to future
PRSs for display purposes.
Issue: Western should project future interest rates in the PRS
instead of using the current-year rate for all future years.
Response: Western uses the rate required by DOE Order RA 6120.2,
sections 10.i. and 11.b., for all future investments. Section 10.i.
states that forecasts for PRSs will utilize the rate for the latest
available year established by the Secretary of the Treasury and that
this rate shall be used for all future years. Section 11.b. defines the
criteria used by the Department of the Treasury to determine the rate
each year.
The present rate is computed on the basis of interest-bearing
Treasury securities which, at the time the computation is made, have
terms of 15 years or more to maturity. On this basis, short-term
fluctuations in market prices are removed and projections have built-in
stability based upon a ``rolling average'' each year. In effect,
volatile changes in the rate are mitigated through the blending
process.
While it is true that the interest rate may decrease in the FY 1994
PRS, estimating a new rate would be no more accurate than the current
method for projecting investment rates 3 or 4 years into the future. In
fact, if such estimates were used in the late 1970s, they would have
resulted in higher revenue requirements. There is no assurance that
this would not happen again in the future.
Issue: Western should take an interest credit in the PRS for the
net cash balance accrued during the year for interest expense that is
not due and payable until yearend.
Response: The method used to compute interest in the PRS conforms
to DOE Order RA 6120.2, section 10.j., dated September 20, 1979, which
requires that interest shall be the sum of 1 year's interest on the
unpaid balance of each investment plus \1/2\ year's interest on new
investment added and in-service during the year, and interest on
deferred annual expenses (i.e., capitalized deficits). This amount may
be offset by a credit against interest expense if the credit concept is
utilized by the power marketing agency.
The methodology for computing the interest offset varies between
PMAs; DOE Order RA 6120.2 does not prescribe a specific procedure to be
used in making the interest calculation. The methodology employed by
Western incorporates an interest credit for \1/2\ year on all principal
payments made to investments during the current FY, and computes this
credit at the same rates of the investments being repaid. No interest
credit is taken for interest collected and retained throughout the
year.
This methodology is based on the premise that interest expenses are
equivalent to annual operating expenses such as O&M and are due and
payable throughout the year, not on the last day of the FY. As such,
payments to the Department of the Treasury are made to repay interest
as it is incurred. This approach is recommended by the U.S. General
Accounting Office (GAO) in attachment 3 to a letter from DOE to the
Administrators of the five PMAs dated September 8, 1983.
In attachment 3, GAO reviewed the interest rate practices of four
PMAs (Bonneville Power Administration, Southwestern Power
Administration, Western Area Power Administration, and Southeastern
Power Administration) and provided a draft recommendation that DOE
revise DOE Order RA 6120.2 to incorporate Western's methodology for
computing interest credits. GAO summarized that Western was utilizing
reasonable business principles in the application of the interest
credit.
Western believes that the methodology employed by the P-SMBP and
Fry-Ark PRSs is consistent with sound business principles and offers a
fair and reasonable credit against interest expenses.
Environmental Evaluation
In compliance with the National Environmental Policy Act of 1969,
42 U.S.C. 4321 et seq.; Council on Environmental Quality Regulations
(40 CFR parts 1500-1508); and DOE NEPA Regulations (10 CFR part 1021),
Western has determined that this action is categorically excluded from
the preparation of an environmental assessment or an environmental
impact statement.
Executive Order 12866
DOE has determined that this is not a significant regulatory action
because it does not meet the criteria of Executive Order 12866, 58 FR
51735. Western has an exemption from centralized regulatory review
under Executive Order 12866; accordingly, no clearance of this notice
by the Office of Management and Budget is required.
Availability of Information
Information regarding these rate adjustments, including PRSs,
comments, letters, memorandums, and other supporting material made or
kept by Western for the purpose of developing the power rates, is
available for public review in the Billings Area Office, Western Area
Power Administration, Division of Market Studies, Rates and Resources,
2525 4th Avenue North, Billings, Montana 59107-5800, telephone (406)
657-6488; Western Area Power Administration, Division of Marketing and
Rates, 1627 Cole Boulevard, Golden, Colorado 80401; and Western Area
Power Administration, Office of the Assistant Administrator for
Washington Liaison, room 8G-061, Forrestal Building, 1000 Independence
Avenue SW., Washington, DC 20585.
Submission to Federal Energy Regulatory Commission
The rates herein confirmed, approved, and placed into effect on an
interim basis, together with supporting documents, will be promptly
submitted to FERC for confirmation and approval on a final basis.
Order
In view of the foregoing and pursuant to the authority delegated to
me by the Secretary of Energy, I confirm and approve on an interim
basis, effective the first day of the first full billing period
beginning on or after February 1, 1994, Rate Schedules P-SED-F6 and P-
SED-FP6 for the Pick-Sloan Missouri Basin Program-Eastern Division. The
rate schedules shall remain in effect on an interim basis, pending
Federal Energy Regulatory Commission confirmation and approval of them
or substitute rates on a final basis, through January 31, 1999.
Issued in Washington, D.C., January 6, 1994.
Bill Whiten,
Deputy Secretary.
United States Department of Energy--Western Area Power
Administration
[Schedule P-SED-F6 (Supersedes Schedule P-SED-F5)]
Pick-Sloan Missouri Basin Program--Eastern Division, Montana, North
Dakota, South Dakota, Minnesota, Iowa, Nebraska; Schedule of Rates for
Firm Power Service
Effective: First Step: The first day of the first full billing
period beginning on or after February 1, 1994, through September 30,
1994.
Second Step: Beginning on the first day of the first full billing
period beginning on or after October 1, 1994, through January 31, 1999.
Available: Within the marketing area served by the Eastern Division
of the Pick-Sloan Missouri Basin Program.
Applicable: To the power and energy delivered to customers as firm
power service.
Character: Alternating current, 60 hertz, three phase, delivered
and metered at the voltages and points established by contract.
Monthly Rate:
First Step:
Demand Charge: $3.00 for each kilowatt per month (kW-month) of
billing demand.
Energy Charge: 7.76 mills for each kilowatthour (kWh) for all
energy delivered as firm power service. An additional charge of 3.38
mills per kWh (mills/kWh), for a total of 11.14 mills/kWh, will be
assessed for all energy delivered as firm power service that is in
excess of 60-percent monthly load factor and within the delivery
obligations under the provisions of the power sales contract.
Billing Demand: The billing demand will be as defined by the power
sales contract.
Second Step:
Demand Charge: $3.20 for each kW-month of billing demand.
Energy Charge: 8.32 mills for each kWh for all energy delivered as
firm power service. An additional charge of 3.38 mills/kWh for a total
of 11.70 mills/kWh will be assessed for all energy delivered as firm
power service that is in excess of 60-percent monthly load factor and
within the delivery obligations under the provisions of the power sales
contracts.
Billing Demand: The billing demand will be as defined by the power
sales contract.
Adjustments:
For Character and Conditions of Service: Customers who receive
deliveries at transmission voltage may in some instances be eligible to
receive a 5-percent discount on capacity and energy charges when
facilities are provided by the customer that result in a sufficient
savings to the United States to justify the discount. The determination
of eligibility for receipt of the voltage discount shall be exclusively
vested in the United States.
For Billing of Unauthorized Overruns: For each billing period in
which there is a contract violation involving an unauthorized overrun
of the contractual firm power and/or energy obligations, such overrun
shall be billed at 10 times the above rate.
For Power Factor: None. The customer will be required to maintain a
power factor at the point of delivery between 95-percent lagging and
95-percent leading.
United States Department of Energy--Western Area Power
Administration
[Schedule P-SED-FP6 (Supersedes Schedule P-SED-FP5)]
Pick-Sloan Missouri Basin Program--Eastern Division, Montana, North
Dakota, South Dakota, Minnesota, Iowa, Nebraska; Schedule of Rates for
Firm Peaking Power Service
Effective: First Step: The first day of the first full billing
period beginning on or after February 1, 1994, through September 30,
1994.
Second Step: Beginning on the first day of the first full billing
period beginning on or after October 1, 1994, through January 31, 1999.
Available: To the customers of the Billings Area Office with
generating resources enabling them to use firm peaking power service.
Applicable: To the power sold to customers as firm peaking power
service.
Character: Alternating current, 60 hertz, three phase, delivered
and metered at the voltages and points established by contract.
Monthly Rate:
First Step:
Demand Charge: $3.00 for each kilowatt per month (kW-month) of the
effective contract rate of delivery for peaking power or the maximum
amount scheduled, whichever is greater.
Energy Charge: 7.76 mills for each kilowatthour (kWh) for all
energy scheduled for delivery without return.
Billing Demand: The billing demand will be the greater of (1) the
highest 30-minute integrated demand measured during the month up to,
but not in excess of, the delivery obligation under the power sales
contract, or (2) the contract rate of delivery.
Second Step:
Demand Charge: $3.20 for each kW-month of the effective contract
rate of delivery for peaking power or the maximum amount scheduled,
whichever is greater.
Energy Charge: 8.32 mills for each kWh for all energy scheduled for
delivery without return.
Billing Demand: The billing demand will be the greater of (1) the
highest 30-minute integrated demand measured during the month up to,
but not in excess of, the delivery obligation under the power sales
contract, or (2) the contract rate of delivery.
Adjustments:
Billing for Unauthorized Overruns: For each billing period in which
there is a contract violation involving an unauthorized overrun of the
contractual obligation for peaking capacity and/or energy, such overrun
shall be billed at 10 times the above rate.
[FR Doc. 94-1487 Filed 1-19-94; 4:15 pm]
BILLING CODE 6450-01-P
