2015-09955. Indian Oil Valuation Amendments

AGENCY:

Office of Natural Resources Revenue (ONRR), Interior.

ACTION:

Final rule.

SUMMARY:

ONRR is amending its regulations governing the valuation, for royalty purposes, of oil produced from Indian leases. This rule will expand and clarify the major portion valuation requirement found in the existing regulations for oil production. This rule represents the recommendations of the Indian Oil Valuation Negotiated Rulemaking Committee (Committee). This rule also changes the form filing requirements necessary to claim a transportation allowance for oil produced from Indian leases.

DATES:

Effective date: July 1, 2015.

FOR FURTHER INFORMATION CONTACT:

For questions on technical issues, contact John Barder at [phone], Karl Wunderlich at [phone], or Elizabeth Dawson at [phone], ONRR.

SUPPLEMENTARY INFORMATION:

I. Background

The purpose of implementing this final rule regarding the valuation of oil production from Indian leases is: (1) To ensure that Indian mineral lessors receive the maximum revenues from mineral resources on their land consistent with the Secretary of the Interior's (Secretary) trust responsibility and lease terms and (2) to provide simplicity, certainty, clarity, and consistency for Indian oil valuation for Indian mineral revenue recipients and Indian mineral lessees.

II. Comments on Proposed Rule

On June 19, 2014, ONRR published a Notice of Proposed Rulemaking (79 FR 35102) to amend the valuation regulations for oil production from Indian leases. The proposed rule represents the recommendations of the Indian Oil Valuation Negotiated Rulemaking Committee (Committee). The proposed rulemaking provided for a 60-day comment period, which ended on August 18, 2014. During the public comment period, ONRR received fifteen written comments: two responses from industry, three from industry trade groups or associations, three from Indian Tribes, four from individual Indian mineral owners, and three from unassociated individuals.

ONRR has carefully considered all of the public comments that it received during the rulemaking process. ONRR hereby adopts final regulations governing the valuation of oil produced from Indian leases. These regulations will apply, prospectively, to oil produced on or after the effective date that we have specified in the DATES section of this preamble.

This final rule reflects other changes to the proposed rule. In the preamble of the proposed rule, ONRR requested comments on: (1) Eliminating the current regulation's requirement that a lessee must file a Form ONRR-4110 to claim an arm's-length transportation allowance, which would mirror the Indian gas valuation rule at 30 CFR 1206.178(a)(1)(i); (2) removing the current rule's requirement that lessees reporting non-arm's-length transportation arrangements submit a Form ONRR-4110 with estimated information prior to taking the transportation allowance, again this change would mirror the Indian gas valuation rule found at § 1206.178(b)(2)(i); (3) eliminating a lessee's ability to use transportation factors in calculating its royalties due under § 1206.57, and, instead, requiring lessees to report all transportation costs as separate entries for transportation allowances on Form ONRR-2014; and (4) removing the ability for a lessee to request to exceed the 50-percent limitation on transportation allowances. As we discuss in more detail below, ONRR amended the current rule to (1) eliminate form filing requirements for arm's-length transportation allowances and (2) eliminate the pre-filing of Form ONRR-4110 prior to claiming a non-arm's-length transportation allowance.

A. General Comments

ONRR received fifteen comments on the new rule. The majority of commenters expressed support for the rule. Other general comments fall into three categories: (1) ONRR's trust responsibilities, (2) increased communication with Indian lessors, and (3) the rule's impact on Indian lease royalty rates.

1. ONRR's Trust Responsibility

Public Comment: ONRR received two comments requesting that ONRR emphasize that the purpose of the proposed rule is to maximize revenues to Indian lessors under Interior's trust responsibility. A Tribe indicated that ONRR also should modify the language in the preamble of the final rule to mirror the language that is in the proposed Indian gas rule to clarify that the purpose of the rule is to maximize revenues for the Indian lessor.

In contrast, an individual commenter disputed the proposed rule because the commenter believes that the Tribes, not ONRR, should be establishing oil prices on Indian lands. The commenter stated that the Secretary's role is solely to approve or disapprove Indian agreements and should not take on any fiduciary responsibilities.

ONRR Response: ONRR has included language in the preamble of the final rule that states that the purpose of the rule is to maximize revenues for the Indian lessor, mirroring language contained in the preamble of the Indian gas valuation rule.

The United States Government has a unique legal relationship with American Indian Tribal governments, stemming from the Constitution of the United States. Over time, treaties, Federal statutes, regulations, and court decisions have refined the relationship to be one that is committed to protecting and respecting the rights of self-government of sovereign Tribal governments. Thus, Federal Indian statutes and regulations have evolved to rest certain obligations on the Federal Government.

The Indian Mineral Leasing Act of 1938, 25 U.S.C 396a-396g, grants the Secretary the authority to oversee the leasing and development of Indian mineral resources. By enacting the Indian Mineral Leasing Act, Congress intended the Secretary to act as a trustee to Tribes and Indian mineral owners. Jicarilla Apache Tribe v. Supron Energy Corp., 728 F.2d 1555, 1565 (10th Cir.1984) (Seymour, J., concurring in part and dissenting in part), adopted as majority opinion as modified en banc, 782 F.2d 855 (10th Cir.1986), supplemented, 793 F.2d 1171 (10th Cir. 1986), cert. denied, 479 U.S. 970 (1986). As a trustee, when “faced with a decision for which there is more than one `reasonable' choice as that term is used in administrative law, [the Secretary] must chose the alternative that is in the best interests of the Indian tribe.” Jicarilla v. Supron, Id. at 1567.

Furthermore, Tribes and individual Indian mineral owners can negotiate mineral leasing agreements under the Indian Mineral Development Act of 1982, 25 U.S.C. 2101-2108. Consistent with principles of self-determination, Tribes and individual Indian mineral owners, through Tribal affiliation, can negotiate valuation terms in their leases, subject to Secretarial approval. The Secretary has a duty to administer Indian oil and gas leases, including enforcing royalty obligations under those leases.

2. Increased Communication With Indian Lessors

Public Comment: ONRR received a comment seeking amendment to the rule requiring lessees to provide daily oil production reports. The commenter stated that daily oil production reports would “ensure the timely marketing of the produced oil and that the production cycle is not interrupted.”

ONRR Response: ONRR appreciates the comment. The comment, however, is beyond the scope of this rulemaking, which is limited to the valuation of oil produced from Indian leases. ONRR receives monthly oil and gas reports, which are sufficient for us to ensure proper production verification and accountability. Through audits and other compliance activities, ONRR can, if necessary, obtain daily information to verify that lessees have properly accounted for and reported their Indian oil production.

Public Comment: ONRR received two comments seeking improved access to data to allow Indian lessors to monitor their leases—by wells—on a monthly basis. Both commenters felt that the Explanation of Payment Report (EOP) that the Bureau of Indian Affairs currently sends with royalty payments to Indian lessors on a monthly basis is insufficient to provide a clear picture of the Indian lessor's oil and gas production. One commenter felt that ONRR should post individual well information on its Web site for Indian lessors to monitor their leases.

ONRR Response: ONRR appreciates the comment. The comment, however, is beyond the scope of this rulemaking, which is limited to the valuation of oil produced from Indian leases. Under the Federal Oil and Gas Royalty Management Act (FOGRMA), the Secretary must provide an EOP when a lessee makes any payment to an Indian lessor. 30 U.S.C. 1715. The Secretary must include “a description of the type of payment being made, the period covered by such payment, the source of such payment, production amounts, the royalty rate, unit value and such other information as may be agreed upon by the Secretary and the recipient State, Indian tribe, or Indian allottee.” Id.

ONRR generally does not receive royalty payment information by well because the information is voluminous and can include multiple leases, multiple communitization areas, and multiple lessors. And the lease, not the well, typically provides the basis for financial reporting, including financial terms against which ONRR assures compliance by companies and distributes royalties to Indian lessors.

Furthermore, the rule will require ONRR to post Index-Based Major Portion (IBMP) prices on its Web site. Thus, the proposed rule will increase the capacity for Indian lessors to validate the royalties that they receive are accurate. For applicable leases, if the volume-weighted price shown on the EOP is less than the IBMP value posted on ONRR's Web site, the Tribe and/or individual Indian mineral owner will know that there is a discrepancy based on the value of oil, the volume of the oil, and the lease's royalty rate.

3. The Rule's Impact on Indian Lease Royalty Rates

Public Comment: ONRR received two comments regarding the royalty rates in the leases. One commenter stated that “the proposed rule leaves no ability for the lessor to negotiate a rate when the opportunity presents itself.” Another stated that “the Secretary has refused to negotiate royalty rates for which the Secretary is responsible.”

ONRR Response: ONRR appreciates the comments. The royalty rate, however, is a clause in the lease and is not a component of the proposed rule. Under the Indian Mineral Development Act, Tribes and individual Indian mineral owners are free to negotiate lease terms with potential lessees, subject to Secretarial approval. 25 U.S.C. 2102. The proposed rule does not limit or otherwise infringe on the authority of Tribes to negotiate those leases. The BIA regulations set out a minimum royalty rate, see 25 CFR 211.41(b); 212.41(b), and Indian lessors are free to negotiate a higher royalty rate. Nothing in this rule prevents Indian lessors from doing so.

Public Comment: In addition, a Tribal commenter stated that the proposed rule implicitly states that the Secretary's trust responsibility will not apply to Tribes in Eastern Oklahoma because the rule is not applicable to District Court leases, which do not contain a major portion provision or provide for Secretarial discretion to determine value.

ONRR Response: The purpose of the rule is to provide a method to calculate value under the major portion provision found in most Indian leases. The rule does not change how to value Indian oil on leases that do not contain a major portion provision. The commenter is correct that the rule will not apply to District Court leases because those leases do not contain a major portion provision or provide for Secretarial discretion to determine value. Therefore, valuing Indian oil produced from these leases will not change under the proposed rule. Indian lessors remain free to negotiate their royalty rates. And, as stated previously, the rule does not alter a lessor's ability to negotiate new leases or lease terms.

B. Specific Comments on 30 CFR Part 1206—Product Valuation, Subpart B—Indian Oil

1. How ONRR Calculates the LCTD

Public Comment: ONRR received a comment recommending that ONRR use an “Adjustment Ratio (AR)” instead of the Location and Crude Type Differential (LCTD). The commenter proposes an AR as the ratio of the Major Portion Price to the New York Mercantile Exchange (NYMEX) Calendar Monthly Average (CMA), which would be equal to the LCTD, but would take fewer steps to calculate and, thus, decrease the chance of error.

ONRR Response: ONRR agrees with the commenter that the initial Adjustment Ratio (AR) would return the same result as the initial LCTD. The method used in the proposed rule, however, makes explicit use of the differential between the major portion price and NYMEX CMA so that those less familiar with the formula can clearly see how the Index-Based Major Portion is calculated. Therefore, ONRR will retain the LCTD in the final rule because it is more transparent.

Public Comment: ONRR received two comments regarding the LCTD. One commenter recommended amending the rule to eliminate the 10-percent adjustment mechanism for the LCTD. That commenter stated that, in months where lessees report more than 28 percent of the production as non-OINX (the gross proceeds that the lessee receives for volumes sold above the IBMP value), ONRR has the data that it needs to calculate the 75-percent major portion price. Thus, the commenter states that ONRR should use that number rather than the IBMP value because that is the price at which 75 percent of production was sold in the designated area. In months where lessees report volumes of a specific crude type in a particular designated area as non-OINX fall below 22 percent, the commenter proposes multiplying the AR by 0.98.

ONRR Response: The commenter correctly states that, in months where there is more than 28 percent of the production reported in a particular designated area for a specific crude type as non-OINX, ONRR has the price at which the 75th percentile of oil is sold. ONRR, however, disagrees that the Agency should use that price as the major portion price. First, the price will not be contemporaneous with the current production month. The commenter's recommendation will require ONRR to base the value of the Indian oil production on sales that occurred two production months prior to the current production month—effectively putting the IBMP price two months in arrears from the current reporting month. In contrast, the IBMP value uses the most recent NYMEX prices adjusted by the LCTD, which is contemporaneous with the production month. Thus, under the final rule, the data that ONRR uses results in an adjustment of the most recent NYMEX CMA price.

Second, the commenter does not clarify how ONRR would return to using an LCTD once the amount of production not reported as non-OINX falls below 28 percent. Instead, the commenter suggests using the commenter's original AR and multiplying that by 0.98 to adjust the IBMP value. As we discussed above, however, ONRR is not amending the rule to use the AR. And, this methodology falls outside of the recommendations of the Committee. Lastly, ONRR is unclear how the 0.98 adequately replaces the LCTD adjustment.

Public Comment: ONRR received another comment regarding the proposed rule's 10-percent adjustment to the LCTD. The commenter stated that the 10-percent adjustment appears arbitrary and does not take into account severe swings in the market.

ONRR Response: ONRR disagrees that the 10-percent adjustment mechanism is arbitrary. The Committee negotiated the 10-percent adjustment to allow ONRR to adjust the LCTD to reflect swings in the market. The Committee negotiated the 10-percent adjustment to ensure that the IBMP value will return to the 22-percent-to-28-percent range in the event that the IBMP value does fall outside of that range. The Committee, however, limited the adjustment to 10 percent to prevent drastic swings in the LCTD from month to month.

2. How ONRR Calculates the IBMP Value

Public Comment: ONRR received multiple comments regarding how ONRR calculates the IBMP value. ONRR received one comment stating that the formula that ONRR uses to calculate the IBMP value is too complex and difficult for the Indian lessor to understand. The commenter further believes that the calculation is labor-intensive and susceptible to error.

ONRR Response: ONRR appreciates the comment. While the formula may appear complex, ONRR will calculate the IBMP value each month and post the value on our Web site. Industry will then report and pay royalties on the higher of its gross proceeds or the posted IBMP value. Like the Indian Gas Major Portion calculation, ONRR will automate the process with internal controls to mitigate the risk of error. ONRR will provide training to those Tribes who would like to better understand the rule and to industry, who must comply with the rule.

Public Comment: Other commenters raised concerns regarding ONRR's shift from defining the major portion price in an area to be the price at which 50 percent by volume plus one barrel of oil is sold to using the price at which 25 percent, plus one barrel, by volume (starting from the top) of oil in an area is sold. One industry commenter states the 75th percentile is not a “major” portion—a major portion would be the 50 percent plus one barrel used under the current rule.

ONRR Response: ONRR incorporated the 75th percentile as the major portion of production based on (1) consistency with the Indian gas valuation rule and (2) the agreement reached by Committee. The Committee spent a significant amount of time deliberating what to use as a major portion price. Representatives for the Indian lessors advocated for a major portion price using the 75th percentile. Industry supported a major portion price based on the 50th percentile. Ultimately, industry representatives agreed to the 75th percentile in exchange for the benefits of the rule, including but not limited to: (1) Reduced accounting and administrative costs; (2) certainty associated with meeting the major portion obligation in real time; (3) significant reduction in prior period adjustments; (4) simplified audits and related expenses; and (5) reduced administrative appeals and litigation. In return, Indian lessors receive (1) royalties on their oil production founded on an index-based price equivalent to a 25-percent major portion from the top or the gross proceeds that their lessees receive; (2) more predictable and transparent information on revenues that they can expect to receive; and (3) royalties based on the leases' major portion provision sooner and with fewer adjustments. The Committee agreed to use the price at which 25 percent or more of the oil from the top is sold as a reasonable compromise on the term “major.” The change in the major portion value is identical to the trade-off that ONRR and the Indian Gas Valuation Negotiation Rulemaking Committee agreed upon prior to adopting the final Indian Gas Valuation Rules in 1999. Industry representatives agreed to the change in exchange for clarity, certainty, and reduced administrative costs.

Public Comment: ONRR also received a comment from an individual asserting ONRR “has not enforced the major portion provision or disclosed facts essential to understanding a claim. . . .”

ONRR Response: The final rule applies prospectively and will not impact ONRR's efforts to enforce the major portion provision under the prior rule.

Public Comment: One industry commenter noted that the 25-percent major price component in the rule will result in the commenter realizing the full 3.93-percent increase in royalties that ONRR estimated that industry would pay under the proposed rule.

ONRR Response: The 3.93 percent discussed in the preamble of the proposed rule is only to show, on average, the minimal impact of the proposed rule industrywide. The commenter's royalties may increase more or less than 3.93 percent.

Public Comment: ONRR also received a comment implying that the IBMP value is inadequate because it includes cost sharing. The commenter proposed to value oil produced from Indian lands by paying the Indian lessor 25 percent of the current NYMEX price, less the LCTD. The commenter stated that the LCTD should be allowed, but it should only capture the difference in value due to location and quality and that ONRR should eliminate any transportation allowances and any other costs/allowances. In so doing, the commenter states that ONRR will maximize the revenue of the Indian lessor.

ONRR Response: ONRR disagrees. ONRR maintains that the final rule maximizes revenues for Tribes and individual Indian mineral owners. The final rule ensures that the lessor receives the higher of (1) a value that approximates the major portion price at the 25th percentile by volume plus one barrel from highest price to lowest price, arrayed from the top (the top means that volume associated with the highest price that lessees receive for crude oil produced in a particular designated area in any given month); or (2) the gross proceeds accruing to the lessee. ONRR addresses the commenter's view on the elimination of transportation allowances under section 6 of the response to specific comments.

Public Comment: ONRR received three comments regarding the data that it uses to calculate the IBMP. Two Tribal commenters stated that ONRR must rely on audited data to calculate the initial LCTD for each designated area. The Tribal commenters are concerned that unaudited data may include inaccurate data that will have lingering and ongoing effects on the IBMP value. In contrast, ONRR received a comment from an individual stating that ONRR cannot go back and change the IBMP regardless if ONRR found errors in reported information.

ONRR Response: All oil production and sales reported to ONRR are subject to review and audit. Currently, ONRR has upfront edits, i.e. automated verifications, in place in our reporting systems, as well as data mining activities, which minimize inaccurately reported data. Moreover, as ONRR inputs the data that it uses to calculate the initial LCTD and future adjustments, ONRR will scrutinize the data to identify and resolve outliers as well as grossly misreported royalty volumes and values. Additionally, the large amount of data necessary to calculate the LCTD for any designated area will minimize the effects of individual misreported data. ONRR feels that these tools will adequately prevent bad data from influencing the initial LCTD calculation. In order to begin collecting royalties on the IBMP value, ONRR is using the previous 12 months of data collected. As we discussed above, ONRR will edit and scrutinize that data before using it in the formula. This approach represents a trade-off between using audited data, which can take three or more years to complete, and using the IBMP value formula, which results in contemporaneous payment of major portion obligations and early certainty for the Indian lessors.

3. ONRR's Discretion To Determine IBMP Value

In the preamble of the proposed rule, ONRR requested comments on whether ONRR should modify paragraph (e) of 30 CFR 1206.54 to provide that ONRR will use its discretion to determine an appropriate IBMP value where there are insufficient lines reported to ONRR on Form ONRR-2014 to determine a differential for a specific crude oil type or when the LCTD varies more than +/- 20 percent. In addition, ONRR requested comments on what would constitute a significant variation.

Public Comment: ONRR only received one general comment on § 1206.54(e). The commenter recommended that ONRR uses the Indian oil valuation standards found in the current oil rule to guide ONRR's discretion to ensure that the IBMP value is tied to the express terms of the lease.

ONRR Response: The provision in § 1206.54(e) providing ONRR with discretion allows ONRR to calculate a value if, for unforeseen circumstances, the data in a particular designated area for a particular crude type would prevent ONRR from accurately calculating the IBMP value. ONRR would still rely on information regarding like-quality oil and the location of the lease to calculate an appropriate differential, consistent with the lease terms. For example, ONRR may use its discretion to review sales data from nearby Federal leases to calculate the differential in situations where a designated area may have insufficient data to calculate an LCTD. Furthermore, ONRR identified designated areas to ensure that there is adequate information provided in the Form ONRR-2014 to calculate the IBMP value.

ONRR decided not to adopt a rule providing us with the discretion to calculate an IBMP value when the LCTD varies more than +/−20 percent. Instead, we will use the final rule's LCTD 10-percent adjustment mechanism to approximate, as close as possible, the 25th percentile major portion price.

4. ONRR's Proposed Designated Areas

Public Comment: A Tribal commenter indicated that Oklahoma should not be a single designated area. The Tribal commenter is concerned that using Oklahoma as a single designated area does not take into account varying transportation costs and differences in the quality of oil.

ONRR Response: In evaluating whether to use the State of Oklahoma as a Designated Area, ONRR analyzed prices and crude types across Oklahoma. In performing the analysis, ONRR did not find that there were any significant differences in the quality of the oil and the price of the oil sufficient to warrant separate designated areas, and, hence, separate LCTD calculations. The proximity of the Indian oil producing leases in Oklahoma to Cushing, Oklahoma, (the market center that serves as the basis of the IBMP value under this rule) reduced the impact of the location differential on the price of the oil. ONRR performed an analysis for the Committee, showing that transportation costs throughout Oklahoma were relatively small and that such costs do not demonstrate a consistent cost difference between leases in close proximity to Cushing and those further away. Although the Designated Area of Oklahoma is in close proximity to Cushing, Oklahoma, ONRR concluded an LCTD was warranted for Oklahoma. Because of its proximity to Cushing, Oklahoma, however, the LCTD for Oklahoma will be minimal.

Public Comment: An individual commenter suggested that ONRR remove the Muscogee (Creek) Nation and the Seminole Nation's lands in Osage County, Oklahoma, and designate those lands as a “Designated Area.”

ONRR Response: ONRR has confirmed that the Osage Nation owns all of the mineral rights in Osage County, Oklahoma. FOGRMA excludes Osage Indian lands. 30 U.S.C. 1702 (3). Therefore, ONRR cannot include Osage County as its own designated area or enforce the rule on Indian mineral production from Osage County, Oklahoma.

Public Comment: ONRR also received a comment from an industry commenter stating that ONRR has not provided the criteria it will use to determine when to modify or add designated areas. The commenter worries that there is no mechanism for industry “to petition ONRR to modify a designated area in the event that the designated area contains diverse geography and distinguishable access to infrastructure (such as pipelines, rail lines, and trucking).”

ONRR Response: The final rule and the preamble of the proposed rule specifically address the commenter's concerns. The final rule at 30 CFR 1206.51 lists criteria that ONRR will use to determine any future changes to designated areas that are identical to the very criteria that the commenter lists. Such criteria include markets served (such as refineries and market centers) and access to infrastructure (including trucking, pipelines, or rail). 30 CFR 1206.151 (final rule).

Moreover, the preamble to the proposed rule states: “If there is a significant change that affects the differentials for a designated area, affected Tribes, Indian mineral owners, or lessees/operators may petition ONRR to consider conveying a technical committee to review, modify, or add designated areas.” 79 FR 35102; 35104 (Jun. 19, 2014). ONRR will look at the same criteria that we outlined in the final rule to determine any future changes to designated areas. Id.

Public Comment: The industry commenter also takes issue with the final rule's use of “Designated Areas” over “fields” to calculate a price for ONRR to use to calculate the major portion price. The commenter believes that the use of a designated area is inconsistent with the lease language.

ONRR Response: The primary purpose of creating the Committee was to come to a consensus on how to implement the major portion provision found in most Indian leases. Determining the geographic range of data to use to calculate a major portion provision was one of the most highly debated topics in the Committee meetings. As a general rule, Committee members who represented industry advocated for the use of specific fields to calculate a value of oil sold under the major portion provision. Alternatively, Tribes and allottees promoted a broader area focused more on an oil type than the geographic location of the lease. The debate turned to implementing the rule on a field level versus a broader area. Ultimately, the Committee agreed to use “designated areas” developed based on the set criteria defined in the final rule. All meeting presentations, handouts, and meeting minutes are available on the Committee Web site at http://www.onrr.gov/​Laws_​R_​D/​IONR/​.

The commenter interprets the lease terms as requiring the Secretary to perform a major portion analysis solely on a field-by-field basis. Standard Indian lease forms commonly include a provision that states:

During the period of supervision, “value” for the purposes hereof, may, in the discretion of the Secretary, be calculated on the basis of the highest price paid or offered . . . at the time of production for the major portion of the oil of the same gravity, and gas, and/or natural gasoline, and/or all other hydrocarbon substances produced from the field where the leased lands are situated . . .

Standard Indian Allotted Lease, para. 3(c)

The rationale of using an area over a field is to ensure that there is a reasonable sample of data to conduct a major portion analysis. ONRR must meet both the requirements of the major portion provision in the leases and the Trade Secrets Act. Under the Trade Secrets Act, ONRR cannot reveal or release information that can be considered a trade secret because doing so may cause competitive harm. The Department has adopted a policy that financial and commercial data is proprietary. ONRR uses financial and commercial data that payors report to conduct a major portion analysis. Thus, ONRR has determined that, to perform a major portion analysis, it needs an area large enough to have at least three payors. Otherwise, it would be possible for a party to use the value data that ONRR provides with its calculations, combine it with other publicly available data, and determine the price that other industry members are selling their oil.

ONRR has consistently interpreted the Secretary's discretion language in Indian leases as allowing ONRR to evaluate the major portion price in areas as well as fields. See 30 CFR 1206.152; 1206.52; 1206.51; 30 CFR 206.103 (1984); and Notice to Lessees and Operators of Indian Oil and Gas Leases (NTL-1A), 42 FR 18135 (Apr. 5, 1977). In fact, under the Indian gas valuation rule, ONRR calculates the major portion price for Indian-gas-based designated areas similar to those proposed in this rule. See 30 CFR 1206.173(a)(2)(i) (2013).

The Navajo Nation Reservation provides an example of ONRR's reasoning to expand the field to a designated area. Ninety-seven percent of production on the Navajo Nation Reservation comes from one field and reservoir, the Greater Aneth Field in the Paradox Basin. Six payors report production from the Greater Aneth Field. The remaining 3 percent of production on the Navajo Nation Reservation comes from 24 fields with less than three payors on 22 of those 24 fields. The oil produced and sold on the Navajo Reservation is similar in all fields and is transported to the same refinery using similar transportation systems. Thus, to properly perform a major portion analysis for any oil production on the Navajo Reservation, ONRR expands the Designated Area to incorporate fields surrounding the Greater Aneth because the individual fields do not provide an appropriate sample size.

Public Comment: The same commenter next disputes ONRR's use of an entire reservation as a designated area. The commenter believes that using a reservation as a designated area fails to accurately account for local price differences and transportation costs that can vary within the reservation. The commenter uses the Navajo Nation Reservation as an example, illustrating the difficulties of obtaining accurate differentials. The commenter further states that it does not see that ONRR took into consideration geography and access to infrastructure within the reservations when we created the designated areas based on reservation boundaries.

ONRR Response: The Committee had exhaustive and extensive discussions regarding the amount and variation of transportation for each of the designated areas, including the factors that the commenter lists. As discussed above, ONRR evaluated the oil produced on the Navajo Nation Reservation, including the quality of the oil produced, transportation methods, and refineries used. Based on ONRR's analysis, the Committee determined that one Designated Area on the Navajo Nation Reservation adequately captured the differentials between oil produced on the reservation and oil sold in Cushing.

5. The Roll

Public Comment: ONRR received two comments in response to its request for comments on how ONRR changes the roll. ONRR sought comments on the flexibility of changing how it defines the roll or terminating the roll, with the caveat that it will publish any changes to the roll in the Federal Register. An industry commenter supported the ability for ONRR to terminate or redefine the roll only if such changes are published in the Federal Register, and ONRR provides industry the opportunity to comment on the proposed change. The second commenter suggested that ONRR eliminate the roll from its calculations altogether. The roll applies only to Indian oil produced in Oklahoma.

ONRR Response: ONRR will publish any changes to the roll in the Federal Register to provide notice and the opportunity for comment. ONRR incorporates the roll based on the agreement of the Committee and the fact that most contracts for oil sold from Indian leases in Oklahoma, which reference NYMEX prices, include the roll. Therefore, ONRR is keeping the roll in the final rule.

6. Transportation Allowances

Public Comment: ONRR received comments from five individual Indian mineral owners and one Tribe arguing that ONRR does not have the authority to include transportation allowances as part of the royalty equation.

ONRR Response: ONRR disagrees. The Act of June 30, 1834 (25 U.S.C. 9); the Act of March 3, 1909 (25 U.S.C. 396); the Indian Mineral Leasing Act of 1938 (25 U.S.C. 396a-396g); the Indian Mineral Development Act of 1982 (25 U.S.C. 2101, et seq.); and the FOGRMA (Pub. L. 97-451; 30 U.S.C. 1701 et seq.) authorize the Secretary to promulgate whatever regulations are necessary to implement those statutes.

The rationale for allowing lessees to deduct transportation costs comes from the language of the lease. Generally, Indian oil leases provide that the lessee will pay the Tribe or individual Indian mineral owner a certain percent of the “value or amount of all oil, gas, and/or natural gasoline, and/or all other hydrocarbon substances produced and saved from the land leased herein.” See Standard Indian Allotted Lease, para. 3(c) (Emphasis added). In essence, transportation allowance accounts for the costs that a lessee must incur to move its production to a market and, therefore, captures the value at the lease. The lessor shares in this expense because the lessor reaps the benefit of selling its lease production at a market rather than at the wellhead. If the lessor were to take its royalties in kind (i.e. in barrels of oil), the lessor would then incur all of the cost of transporting the oil production to a market to sell the oil.

To comply with this provision, for decades ONRR's regulations have allowed a lessee to deduct its transportation costs to calculate the value of their Indian oil production when it sells that oil at a location remote from the lease. See 53 FR 1184 (Jan. 15, 1988) (promulgating rule incorporating transportation allowances to determine the value of Federal and Indian oil production, for royalty purposes). ONRR has consistently allowed transportation costs because transporting oil to market off of the lease increases the value of the oil.

Courts have upheld the use of transportation allowances as a means to calculate the value of oil production for royalty purposes. See United States v. General Petroleum Corp. of California, 73 F. Supp. 225, 262 (S.D. Cal. 1946), aff'd sub nom Continental Oil Co. v. United States, 184 F.2d 802 (9th Cir. 1950) (stating “It has been held that if there is no open market in the place where an article ordinarily would be sold, the market value of such article in the nearest open market less cost of transportation to such open market becomes the market value of the article in question.”). The IBLA has confirmed allowing such deductions to Indian leases, consistent with Interior policy. Kerr-McGee Corp., 22 IBLA 24 (1975).

Public Comment: One commenter claims that allowing lessees to deduct transportation allowances from the value of their oil is a taking that is prohibited by the Fifth Amendment of the U.S. Constitution.

ONRR Response: ONRR disagrees. Under the Fifth Amendment of the U.S. Constitution, the Federal government cannot deprive a person of “life, liberty, or property, without due process of law; nor shall private property be taken for public use, without just compensation.” This provision is not violated or implicated by the final rule. This final rule will not impose conditions or limitations on the use of private property, and this final rule does not modify the current regulations to allow additional transportation costs. Therefore, this final rule does not result in a takings.

Public Comment: A Tribal commenter commented on using a statewide index for transportation costs in Oklahoma when the costs of transportation in the State will vary from location to location, thus “increasing with distance from the point of sale.”

ONRR Response: The Committee debated the issue of whether to allow location differentials for Oklahoma as a designated area. As we stated previously, ONRR performed an analysis for the Committee showing that there were small amounts of transportation costs that Indian lessees claimed throughout Oklahoma. The analysis showed that, although there were small amounts of transportation in Oklahoma, such costs did not demonstrate a consistent cost difference between leases in close proximity to Cushing and those further away. ONRR found that a lease located within a few miles of Cushing may have a higher transportation cost than a lease hundreds of miles away. Although the Designated Area of Oklahoma is in close proximity to Cushing, Oklahoma, ONRR concluded that an LCTD was warranted for Oklahoma. However, because of its proximity to Cushing, Oklahoma, the LCTD for Oklahoma will be minimal.

7. Comments in Response to Other Proposed Changes to the Indian Oil Rule

In addition to the major portion component of the proposed Indian oil valuation rule, ONRR requested comments concerning amending some of the provisions governing transportation allowances. Specifically, ONRR requested comments on (1) eliminating the requirement under the current rule to file a Form ONRR-4110, Oil Transportation Allowance Report, for arm's-length transportation agreements, which would mirror the requirement to file arm's-length transportation contracts with ONRR—rather than a form—under the current Indian Gas Valuation Rule at 30 CFR 1206.178(a)(1)(i); (2) removing the requirement that lessees submit a Form ONRR-4110 for non-arm's-length transportation allowances in advance of claiming an allowance and, instead, submit actual cost information in support of the allowance on its Form ONRR-4110, again mirroring the current Indian Gas Rule; (3) eliminating transportation factors under § 1206.57(a)(5); and (4) eliminating a lessee's ability to request to exceed the 50-percent limitation on transportation allowances under the current rule at § 1206.56(b)(2).

Public Comment: Generally, commenters supported removing the form filing requirements for arm's-length transportation allowances. A couple of industry commenters, however, requested guidance on what types of agreements that ONRR would require in order to claim a transportation allowance and what format ONRR would accept the agreement to be in (hardcopy, email, flashdrive, etc.). A Tribal commenter recommended that ONRR require lessees to provide hard copies of their transportation contracts.

ONRR Response: The final rule mirrors the Indian Gas Valuation Rule and requires payors to file arm's-length transportation contracts with ONRR rather than Form ONRR-4110. See 30 CFR 1206.178(a)(1)(i). ONRR will provide guidance to payors on the acceptable types and forms of contracts on a case-by-case basis, taking into consideration the Indian lessor's preferences.

Public Comment: For non-arm's-length transportation allowances, ONRR received two comments in support of the change proposed. The Tribal commenter, however, requested that ONRR require lessees to notify ONRR in advance that the lessee will apply a non-arm's-length transportation allowance against the value of the oil production. The Tribal commenter feels that this notice would be helpful in identifying areas of risk and discouraging lessees from failing to report transportation allowances.

ONRR Response: ONRR appreciates the comment and suggestion. The Form ONRR-4110 does not require lessees to provide notice and, at this time, ONRR will not require lessees to provide notice. ONRR understands the Tribal commenter's concerns regarding reporting transportation allowances. Under the current rule and final rule, however, lessees must report any non-arm's-length transportation allowances as a separate line on Form ONRR-2014. Should any auditor find that a lessee is reporting its oil production net of a transportation allowances, the auditor should refer the matter to ONRR's Office of Enforcement. ONRR's Office of Enforcement will investigate, enforce the regulations, and, where necessary, issue civil penalties.

Public Comment: ONRR received three opposing comments from industry and one supporting comment from a Tribe in response to its request for comments to eliminate transportation factors.

ONRR Response: ONRR believes that the increased transparency associated with eliminating transportation factors will better facilitate (1) ONRR's monitoring of oil values and (2) the accuracy of those values. Because of the other more important aspects of this rule, however, and our desire to have consistency with the Indian gas valuation rule, ONRR has decided to pursue this issue in a future rulemaking for both Indian oil and gas production.

Public Comment: One commenter stated that it opposed eliminating transportation factors because it could not find a definition of a transportation factor. The commenter indicated it was impossible to comment without such a definition. Another industry commenter stated that “transportation factors used for oil often include both a location and a quality differential, and it may not be possible to separate this factor between the two differentials.”

ONRR Response: The current rule does not provide a definition for a transportation factor. If an arm's-length contract price or posted price includes a provision by which the purchaser reduces the listed price to reflect the purchaser's transportation costs and then pays the lessee a net value under that arm's-length contract, ONRR deems the amount of the transportation reduction to be a transportation factor. A transportation factor is an actual transportation cost embedded in the arm's-length sales contract. See 30 CFR 1206.57. Because these actual transportation costs are part of what a lessee reports as the sales price of the oil that the lessee sells and are not separately reported transportation allowances, ONRR and its Indian lessors do not see the cost of transporting the oil to the point of sale as it would with transportation allowances. While ONRR believes that eliminating transportation factors increases transparency and certainty, ONRR has decided not to eliminate transportation factors in the final rule. Because of the more important aspects of the final rule and our desire to have consistency with the Indian gas valuation rule, ONRR has decided to pursue this issue in a future rulemaking for both Indian oil and gas production.

Public Comment: ONRR received three opposing comments from industry groups and one supporting comment from a Tribe in response to its request for comments on removing the provision under 30 CFR 1206.56(b)(2) that allows lessees to request an exception of the 50-percent limitation on transportation allowances.

ONRR Response: The final rule retains a lessee's ability to request approval to exceed the 50-percent limitation on transportation allowances. Under the current rule and the final rule, ONRR has the authority to review each and every request to ensure that the exception still represents a lessee's reasonable, actual, and necessary transportation costs. To date, ONRR has yet to receive a request for a transportation allowance to exceed 50 percent of the value of the Indian oil production. At this time, ONRR does not anticipate it will begin to receive such requests. Should ONRR receive a request to exceed, however, the Agency will review the request and all data involved, then we will consult with the Indian lessor before deciding to allow the lessee to exceed 50 percent. ONRR believes that these controls satisfy its trust responsibility to the Indian lessor.

C. Specific Comments on 30 CFR Part 1210—Forms and Reports, Subpart B—Royalty Reports—Oil, Gas, and Geothermal Resources

ONRR did not receive comments specific to 30 CFR part 1210.

D. Principal Changes

Under the proposed rule, ONRR stated, “for every month following the first full production month after this rule is effective, ONRR will monitor the LCTD using data reported on the Form ONRR-2014 for the previous month.” ONRR discovered, however, that, because companies can report on estimates, significant volumes of Indian oil sales are not reported by the last day of the month following the month of production. ONRR allows lessees to make a one-time estimate of their monthly royalty obligation in order to report and pay future royalties two months following the month of production. ONRR monitors a lessee's monthly reporting to ensure that the estimate on file with ONRR is sufficient, and, if it is not, then ONRR bills the lessee for late payment interest for the amount of the estimate that is insufficient.

Because of these estimates, many lessees do not report a large volume of Indian oil sales by the last day of the month following the month of production, ONRR is modifying the rule to use data from two months prior to the production month to monitor whether we will adjust the LCTD. This change will ensure that the data that ONRR uses to adjust the LCTD captures the majority of oil sales for that particular production month. Because ONRR will require the sales data from two months prior to the production month, ONRR will not make any adjustments to the LCTD for the first two production months after the rule is in effect.

III. Procedural Matters

1. Summary Cost and Royalty Impact Data

We estimated the costs and benefits that this rulemaking may have on all potentially affected groups: Industry, Indian Lessors, and the Federal government. This amendment will result in an estimated annual increase in royalty collections of between $19.4 million and $20.6 million for ONRR to disburse to Indian lessors. This net impact represents a minimal increase of between 3.82 percent and 3.93 percent of the total Indian oil royalties that ONRR collected in 2012. We also estimate that Industry and the Federal government will experience one-time increased system costs of approximately $4.84 million and $247 thousand, respectively.

A. Industry

The table below lists ONRR's low, mid-range, and high estimates of the additional royalty costs that Industry will incur in the first year (excluding one-time system costs). Industry will incur these costs in the same amount each year thereafter.

Summary of Royalty Impacts to Industry

Low	Mid	High
$19,400,000	$20,000,000	$20,600,000

Cost—Using the Higher of the Index-Based Major Portion Formula Value or Gross Proceeds To Value Indian Oil Sales

As discussed above, the final rule contains a provision under 30 CFR 1206.54 that explains how a lessee must meet its obligation to value oil produced from Indian leases based on the highest price paid for a major portion of like-quality oil from the field. This rule defines the monthly IBMP value that a lessee must compare to its gross proceeds and pay on the higher of those two values.

To perform this economic analysis, ONRR used royalty data that we collected for Indian oil (product code 01) for calendar year 2012. We chose calendar year 2012 because most data reported has gone through ONRR edits and lessees have made most of their adjustments. We did not distinguish crude oil type within each designated area because (1), based on our experience, crude oil type within each designated area is generally the same, and (2) lessees currently do not report crude oil type to ONRR.

We then segregated the data into the following 14 designated areas:

1. Uintah and Ouray—Uintah and Grand Counties

2. Uintah and Ouray—Duchesne County

3. North Fort Berthold

4. South Fort Berthold

5. Oklahoma—One statewide area excluding Osage County

6. Fort Peck

7. Turtle Mountain

8. Blackfeet Indian Reservation

9. Crow Indian Reservation

10. Jicarilla Apache Indian Reservation

11. Isabella Indian Reservation (Saginaw Chippewa)

12. Navajo Indian Reservation

13. Ute Mountain Ute Indian Reservation

14. Wind River Indian Reservation

We first arrayed the monthly reported prices—net of transportation—from highest to lowest and then calculated the monthly major portion price as that price at which 25 percent plus 1 barrel (by volume) of the oil is sold (starting from the highest price). Next, we calculated the difference between the reported prices and the major portion price. For any price below the major portion price, we multiplied the price difference by the royalty volume to estimate additional royalties.

Lastly, we totaled all of the monthly additional royalties for each designated area and then totaled all of the areas to arrive at an additional average royalty amount of $20 million. This amount represents 3.70 percent of all Indian oil royalties collected in 2012, or, approximately, $0.558/bbl.

Of note, we did not use the LCTD in this analysis. The rule uses the LCTD to calculate the IBMP value, which keeps the gross proceeds volume near the 25th percentile, through monthly monitoring and adjustments to the LCTD. Rather, we used the actual monthly major portion price in our analysis. Because we used the actual monthly major portion price, we did not account for the potential +/− 3 percent volume variation adjustments that the rule would allow. Instead, we created a +/− 3 percent range of royalty impacts above and below the estimated additional royalties, reflected in the table above.

Cost—System Changes To Accommodate Reporting of Crude Oil Type

ONRR needs to know crude oil types to calculate and publish the IBMP value. Therefore, § 1210.61 requires a lessee to report crude oil types using new product codes on Form ONRR-2014. ONRR anticipates that a lessee will make computer system changes to add these new product codes to their automated reporting.

We identified 205 Indian payors (those reporting and paying royalties to ONRR) in 2012. Of those, ONRR identified 32 as large businesses and 173 as small businesses (based on the SBA definition of a small business having 500 employees or fewer). To more accurately reflect the Indian payor community—based on our experience, we reclassified the 173 small businesses into two categories: Medium and small companies. We defined a medium company as those companies with between 250 and 500 employees. We also defined small companies as those companies with 250 or fewer employees. We classified 58 companies as medium companies and 115 companies as small companies.

ONRR first identified the changes that we must make to our systems in order to accommodate the requirements (adding product codes and edits, changing and adding reports, and modifying Oil and Gas Operations Reports, Form ONRR-4054 (OGORs)) of this rule and then estimated the number of hours needed to make those changes. We then multiplied those hours by our estimated hourly cost (including contractors) to implement system changes. Some of the hours calculated for ONRR include costs that Industry would not incur, such as eCommerce updates, changes to the compliance management tool, and web publishing.

We used this same process for large businesses, reducing or eliminating the hours for some categories, but used the same hourly cost because most large companies employ system contractors similar to those ONRR employs and, therefore, would have similar system change costs.

We reduced the hours for the medium (200 hours) and small companies (100 hours) to reflect the fact that their systems are smaller and less complex. We also reduced the hourly rate for medium and small businesses to $100 and $75, respectively, reflecting lower contractor costs. The table below provides our estimate of system change costs for both ONRR and Industry.

System changes	ONRR	Large business	Medium business	Small business
Adding product codes to ONRR 2014-PS	100	100	100	50
Adding product codes to ONRR 2014-eCommerce	100	0	0	0
Adding new edit	150	75	0	0
Changing reports	250	100	0	0
Changes to CPT	150	0	0	0
Changes to Web publishing	150	0	0	0
Changes to OGOR/PASR form	150	100	100	50
Total hours	1,050	375	200	100
Average hourly rate	× $235	× $235	× $100	× $75
Cost per entity [Total hours × Average hourly rate]	$246,750	$88,125	$20,000	$7,500
Number of Businesses	N/A	× 32	× 58	× 115
Total cost		$2,820,000	$1,160,000	$862,500
Industry Grand Total				$4,842,500

The table below lists the overall estimated first year economic impact to Industry from the changes, based on the mid-range estimate of costs:

Description	Annual (cost)/benefit amount
Cost—Major Portion Royalty	($20,000,000)
Cost—System Changes	($4,842,500)
Net First Year Cost to Industry	($24,842,500)

After the first year, we anticipate that the estimated cost to Industry will be approximately $20,000,000 each year, based on 2012 data.

B. Indian Lessors

The impact to Indian lessors will be a net overall increase in royalties as a result of this change. This royalty increase will equal the royalty increase from Industry, or $20 million.

C. Federal Government

Cost—System Changes To Accommodate Reporting of Crude Oil Type

The Federal Government will incur system costs to accommodate crude oil type reporting similar to Industry. As detailed above, ONRR estimates that it will take 1,050 hours to implement system changes related to this rule, equating to a total cost of $246,750.

This rule will have no impact on Federal royalties. We also believe that there will be no administrative cost increases to the Federal Government because administrative savings due to decreased audit and litigation costs will offset the additional work needed to monitor and adjust the LCTD and IBMP value.

D. Summary of Royalty Impacts and Costs to Industry, Indian Lessors, and the Federal Government

In the table below, the negative values in the Industry column represent their estimated royalty and cost increases, while the positive values in the other columns represent the increase in Indian royalty receipts. For the purposes of this summary table, we assumed that the average for royalty increases is the midpoint of our range.

Summary of Costs & Royalties the First Year

	Industry	Indian	Federal Government
Annual Additional Royalties Paid	($20,000,000)	$0	$0
Cost to Modify Systems	($4,842,500)	$0	($246,750)
Additional Royalties Received	$0	$20,000,000	$0
Total	($24,842,500)	$20,000,000	($246,750)

After the first year, this rule will cost industry approximately $20 million per year in additional royalties paid, and Indian lessors will increase their annual royalty receipts by approximately $20 million. The Federal Government will not incur any additional costs after the first year.

2. Regulatory Planning and Review (Executive Orders 12866 and 13563)

Executive Order (E.O.) 12866 provides that the Office of Information and Regulatory Affairs (OIRA) of the Office of Management and Budget (OMB) will review all significant rulemaking. OIRA has determined that this rule is not significant.

Executive Order 13563 reaffirms the principles of E.O. 12866, while calling for improvements in the nation's regulatory system to promote predictability, to reduce uncertainty, and to use the best, most innovative, and least burdensome tools for achieving regulatory ends. This executive order directs agencies to consider regulatory approaches that reduce burdens and maintain flexibility and freedom of choice for the public where these approaches are relevant, feasible, and consistent with regulatory objectives. E.O. 13563 emphasizes further that regulations must be based on the best available science and that the rulemaking process must allow for public participation and an open exchange of ideas. We have developed this rule in a manner consistent with these requirements.

3. Regulatory Flexibility Act

The Department of the Interior (Department) certifies that this rule will not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.).

This rule will affect lessees under Indian mineral leases (excluding Osage Indian leases in Oklahoma). Lessees of Federal and Indian mineral leases are generally companies classified under the North American Industry Classification System (NAICS) Code 211111, which includes companies that extract crude petroleum and natural gas. For this NAICS code classification, a small company is one with fewer than 500 employees. Approximately 205 different companies submit royalty and production reports from Indian leases to ONRR each month. In addition, approximately 32 companies are large businesses under the U.S. Small Business Administration definition because they have over 500 employees. The Department believes that the remaining 173 companies affected by this rule are small businesses.

As provided in 1A Industry of the Procedural Matters section, we believe that industry will incur a one-time cost to comply with this rule. On average, ONRR estimates that each small business will incur a one-time cost of between $7,500 and $20,000 to modify their systems to comply with this rule.

As we stated earlier, we believe, based on 2012 Indian oil sales, this rule will cost industry approximately $20 million dollars per year. Small businesses only accounted for 13.55 percent of the oil volumes sold in 2012. Applying that percentage to industry costs, ONRR estimates that the major portion provision will cost all small-business lessors approximately $2,710,000 per year. The amount will vary for each company depending on the volume of production that each small business produces and sells each year. We believe that reduced administrative costs, such as reduced accounting, auditing, and litigation expenses, will offset some of these costs.

In sum, we do not believe that this rule will result in a significant economic effect on a substantial number of small entities because (1) the initial one-time cost to a small business to modify its system will be between $7,500 and $20,000, and (2) this rule will cost the small businesses a collective total of $2,710,000 per year. Therefore, a Regulatory Flexibility Analysis will not be required, and, accordingly, a Small Entity Compliance Guide will not be required.

Your comments are important. The Small Business and Agriculture Regulatory Enforcement Ombudsman and ten Regional Fairness Boards receive comments from small businesses about Federal agency enforcement actions. The Ombudsman annually evaluates the enforcement activities and rates each agency's responsiveness to small business. If you wish to comment on the actions of ONRR, call 1-888-734-3247. You may comment to the Small Business Administration without fear of retaliation. Allegations of discrimination/retaliation filed with the Small Business Administration will be investigated for appropriate action.

4. Small Business Regulatory Enforcement Fairness Act (SBREFA)

This rulemaking is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This rulemaking:

a. Does not have an annual effect on the economy of $100 million or more. The effect will be limited to a maximum estimated at $2,710,000, which equals the $20,000,000 yearly cost of this rule to industry at large multiplied by 13.55 percent (volumes sold attributable to small businesses).

b. Does not cause a major increase in costs or prices for consumers; individual industries; Federal, State, Indian, or local government agencies; or geographic regions.

c. Does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of United States-based enterprises to compete with foreign-based enterprises.

5. Unfunded Mandates Reform Act

This rule does not impose an unfunded mandate on State, local, or Tribal governments or the private sector of more than $100 million per year. This rule does not have a significant or unique effect on State, local, or Tribal governments or the private sector. We are not required to provide a statement containing the information that the Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.) requires because this rule is not an unfunded mandate.

6. Takings (E.O. 12630)

Under the criteria in section 2 of E.O. 12630, this rule does not have any significant takings implications. This rule will not impose conditions or limitations on the use of any private property. Therefore, this rule does not require a Takings Implication Assessment.

7. Federalism (E.O. 13132)

Under the criteria in section 1 of E.O. 13132, this rule does not have sufficient Federalism implications to warrant the preparation of a Federalism summary impact statement. This rule does not substantially and directly affect the relationship between the Federal and State governments. The management of Indian leases is the responsibility of the Secretary of the Interior, and ONRR distributes all of the royalties that it collects from Indian leases to Tribes and individual Indian mineral owners. Because this rule does not alter that relationship, this rule does not require a Federalism summary impact statement.

8. Civil Justice Reform (E.O. 12988)

This rule complies with the requirements of E.O. 12988. Specifically, this rule:

a. Meets the criteria of section 3(a), which requires that we review all regulations to eliminate errors and ambiguity and write them to minimize litigation.

b. Meets the criteria of section 3(b)(2), which requires that we write all regulations in clear language using clear legal standards.

9. Consultation With Indian Tribal Governments (E.O. 13175)

The Department strives to strengthen its government-to-government relationship with Indian Tribes through a commitment to consultation with Indian Tribes and recognition of their right to self-governance and Tribal sovereignty. Under the Department's consultation policy and the criteria in E.O. 13175, we evaluated this rule and determined that it has no Tribal implications that will impose substantial, direct compliance costs on Indian Tribal governments.

Prior to formally promulgating this rule and throughout this rulemaking, ONRR has consulted with Tribes and representatives of individual Indian mineral owners as collaborative partners. On December 1, 2011, the Secretary signed the charter of the Indian Oil Valuation Negotiated Rulemaking Committee (Committee) and authorized the Committee under the Federal Advisory Committee Act. Members of the Committee included the Shoshone and Arapaho Tribes, Land Owners Association (Fort Berthold), Navajo Nation, Oklahoma Indian Land/Mineral Owners of Associated Nations, Ute Indian Tribe, Jicarilla Apache Nation, Blackfeet Nation and individual Indian mineral owner associations. The Committee engaged in substantive discussions under the Department's consultation policy; engaging in negotiated rulemaking is an appropriate process to engage in Tribal consultation.

Also, under this consultation policy and Executive Order criteria with Indian Tribes and individual Indian mineral owners on all policy changes that may affect them, ONRR scheduled public meetings in five different locations for the purpose of consulting with Indian Tribes and individual Indian mineral owners and to obtain public comments from other interested parties.

ONRR held consultation sessions with Tribes and individual Indian mineral owners on October 29, 2013, at the Civic Center in New Town, North Dakota; November 6, 2013, at Ft. Washakie, Wyoming; December 14, 2013, at the Wes Watkins Technology Center at Wetumka, Oklahoma; March 19-20, 2014, at the Indian Pueblo Cultural Center in Albuquerque, New Mexico; and March 31, 2014, at the BIA Agency in Ft. Duchene, Utah.

10. Paperwork Reduction Act of 1995

This rule:

(1) Does not contain any new information collection requirements.

(2) Does not require a submission to the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.).

This rule will modify § 1210.61 to require a lessee of Indian leases to report additional product codes for crude oil types on Form ONRR-2014. Currently, OMB approved a total of 239,937 burden hours for lessees to file their Forms ONRR-2014 under OMB Control Number 1012-0004. ONRR estimates that there will be no additional burden hours, beyond the initial hours that industry must incur in order to modify systems so as to accommodate this rule, to report the applicable crude oil type in the product code field.

This rule also changes the form filing requirements necessary to claim a transportation allowance for oil produced from Indian leases. Currently, OMB approved a total of 220 burden hours for lessees to file their Forms ONRR-4110 under OMB Control Number 1012-0002. ONRR estimates that there will be no additional burden hours because this rule will insignificantly reduce the burden hours associated with the Oil Transportation Allowance Report (Form ONRR-4110) under OMB Control Number 1012-0002. Rather than submitting estimated transportation cost information on the form and then following up with actual cost information at the end of the reporting cycle, the rule will require only responses with actual cost information. Also, under this rule, Indian lessees that have arm's-length transportation costs will no longer submit a Form ONRR-4110 to ONRR but will, instead, submit copies of the actual contracts to ONRR.

11. National Environmental Policy Act

This rule does not constitute a major Federal action significantly affecting the quality of the human environment. We are not required to provide a detailed statement under the National Environmental Policy Act of 1969 (NEPA) because this rule qualifies for categorical exclusion under 43 CFR 46.210(c) and (i) and the DOI Departmental Manual, part 516, section 15.4.D: “(c) Routine financial transactions including such things as . . . audits, fees, bonds, and royalties . . . (i) Policies, directives, regulations, and guidelines: That are of an administrative, financial, legal, technical, or procedural nature.” We have also determined that this rule is not involved in any of the extraordinary circumstances listed in 43 CFR 46.215 that require further analysis under NEPA. The procedural changes resulting from the IBMP value would have no consequence on the physical environment. This rule does not alter, in any material way, natural resources exploration, production, or transportation.

12. Effects on the Nation's Energy Supply (E.O. 13211)

This rule is not a significant energy action under the definition in E.O. 13211. and, therefore, a Statement of Energy Effects is not required.

List of Subjects

30 CFR Part 1206

• Coal
• Continental shelf
• Geothermal energy
• Government contracts
• Indians—lands
• Mineral royalties
• Oil and gas exploration
• Public lands—mineral resources
• Reporting and recordkeeping requirements

30 CFR Part 1210

• Continental shelf
• Geothermal energy
• Government contracts
• Indian leases
• Indians—lands
• Mineral royalties
• Oil and gas reporting
• Phosphate
• Potassium
• Reporting and recordkeeping requirements
• Royalties
• Sales contracts
• Sales summary
• Sodium
• Solid minerals
• Sulfur

Dated: March 26, 2015.

Kristen J. Sarri,

Principal Deputy Assistant Secretary for Policy, Management and Budget.

Authority and Issuance

For the reasons discussed in the preamble, ONRR amends 30 CFR parts 1206 and 1210 as follows:

PART 1206—PRODUCT VALUATION

1. The authority for part 1206 continues to read as follows:

Authority: 5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq., 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq., 1331 et seq., and 1801 et seq.

2. Revise subpart B of part 1206 to read as follows:

Subpart B—Indian Oil

1206.50

What is the purpose of this subpart?

1206.51

What definitions apply to this subpart?

1206.52

How do I calculate royalty value for oil that I or my affiliate sell(s) or exchange(s) under an arm's-length contract?

1206.53

How do I calculate royalty value for oil that I or my affiliate do(es) not sell under an arm's-length contract?

1206.54

How do I fulfill the lease provision regarding valuing production on the basis of the major portion of like-quality oil?

1206.55

What are my responsibilities to place production into marketable condition and to market production?

1206.56

What general transportation allowance requirements apply to me?

1206.57

How do I determine a transportation allowance if I have an arm's-length transportation contract?

1206.58

How do I determine a transportation allowance if I have a non-arm's-length transportation contract or have no contract?

1206.59

What interest applies if I improperly report a transportation allowance?

1206.60

What reporting adjustments must I make for transportation allowances?

1206.61

How will ONRR determine if my royalty payments are correct?

1206.62

How do I request a value determination?

1206.63

How do I determine royalty quantity and quality?

1206.64

What records must I keep to support my calculations of value under this subpart?

1206.65

Does ONRR protect information I provide?

Subpart B—Indian Oil

§ 1206.50

What is the purpose of this subpart?

(a) This subpart applies to all oil produced from Indian (Tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma). This subpart does not apply to Federal leases, including Federal leases for which revenues are shared with Alaska Native Corporations. This subpart:

(1) Explains how you as a lessee must calculate the value of production for royalty purposes consistent with Indian mineral leasing laws, other applicable laws, and lease terms.

(2) Ensures the United States discharges its trust responsibilities for administering Indian oil and gas leases under the governing Indian mineral leasing laws, treaties, and lease terms.

(b) If you dispose of or report production on behalf of a lessee, the terms “you” and “your” in this subpart refer to you and not to the lessee. In this circumstance, you must determine and report royalty value for the lessee's oil by applying the rules in this subpart to your disposition of the lessee's oil.

(c) If the regulations in this subpart are inconsistent with:

(1) A Federal statute;

(2) A settlement agreement between the United States, Indian lessor, and a lessee resulting from administrative or judicial litigation;

(3) A written agreement between the Indian lessor, lessee, and the ONRR Director establishing a method to determine the value of production from any lease that ONRR expects at least would approximate the value established under this subpart; or

(4) An express provision of an oil and gas lease subject to this subpart then the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency.

(d) ONRR or Indian Tribes, which have a cooperative agreement with ONRR to audit under 30 U.S.C. 1732, may audit, or perform other compliance reviews, and require a lessee to adjust royalty payments and reports.

§ 1206.51

What definitions apply to this subpart?

For purposes of this subpart:

Affiliate means a person who controls, is controlled by, or is under common control with another person.

(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of non-control that ONRR may rebut.

(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or instruments of ownership, or other forms of ownership, of another person, ONRR will consider the following factors in determining whether there is control in a particular case:

(i) The extent to which there are common officers or directors;

(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership:

(A) The percentage of ownership or common ownership;

(B) The relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons;

(C) Whether a person is the greatest single owner; and

(D) Whether there is an opposing voting bloc of greater ownership;

(iii) Operation of a lease, plant, or other facility;

(iv) The extent of participation by other owners in operations and day-to-day management of a lease, plant, or other facility; and

(v) Other evidence of power to exercise control over or common control with another person.

(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates.

Area means a geographic region at least as large as the defined limits of an oil and/or gas field in which oil and/or gas lease products have similar quality, economic, and legal characteristics.

Arm's-length contract means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm's-length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed.

Audit means a review, conducted under the generally accepted Governmental Auditing Standards, of royalty reporting and payment activities of lessees, designees, or other persons who pay royalties, rents, or bonuses on Indian leases.

BLM means the Bureau of Land Management of the Department of the Interior.

Condensate means liquid hydrocarbons (generally exceeding 40 degrees of API gravity) recovered at the surface without resorting to processing. Condensate is the mixture of liquid hydrocarbons that results from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir.

Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.

Designated area means an area that ONRR designates for purposes of calculating Location and Crude Type Differentials applied to an IBMP value. ONRR will post designated areas on our Web site at www.onrr.gov. ONRR will monitor the market activity in the designated areas and, if necessary, hold a technical conference to review, modify, or add a particular designated area. ONRR will post any change to the designated areas on our Web site at www.onrr.gov. Criteria to determine any future changes to designated areas include, but are not limited to: Markets served, examples include refineries and/or market centers, such as Cushing, OK; access to markets, examples include access to similar infrastructure, such as pipelines, rail lines, and trucking; and/or similar geography, examples include no challenging geographical divides, large rivers, and/or mountains.

Exchange agreement means an agreement where one person agrees to deliver oil to another person at a specified location in exchange for oil deliveries at another location, as well as other consideration(s). Exchange agreements:

(1) May or may not specify prices for the oil involved;

(2) Frequently specify dollar amounts reflecting location, quality, or other differentials;

(3) Include buy/sell agreements, which specify prices to be paid at each exchange point and may appear to be two separate sales within the same agreement or in separate agreements; and

(4) May include, but are not limited to, exchanges of produced oil for specific types of oil (e.g. WTI); exchanges of produced oil for other oil at other locations (location trades); exchanges of produced oil for other grades of oil (grade trades); and multi-party exchanges.

Field means a geographic region situated over one or more subsurface oil and gas reservoirs encompassing at least the outermost boundaries of all oil and gas accumulations known to be within those reservoirs vertically projected to the land surface. Onshore fields usually are given names, and their official boundaries are often designated by oil and gas regulatory agencies in the respective States in which the fields are located.

Gathering means the movement of lease production to a central accumulation or treatment point on the lease, unit, or communitized area or to a central accumulation or treatment point off of the lease, unit, or communitized area, as BLM operations personnel approve.

Gross proceeds means the total monies and other consideration accruing for the disposition of oil produced. Gross proceeds also include, but are not limited to, the following examples:

(1) Payments for services, such as dehydration, marketing, measurement, or gathering that the lessee must perform—at no cost to the lessor—in order to put the production into marketable condition;

(2) The value of services to put the production into marketable condition, such as salt water disposal, that the lessee normally performs but that the buyer performs on the lessee's behalf

(3) Reimbursements for harboring or terminalling fees;

(4) Tax reimbursements, even though the Indian royalty interest may be exempt from taxation;

(5) Payments made to reduce or buy down the purchase price of oil to be produced in later periods by allocating those payments over the production whose price the payment reduces and including the allocated amounts as proceeds for the production as it occurs; and

(6) Monies and all other consideration to which a seller is contractually or legally entitled but does not seek to collect through reasonable efforts.

IBMP means the Index-Based Major Portion value calculated under § 1206.54.

Indian Tribe means any Indian Tribe, band, nation, pueblo, community, rancheria, colony, or other group of Indians for which any minerals or interest in minerals is held in trust by the United States or that is subject to Federal restriction against alienation.

Individual Indian mineral owner means any Indian for whom minerals or an interest in minerals is held in trust by the United States or who holds title subject to Federal restriction against alienation.

Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under an Indian mineral leasing law that authorizes exploration for, development or extraction of, or removal of lease products. Depending on the context, lease may also refer to the land area that the authorization covers.

Lease products means any leased minerals attributable to, originating from, or allocated to Indian leases.

Lessee means any person to whom the United States, a Tribe, or individual Indian mineral owner issues a lease and any person who has been assigned an obligation to make royalty or other payments required by the lease. Lessee includes:

(1) Any person who has an interest in a lease (including operating rights owners).

(2) An operator, purchaser, or other person with no lease interest who reports and/or makes royalty payments to ONRR or the lessor on the lessee's behalf.

Lessor means an Indian Tribe or individual Indian mineral owner who has entered into a lease.

Like-quality oil means oil that has similar chemical and physical characteristics.

Location and Crude Type Differential (LCTD) means the difference in value between the NYMEX Calendar Monthly Average (CMA) and the value that approximates the monthly Major Portion Price for any given month, designated area, and crude oil type.

Location differential means an amount paid or received (whether in money or in barrels of oil) under an exchange agreement that results from differences in location between oil delivered in exchange and oil received in the exchange. A location differential may represent all or part of the difference between the price received for oil delivered and the price paid for oil received under a buy/sell exchange agreement.

Major Portion Price means the highest price paid or offered at the time of production for the major portion of oil produced from the same designated area for the same crude oil type.

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.

Net means to reduce the reported sales value to account for transportation instead of reporting a transportation allowance as a separate entry on Form ONRR-2014.

NYMEX Calendar Month Average Price means the average of the New York Mercantile Exchange (NYMEX) daily settlement prices for light sweet oil delivered at Cushing, Oklahoma, calculated as follows:

(1) Sum the prices published for each day during the calendar month of production (excluding weekends and holidays) for oil to be delivered in the nearest month of delivery for which NYMEX futures prices are published corresponding to each such day.

(2) Divide the sum by the number of days on which those prices are published (excluding weekends and holidays).

Oil means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities and is marketed or used as such. Condensate recovered in lease separators or field facilities is considered to be oil.

ONRR means the Office of Natural Resources Revenue of the Department of the Interior.

Operating rights owner, also known as a working interest owner, means any person who owns operating rights in a lease subject to this subpart. A record title owner is the owner of operating rights under a lease until the operating rights have been transferred from record title (see Bureau of Land Management regulations at 43 CFR 3100.0-5(d)).

Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).

Processing means any process designed to remove elements or compounds (hydrocarbon and non-hydrocarbon) from gas, including absorption, adsorption, or refrigeration. Field processes that normally take place on or near the lease, such as natural pressure reduction, mechanical separation, heating, cooling, dehydration, and compression, are not considered processing. The changing of pressures and/or temperatures in a reservoir is not considered processing.

Prompt month means the nearest month of delivery for which NYMEX futures prices are published during the trading month.

Quality differential means an amount paid or received under an exchange agreement (whether in money or in barrels of oil) that results from differences in API gravity, sulfur content, viscosity, metals content, and other quality factors between oil delivered and oil received in the exchange. A quality differential may represent all or part of the difference between the price received for oil delivered and the price paid for oil received under a buy/sell agreement.

Roll means an adjustment to the NYMEX price that is calculated as follows: Roll = .6667 × (P₀−P₁) + .3333 × (P₀−P₂), where: P₀ = the average of the daily NYMEX settlement prices for deliveries during the prompt month that is the same as the month of production, as published for each day during the trading month for which the month of production is the prompt month; P₁ = the average of the daily NYMEX settlement prices for deliveries during the month following the month of production, published for each day during the trading month for which the month of production is the prompt month; and P₂ = the average of the daily NYMEX settlement prices for deliveries during the second month following the month of production, as published for each day during the trading month for which the month of production is the prompt month. Calculate the average of the daily NYMEX settlement prices using only the days on which such prices are published (excluding weekends and holidays). ONRR reserves the option of terminating the use of the roll when ONRR believes that the roll is no longer a common industry practice. ONRR also retains the option to redefine how to calculate the roll to comport with changes in industry practice. To terminate or otherwise redefine how to calculate the roll, ONRR will explain its rationale for terminating or redefining how to calculate the roll by publishing a notice in the Federal Register, to provide an opportunity for comment.

(1) Example 1: Prices in out months are lower going forward. The month of production for which you must determine royalty value is December 2012. December was the prompt month from October 23 through November 20. January was the first month following the month of production, and February was the second month following the month of production. P_0, therefore, is the average of the daily NYMEX settlement prices for deliveries during December published for each business day between October 23 and November 20. P₁ is the average of the daily NYMEX settlement prices for deliveries during January published for each business day between October 23 and November 20. P₂ is the average of the daily NYMEX settlement prices for deliveries during February published for each business day between October 23 and November 20. In this example, assume that P₀ = $95.08 per bbl; P₁ = $95.03 per bbl; and P₂ = $94.93 per bbl. In this example (a declining market), Roll = .6667 × ($95.08−$95.03) + .3333 × ($95.08−$94.93) = $0.03 + $0.05 = $0.08. You add this number to the NYMEX price.

(2) Example 2: Prices in out months are higher going forward. The month of production for which you must determine royalty value is November 2012. November was the prompt month from September 21 through October 22. December was the first month following the month of production, and January was the second month following the month of production. P_0, therefore, is the average of the daily NYMEX settlement prices for deliveries during November published for each business day between September 21 and October 22. P₁ is the average of the daily NYMEX settlement prices for deliveries during December published for each business day between September 21 and October 22. P₂ is the average of the daily NYMEX settlement prices for deliveries during January published for each business day between September 21 and October 22. In this example, assume that P₀ = $91.28 per bbl; P₁ = $91.65 per bbl; and P₂ = $92.10 per bbl. In this example (a rising market), Roll = .6667 × ($91.28−$91.65) + .3333 × ($91.28−$92.10) = (−$0.25) + (−$0.27) = (−$0.52). You add this negative number to the NYMEX price (effectively a subtraction from the NYMEX price).

Sale means a contract between two persons where:

(1) The seller unconditionally transfers title to the oil to the buyer and does not retain any related rights, such as the right to buy back similar quantities of oil from the buyer elsewhere.

(2) The buyer pays money or other consideration for the oil.

(3) The parties' intent is for a sale of the oil to occur.

Sales type code means the contract type or general disposition (e.g. arm's-length or non-arm's-length) of production from the lease. The sales type code applies to the sales contract, or other disposition, and not to the arm's-length or non-arm's-length nature of a transportation allowance.

Trading month means the period extending from the second business day before the 25th day of the second calendar month preceding the delivery month (or, if the 25th day of that month is a non-business day, the second business day before the last business day preceding the 25th day of that month) through the third business day before the 25th day of the calendar month preceding the delivery month (or, if the 25th day of that month is a non-business day, the third business day before the last business day preceding the 25th day of that month), unless the NYMEX publishes a different definition or different dates on its official Web site, www.nymex.com,, in which case, the NYMEX definition will apply.

Transportation allowance means a deduction in determining royalty value for the reasonable, actual costs of moving oil to a point of sale or delivery off of the lease, unit area, or communitized area. The transportation allowance does not include gathering costs.

WTI means West Texas Intermediate.

You means a lessee, operator, or other person who pays royalties under this subpart.

§ 1206.52

How do I calculate royalty value for oil that I or my affiliate sell(s) or exchange(s) under an arm's-length contract?

(a) The value of production for royalty purposes for your lease is the higher of either the value determined under this section or the IBMP value calculated under § 1206.54. The value of oil under this section for royalty purposes is the gross proceeds accruing to you or your affiliate under the arm's-length contract, less applicable allowances determined under § 1206.56 or § 1206.57. You must use this paragraph (a) to value oil when:

(1) You sell under an arm's-length sales contract.

(2) You sell or transfer to your affiliate or another person under a non-arm's-length contract and that affiliate or person, or another affiliate of either of them, then sells the oil under an arm's-length contract.

(b) If you have multiple arm's-length contracts to sell oil produced from a lease that is valued under paragraph (a) of this section, the value of the oil is the higher of the volume-weighted average of the values established under this section for all contracts for the sale of oil produced from that lease or the IBMP value calculated under § 1206.54.

(c) If ONRR determines that the gross proceeds accruing to you or your affiliate does not reflect the reasonable value of the production due to either:

(1) Misconduct by or between the parties to the arm's-length contract; or

(2) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor, ONRR will establish a value based on other relevant matters.

(i) ONRR will not use this provision to simply substitute its judgment of the market value of the oil for the proceeds received by the seller under an arm's-length sales contract.

(ii) The fact that the price received by the seller under an arm's-length contract is less than other measures of market price is insufficient to establish breach of the duty to market unless ONRR finds additional evidence that the seller acted unreasonably or in bad faith in the sale of oil produced from the lease.

(d) You have the burden of demonstrating that your or your affiliate's contract is arm's-length.

(e) ONRR may require you to certify that the provisions in your or your affiliate's contract include all of the consideration that the buyer paid to you or your affiliate, either directly or indirectly, for the oil.

(f) You must base value on the highest price that you or your affiliate can receive through legally enforceable claims under the oil sales contract.

(1) Absent contract revision or amendment, if you or your affiliate fail(s) to take proper or timely action to receive prices or benefits to which you or your affiliate are entitled, you must pay royalty based upon that obtainable price or benefit.

(2) If you or your affiliate make timely application for a price increase or benefit allowed under your or your affiliate's contract—but the purchaser refuses—and you or your affiliate take reasonable documented measures to force purchaser compliance, you will not owe additional royalties unless or until you or your affiliate receive additional monies or consideration resulting from the price increase. You may not construe this paragraph (f)(2) to permit you to avoid your royalty payment obligation in situations where a purchaser fails to pay, in whole or in part, or in a timely manner, for a quantity of oil.

(g)(1) You or your affiliate must make all contracts, contract revisions, or amendments in writing, and all parties to the contract must sign the contract, contract revisions, or amendments.

(2) This provision applies notwithstanding any other provisions in this title 30 of the Code of Federal Regulations to the contrary.

(h) If you or your affiliate enter(s) into an arm's-length exchange agreement, or multiple sequential arm's-length exchange agreements, then you must value your oil under this paragraph (h).

(1) If you or your affiliate exchange(s) oil at arm's length for WTI or equivalent oil at Cushing, Oklahoma, you must value the oil using the NYMEX price, adjusted for applicable location and quality differentials under paragraph (h)(3) of this section and any transportation costs under paragraph (h)(4) of this section and §§ 1206.56 and 1206.57 or § 1206.58.

(2) If you do not exchange oil for WTI or equivalent oil at Cushing, but exchange it at arm's length for oil at another location and following the arm's-length exchange(s) you or your affiliate sell(s) the oil received in the exchange(s) under an arm's-length contract, then you must use the gross proceeds under your or your affiliate's arm's-length sales contract after the exchange(s) occur(s), adjusted for applicable location and quality differentials under paragraph (h)(3) of this section and any transportation costs under paragraph (h)(4) of this section and §§ 1206.56 and 1206.57 or § 1206.58.

(3) You must adjust your gross proceeds for any location or quality differential, or other adjustments, that you received or paid under the arm's-length exchange agreement(s). If ONRR determines that any exchange agreement does not reflect reasonable location or quality differentials, ONRR may adjust the differentials that you used based on relevant information. You may not otherwise use the price or differential specified in an arm's-length exchange agreement to value your production.

(4) If you value oil under this paragraph (h), ONRR will allow a deduction, under §§ 1206.56 and 1206.57 or § 1206.58, for the reasonable, actual costs to transport the oil:

(i) From the lease to a point where oil is given in exchange.

(ii) If oil is not exchanged to Cushing, Oklahoma, from the point where oil is received in exchange to the point where the oil received in exchange is sold.

(5) If you or your affiliate exchange(s) your oil at arm's length, and neither paragraph (h)(1) nor (2) of this section applies, ONRR will establish a value for the oil based on relevant matters. After ONRR establishes the value, you must report and pay royalties and any late payment interest owed based on that value.

§ 1206.53

How do I calculate royalty value for oil that I or my affiliate do(es) not sell under an arm's-length contract?

(a) The value of production for royalty purposes for your lease is the higher of either the value determined under this section or the IBMP value calculated under § 1206.54. The unit value of your oil not sold under an arm's-length contract under this section for royalty purposes is the volume-weighted average of the gross proceeds paid or received by you or your affiliate, including your refining affiliate, for purchases or sales under arm's-length contracts.

(1) When calculating that unit value, use only purchases or sales of other like-quality oil produced from the field (or the same area if you do not have sufficient arm's-length purchases or sales of oil produced from the field) during the production month.

(2) You may adjust the gross proceeds determined under paragraph (a) of this section for transportation costs under paragraph (c) of this section and §§ 1206.56 and 1206.57 or § 1206.58 before including those proceeds in the volume-weighted average calculation.

(3) If you have purchases away from the field(s) and cannot calculate a price in the field because you cannot determine the seller's cost of transportation that would be allowed under paragraph (c) of this section and § 1206.56 and § 1206.57 or § 1206.58, you must not include those purchases in your volume-weighted average calculation.

(b) Before calculating the volume-weighted average, you must normalize the quality of the oil in your or your affiliate's arm's-length purchases or sales to the same gravity as that of the oil produced from the lease. Use applicable gravity adjustment tables for the field (or the same general area for like-quality oil if you do not have gravity adjustment tables for the specific field) to normalize for gravity, as shown in the example below.

(1) Example 1. Assume that a lessee, who owns a refinery and refines the oil produced from the lease at that refinery, purchases like-quality oil from other producers in the same field at arm's length for use as feedstock in its refinery. Further assume that the oil produced from the lease that is being valued under this section is Wyoming general sour with an API gravity of 23.5°. Assume that the refinery purchases at arm's-length oil (all of which must be Wyoming general sour) in the following volumes of the API gravities stated at the prices and locations indicated:

10,000 bbl	24.5°	$34.70/bbl	Purchased in the field.
8,000 bbl	24.0°	$34.00/bbl	Purchased at the refinery after the third-party producer transported it to the refinery, and the lessee does not know the transportation costs.
9,000 bbl	23.0°	$33.25/bbl	Purchased in the field.
4,000 bbl	22.0°	$33.00/bbl	Purchased in the field.

(2) Example 2. Because the lessee does not know the costs that the seller of the 8,000 bbl incurred to transport that volume to the refinery, that volume will not be included in the volume-weighted average price calculation. Further assume that the gravity adjustment scale provides for a deduction of $0.02 per 1/10 degree API gravity below 34°. Normalized to 23.5° (the gravity of the oil being valued under this section), the prices of each of the volumes that the refiner purchased that are included in the volume-weighted average calculation are as follows:

10,000 bbl	24.5°	$34.50/bbl	(1.0° difference over 23.5° = $0.20 deducted).
9,000 bbl	23.0°	$33.35/bbl	(0.5° difference under 23.5° = $0.10 added).
4,000 bbl	22.0°	$33.30/bbl	(1.5° difference under 23.5° = $0.30 added).

(3) Example 3. The volume-weighted average price is ((10,000 bbl × $34.50/bbl) + (9,000 bbl × $33.35/bbl) + (4,000 bbl × $33.30/bbl)) / 23,000 bbl = $33.84/bbl. That price will be the value of the oil produced from the lease and refined prior to an arm's-length sale under this section.

(c) If you value oil under this section, ONRR will allow a deduction, under §§ 1206.56 and 1206.57 or § 1206.58, for the reasonable, actual costs:

(1) That you incur to transport oil that you or your affiliate sell(s), which is included in the volume-weighted average price calculation, from the lease to the point where the oil is sold.

(2) That the seller incurs to transport oil that you or your affiliate purchase(s), which is included in the volume-weighted average cost calculation, from the property where it is produced to the point where you or your affiliate purchase(s) it. You may not deduct any costs of gathering as part of a transportation deduction or allowance.

(d) If paragraphs (a) and (b) of this section result in an unreasonable value for your production as a result of circumstances regarding that production, ONRR's Director may establish an alternative valuation method.

§ 1206.54

How do I fulfill the lease provision regarding valuing production on the basis of the major portion of like-quality oil?

(a) This section applies to any Indian leases that contain a major portion provision for determining value for royalty purposes. This section also applies to any Indian leases that provide that the Secretary may establish value for royalty purposes. The value of production for royalty purposes for your lease is the higher of either the value determined under this section or the gross proceeds you calculated under § 1206.52 or § 1206.53.

(b) You must submit a monthly Form ONRR-2014 using the higher of the IBMP value determined under this section or your gross proceeds under § 1206.52 or § 1206.53. Your Form ONRR-2014 must meet the requirements of 30 CFR 1210.61.

(c) ONRR will determine the monthly IBMP value for each designated area and crude oil type and post those values on our Web site at www.onrr.gov. The monthly IBMP value by designated area and crude oil type is calculated as follows:

(1) For Indian leases located in Oklahoma:

(2) For all other Indian leases:

(d) ONRR will calculate the initial LCTD for each designated area (the same designated areas posted on its Web site at www.onrr.gov) and crude oil type using the following formula:

(1) For the first full production month after July 1, 2015, ONRR will calculate the monthly Major Portion Prices using data reported on the Form ONRR-2014 for the previous 12 production months prior to July 1, 2015 (Previous Twelve Months). To the extent that ONRR does not have data on the Form ONRR-2014 regarding the crude oil type for the entire previous twelve months, ONRR will assume the crude oil type is the same for those months for which ONRR does not have data as the months for which the crude oil type was reported on the Form ONRR-2014 for the same leases and/or agreements.

(i) ONRR will array the calculated prices net of transportation by month from highest to lowest price for each designated area and crude oil type. For each month, ONRR will calculate the Major Portion Price as that price at which 25 percent plus 1 barrel (by volume) of the oil (starting from the highest) is sold.

(ii) To calculate the average of the monthly Major Portion Prices for the previous 12 months, ONRR will add the monthly Major Portion Prices calculated in paragraph (d)(1)(i) of this section and divide by 12.

(2) For every month following the first full production month after July 1, 2015, ONRR will monitor the LCTD using data reported on the Form ONRR-2014 for the month ending two months before the current production month.

(i) ONRR will use the oil sales volume that lessees report on Form ONRR-2014 to monitor and, if necessary, to modify the LCTD used in the IBMP value.

(ii) ONRR will monitor oil sales volumes not reported under the sales type code OINX, as provided in 30 CFR 1210.61(a) and (b), on the Form ONRR-2014 on a monthly basis by designated area and crude oil type.

(iii) If the monthly oil sales volumes not reported under the sales type code OINX varies more than +/− 3 percent from 25 percent of the total reported oil sales volume for the month, then ONRR will revise the LCTD prospectively starting with the following month.

(A) If monthly oil sales volumes not reported under the sales type code OINX on Form ONRR-2014 by the designated area and crude oil type fall below 22 percent, ONRR will increase the LCTD by 10 percent every month until the monthly oil sales volumes reported under the sales type code for gross proceeds on Form ONRR-2014 fall within the +/− 3 percent range. In Example 1, assume that the IBMP value is $81.06 and the LCTD for the designated area is 14.28 percent. In the table below, the Percent of Volume not reported as OINX is less than 22 percent, which triggers a modification to the LCTD. ONRR will adjust the LCTD upward by 10 percent (14.28 percent × 1.10). Therefore, for the next month, the LCTD will be 15.71 percent. In the following month, the IBMP value will equal the next month's NYMEX CMA multiplied by (1 − 0.1571). ONRR will continue to make adjustments in subsequent months until monthly sales volumes not reported as OINX fall within 22-28 percent of the total monthly sales volume.

Example 1—Differential Adjustment When ARMS Sales Volume for the Current Month Falls Below 22% of Total Monthly Sales Volume

Lease	Sales volume	Unit price	Sales type code	Cumulative volume	Percent of volume
1	220	81.95	ARMS	220	9.02
2	275	81.71	ARMS	495	20.29
3	400	81.06	OINX	895	36.68
4	425	81.06	OINX	1,320	54.10
5	370	81.06	OINX	1,690	69.26
6	400	81.06	OINX	2,090	85.66
7	350	81.06	OINX	2,440	100.00
	2,440

(B) If monthly oil sales volumes not reported under the sales type code OINX on Form ONRR-2014 by designated area and crude oil type exceed 28 percent, then ONRR will decrease the LCTD by 10 percent every month until the monthly oil sales volumes reported under the sales type code for gross proceeds on Form ONRR-2014 fall within the +/− 3 percent range. In Example 2, assume that the IBMP value is $81.06 and the LCTD is 14.28 percent. As noted in the table below, however, the Percent of Volume not reported as OINX is 32.69 percent, exceeding the 28 percent threshold, which triggers a modification to the LCTD. ONRR will adjust the LCTD downward by 10 percent (14.28 percent × 0.90). Therefore, for the next month, the LCTD will be 12.85 percent. In the following month, the IBMP will equal the next month's NYMEX CMA multiplied by (1−0.1285). ONRR will continue to make adjustments in subsequent months until monthly sales volumes reported as ARMS fall within 22-28 percent of the total monthly sales volume.

Example 2—Differential Adjustment When ARMS Sales Volume Not Reported as OINX for the Current Month Exceeds 28% of Total Monthly Sales Volume

Lease	Sales volume	Unit price	Sales type code	Cumulative volume	Percent of volume
1	230	81.95	ARMS	230	11.06
2	275	81.71	ARMS	505	24.28
3	175	81.45	ARMS	680	32.69
4	250	81.06	OINX	930	44.71
5	425	81.06	OINX	1,355	65.14
6	325	81.06	OINX	1,680	80.77
7	400	81.06	OINX	2,080	100.00
	2,080

(e) In designated areas where there is insufficient data reported to ONRR on Form ONRR-2014 to determine a differential for a specific crude oil type, ONRR will use its discretion to determine an appropriate IBMP value.

§ 1206.55

What are my responsibilities to place production into marketable condition and to market production?

(a) You must place oil in marketable condition and market the oil for the mutual benefit of the lessee and the lessor at no cost to the Indian lessor unless the lease agreement provides otherwise.

(b) If you must use gross proceeds under an arm's-length contract or your affiliate's gross proceeds under an arm's-length exchange agreement to determine value under § 1206.52 or § 1206.53, you must increase those gross proceeds to the extent that the purchaser, or any other person, provides certain services that the seller normally would be responsible to perform in order to place the oil in marketable condition or to market the oil.

§ 1206.56

What general transportation allowance requirements apply to me?

(a) ONRR will allow a deduction for the reasonable, actual costs to transport oil from the lease to the point off of the lease under § 1206.52 or § 1206.53, as applicable. You may not deduct transportation costs to reduce royalties where you did not incur any costs to move a particular volume of oil. ONRR will not grant a transportation allowance for transporting oil taken as Royalty-In-Kind (RIK).

(b)(1) Except as provided in paragraph (b)(2) of this section, your transportation allowance deduction on the basis of a sales type code may not exceed 50 percent of the value of the oil at the point of sale, as determined under § 1206.52. Transportation costs cannot be transferred between sales type codes or to other products.

(2) Upon your request, ONRR may approve a transportation allowance deduction in excess of the limitation prescribed by paragraph (b)(1) of this section. You must demonstrate that the transportation costs incurred in excess of the limitation prescribed in paragraph (b)(1) of this section were reasonable, actual, and necessary. An application for exception (using Form ONRR-4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation necessary for ONRR to make a determination. Under no circumstances may the value, for royalty purposes, under any sales type code, be reduced to zero.

(c) You must express transportation allowances for oil in dollars per barrel. If you or your affiliate's payments for transportation under a contract are not on a dollar-per-barrel basis, you must convert whatever consideration you or your affiliate are paid to a dollar-per-barrel equivalent.

(d) You must allocate transportation costs among all products produced and transported as provided in § 1206.57.

(e) All transportation allowances are subject to monitoring, review, audit, and adjustment.

(f) If, after a review or audit, ONRR determines you have improperly determined a transportation allowance authorized by this subpart, then you must pay any additional royalties due plus late payment interest calculated under § 1218.54 of this chapter or report a credit for, or request a refund of, any overpaid royalties without interest under § 1218.53 of this chapter.

(g) You may not deduct any costs of gathering as part of a transportation deduction or allowance.

§ 1206.57

How do I determine a transportation allowance if I have an arm's-length transportation contract?

(a) Arm's-length transportation. (1) If you incur transportation costs under an arm's-length contract, your transportation allowance is the reasonable, actual costs that you incur to transport oil under that contract. You have the burden of demonstrating that your contract is arm's-length.

(2) You must submit to ONRR a copy of your arm's-length transportation contract(s) and all subsequent amendments to the contract(s) within 2 months of the date that ONRR receives your report, which claims the allowance on Form ONRR-2014.

(3) If ONRR determines that the consideration paid under an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When ONRR determines that the value of the transportation may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.

(4)(i) If an arm's-length transportation contract includes more than one liquid product, and the transportation costs attributable to each product cannot be determined from the contract, then you must allocate the total transportation costs in a consistent and equitable manner to each of the liquid products transported in the same proportion as the ratio of the volume of each product (excluding waste products which have no value) to the volume of all liquid products (excluding waste products which have no value). Except as provided in this paragraph (a)(4)(i), you may not take an allowance for the costs of transporting lease production, which is not royalty-bearing, without ONRR's approval.

(ii) Notwithstanding the requirements of paragraph (a)(4)(i) of this section, you may propose to ONRR a cost allocation method on the basis of the values of the products transported. ONRR shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part.

(5) If an arm's-length transportation contract includes both gaseous and liquid products, and the transportation costs attributable to each product cannot be determined from the contract, you must propose an allocation procedure to ONRR.

(i) You may use the oil transportation allowance determined in accordance with its proposed allocation procedure until ONRR issues its determination on the acceptability of the cost allocation.

(ii) You must submit to ONRR all available data to support your proposal.

(iii) You must submit your initial proposal within 3 months after the last day of the month for which you request a transportation allowance, whichever is later (unless ONRR approves a longer period).

(iv) ONRR will determine the oil transportation allowance based on your proposal and any additional information that ONRR deems necessary.

(6) Where an arm's-length sales contract price includes a provision whereby the listed price is reduced by a transportation factor, ONRR will not consider the transportation factor to be a transportation allowance. You may use the transportation factor to determine your gross proceeds for the sale of the product. The transportation factor may not exceed 50 percent of the base price of the product without ONRR's approval.

(b) Reporting requirements. (1) If ONRR requests, you must submit all data used to determine your transportation allowance. You must provide the data within a reasonable period of time that ONRR will determine.

(2) You must report transportation allowances as a separate entry on Form ONRR-2014. ONRR may approve a different reporting procedure on allotted leases and with lessor approval on Tribal leases.

(3) ONRR may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.

§ 1206.58

How do I determine a transportation allowance if I have a non-arm's-length transportation contract or have no contract?

(a) Non-arm's-length or no contract. (1) If you have a non-arm's-length transportation contract or no contract, including those situations where you or your affiliate perform(s) transportation services for you, the transportation allowance is based on your reasonable, actual costs as provided in this paragraph (a)(1).

(2) You must submit the actual cost information to support the allowance to ONRR on Form ONRR-4110, Oil Transportation Allowance Report, within 3 months after the end of the calendar year to which the allowance applies. However, ONRR may approve a longer time period. ONRR will monitor the allowance deductions to ensure that deductions are reasonable and allowable. When necessary or appropriate, ONRR may require you to modify your actual transportation allowance deduction.

(3) You must base a transportation allowance for non-arm's-length or no-contract situations on your actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment under paragraph (a)(3)(iv)(A) of this section, or a cost equal to the initial capital investment in the transportation system multiplied by a rate of return under paragraph (a)(3)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment), which are an integral part of the transportation system.

(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense that the lessee can document.

(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses that the lessee can document.

(iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.

(iv) You may use either depreciation or a return on depreciable capital investment. After you have elected to use either method for a transportation system, you may not later elect to change to the other alternative without approval from ONRR.

(A) To compute depreciation, you may elect to use either a straight-line depreciation method, based on the life of equipment or on the life of the reserves, which the transportation system services, or on a unit-of-production method. After you make an election, you may not change methods without ONRR's approval. A change in ownership of a transportation system will not alter the depreciation schedule the original transporter/lessee established for the purposes of the allowance calculation. With or without a change in ownership, a transportation system can be depreciated only once. You may not depreciate equipment below a reasonable salvage value.

(B) ONRR will allow as a cost an amount equal to the initial capital investment in the transportation system multiplied by the rate of return determined under paragraph (a)(3)(v) of this section. No allowance will be provided for depreciation.

(v) The rate of return is the industrial rate associated with Standard and Poor's BBB rating. The rate of return you must use is the monthly average rate as published in Standard and Poor's Bond Guide for the first month of the reporting period for which the allowance is applicable and is effective during the reporting period. You must redetermine the rate at the beginning of each subsequent transportation allowance reporting period (which is determined under paragraph (b) of this section).

(4)(i) You must determine the deduction for transportation costs based on your or your affiliate's cost of transporting each product through each individual transportation system. Where more than one liquid product is transported, you must allocate costs to each of the liquid products transported in the same proportion as the ratio of the volume of each liquid product (excluding waste products which have no value) to the volume of all liquid products (excluding waste products which have no value) and you must make such allocation in a consistent and equitable manner. Except as provided in this paragraph (a)(4)(i), you may not take an allowance for transporting lease production that is not royalty-bearing without ONRR's approval.

(ii) Notwithstanding the requirements of paragraph (a)(4)(i) of this section, you may propose to ONRR a cost allocation method on the basis of the values of the products transported. ONRR will approve the method unless we determine that it is not consistent with the purposes of the regulations in this part.

(5) Where both gaseous and liquid products are transported through the same transportation system, you must propose a cost allocation procedure to ONRR.

(i) You may use the oil transportation allowance determined in accordance with its proposed allocation procedure until ONRR issues our determination on the acceptability of the cost allocation.

(ii) You must submit to ONRR all available data to support your proposal.

(iii) You must submit your initial proposal within 3 months after the last day of the month for which you request a transportation allowance (unless ONRR approves a longer period).

(iv) ONRR will determine the oil transportation allowance based on your proposal and any additional information that ONRR deems necessary.

(6) You may apply to ONRR for an exception from the requirement that you compute actual costs under paragraphs (a)(1) through (5) of this section.

(i) ONRR will grant the exception only if you have a tariff for the transportation system the Federal Energy Regulatory Commission (FERC) has approved for Indian leases.

(ii) ONRR will deny the exception request if it determines that the tariff is excessive as compared to arm's-length transportation charges by pipelines, owned by the lessee or others, providing similar transportation services in that area.

(iii) If there are no arm's-length transportation charges, ONRR will deny the exception request if:

(A) No FERC cost analysis exists and the FERC has declined to investigate under ONRR timely objections upon filing.

(B) The tariff significantly exceeds the lessee's actual costs for transportation as determined under this section.

(b) Reporting requirements. (1) If ONRR requests, you must submit all data used to determine your transportation allowance. You must provide the data within a reasonable period of time that ONRR will determine.

(2) You must report transportation allowances as a separate entry on Form ONRR-2014. ONRR may approve a different reporting procedure on allotted leases and with lessor approval on Tribal leases.

(3) ONRR may require you to submit all of the data that you used to prepare your Form ONRR-4110. You must submit the data within a reasonable period of time that ONRR determines.

(4) ONRR may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.

(5) If you are authorized to use your FERC-approved tariff as your transportation cost under paragraph (a)(6) of this section, you must follow the reporting requirements of § 1206.57(b).

(c) Notwithstanding any other provisions of this subpart, for other than arm's-length contracts, no cost will be allowed for oil transportation that results from payments (either volumetric or for value) for actual or theoretical losses. This section does not apply when the transportation allowance is based upon a FERC or State regulatory agency approved tariff.

(d) The provisions of this section will apply to determine transportation costs when establishing value using a netback valuation procedure or any other procedure that requires deduction of transportation costs.

§ 1206.59

What interest applies if I improperly report a transportation allowance?

(a) If you deduct a transportation allowance on Form ONRR-2014 without complying with the requirements of §§ 1206.56 and § 1206.57 or 1206.58, you must pay additional royalties due plus late payment interest calculated under § 1218.54 of this chapter.

(b) If you erroneously report a transportation allowance that results in an underpayment of royalties, you must pay any additional royalties due plus late payment interest calculated under § 1218.54 of this chapter.

§ 1206.60

What reporting adjustments must I make for transportation allowances?

(a) If your actual transportation allowance is less than the amount that you claimed on Form ONRR-2014 for each month during the allowance reporting period, you must pay additional royalties due, plus late payment interest calculated under § 1218.54 of this chapter from the first day of the first month that you were authorized to deduct a transportation allowance to the date that you repay the difference.

(b) If the actual transportation allowance is greater than the amount that you claimed on Form ONRR-2014 for any month during the period reported on the allowance form, you may report a credit for, or request a refund of, any overpaid royalties without interest under § 1218.53 of this chapter.

(c) If you make an adjustment under paragraph (a) or (b) of this section, then you must submit a corrected Form ONRR-2014 to reflect actual costs, together with any payment, using instructions that ONRR provides.

§ 1206.61

How will ONRR determine if my royalty payments are correct?

(a)(1) ONRR may monitor, review, and audit the royalties that you report, and, if ONRR determines that your reported value is inconsistent with the requirements of this subpart, ONRR may direct you to use a different measure of royalty value.

(2) If ONRR directs you to use a different royalty value, you must pay any additional royalties due plus late payment interest calculated under § 1218.54 of this chapter, or you may report a credit for, or request a refund of, any overpaid royalties without interest under § 1218.53 of this chapter.

(b) When the provisions in this subpart refer to gross proceeds, in conducting reviews and audits, ONRR will examine if your or your affiliate's contract reflects the total consideration actually transferred, either directly or indirectly, from the buyer to you or your affiliate for the oil. If ONRR determines that a contract does not reflect the total consideration, you must value the oil sold as the total consideration accruing to you or your affiliate.

§ 1206.62

How do I request a value determination?

(a) You may request a value determination from ONRR regarding any oil produced. Your request must:

(1) Be in writing.

(2) Identify specifically all leases involved, all interest owners of those leases, the designee(s), and the operator(s) for those leases.

(3) Completely explain all relevant facts. You must inform ONRR of any changes to relevant facts that occur before we respond to your request.

(4) Include copies of all relevant documents.

(5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse precedents).

(6) Suggest your proposed valuation method.

(b) In response to your request, ONRR may:

(1) Request that the Assistant Secretary for Indian Affairs issue a valuation determination.

(2) Decide that ONRR will issue guidance.

(3) Inform you in writing that ONRR will not provide a determination or guidance. Situations in which ONRR typically will not provide any determination or guidance include, but are not limited to:

(i) Requests for guidance on hypothetical situations.

(ii) Matters that are the subject of pending litigation or administrative appeals.

(c)(1) A value determination that the Assistant Secretary for Indian Affairs signs is binding on both you and ONRR until the Assistant Secretary modifies or rescinds it.

(2) After the Assistant Secretary issues a value determination, you must make any adjustments to royalty payments that follow from the determination, and, if you owe additional royalties, you must pay the additional royalties due plus late payment interest calculated under § 1218.54 of this chapter.

(3) A value determination that the Assistant Secretary signs is the final action of the Department and is subject to judicial review under 5 U.S.C. 701-706.

(d) Guidance that ONRR issues is not binding on ONRR, the Indian lessor, or you with respect to the specific situation addressed in the guidance.

(1) Guidance and ONRR's decision whether or not to issue guidance or request an Assistant Secretary determination, or neither, under paragraph (b) of this section, are not appealable decisions or orders under 30 CFR part 1290.

(2) If you receive an order requiring you to pay royalty on the same basis as the guidance, you may appeal that order under 30 CFR part 1290.

(e) ONRR or the Assistant Secretary may use any of the applicable valuation criteria in this subpart to provide guidance or make a determination.

(f) A change in an applicable statute or regulation on which ONRR or the Assistant Secretary based any determination or guidance takes precedence over the determination or guidance, regardless of whether ONRR or the Assistant Secretary modifies or rescinds the determination or guidance.

(g) ONRR or the Assistant Secretary generally will not retroactively modify or rescind a value determination issued under paragraph (d) of this section, unless:

(1) There was a misstatement or omission of material facts.

(2) The facts subsequently developed are materially different from the facts on which the guidance was based.

(h) ONRR may make requests and replies under this section available to the public, subject to the confidentiality requirements under § 1206.65.

§ 1206.63

How do I determine royalty quantity and quality?

(a) You must calculate royalties based on the quantity and quality of oil as measured at the point of royalty settlement that BLM approves.

(b) If you determine the value of oil under § 1206.52, § 1206.53, or § 1206.54 based on a quantity and/or quality that is different from the quantity and/or quality at the point of royalty settlement that BLM approves for the lease, you must adjust that value for the differences in quantity and/or quality.

(c) You may not make any deductions from the royalty volume or royalty value for actual or theoretical losses incurred before the royalty settlement point unless BLM determines that any actual loss was unavoidable.

§ 1206.64

What records must I keep to support my calculations of value under this subpart?

If you determine the value of your oil under this subpart, you must retain all data relevant to the determination of royalty value.

(a) You must show:

(1) How you calculated the value that you reported, including all adjustments for location, quality, and transportation.

(2) How you complied with these rules.

(b) On request, you must make available sales, volume, and transportation data for production that you sold, purchased, or obtained from the field or area. You must make this data available to ONRR, Indian representatives, or other authorized persons.

(c) You can find recordkeeping requirements in §§ 1207.5, 1212.50, and 1212.51 of this chapter.

(d) ONRR, Indian representatives, or other authorized persons may review and audit your data, and ONRR will direct you to use a different value if they determine that the reported value is inconsistent with the requirements of this subpart.

§ 1206.65

Does ONRR protect information that I provide?

(a) Certain information that you or your affiliate submit(s) to ONRR regarding the valuation of oil, including transportation allowances, may be exempt from disclosure.

(b) To the extent that applicable laws and regulations permit, ONRR will keep confidential any data that you or your affiliate submit(s) that is privileged, confidential, or otherwise exempt from disclosure.

(c) You and others must submit all requests for information under the Freedom of Information Act regulations of the Department of the Interior at 43 CFR part 2.

PART 1210—FORMS AND REPORTS

3. The authority citation for part 1210 continues to read as follows:

Authority 5 U.S.C. 301 et seq.; 25 U.S.C. 396, 2107; 30 U.S.C. 189, 190, 359, 1023, 1751(a); 31 U.S.C. 3716, 9701; 43 U.S.C. 1334, 1801 et seq.; and 44 U.S.C. 3506(a).

Subpart B—Royalty Reports—Oil, Gas, and Geothermal Resources

4. Add § 1210.61 to subpart B to read as follows:

§ 1210.61

What additional reporting requirements must I meet for Indian oil valuation purposes?

(a) If you must report and pay under § 1206.52 of this chapter, you must use Sales Type Code ARMS on Form ONRR-2014.

(b) If you must report and pay under § 1206.53 of this chapter, you must use Sales Type Code NARM on Form ONRR-2014.

(c) If you must report and pay under § 1206.54 of this chapter, you must use Sales Type Code OINX on Form ONRR-2014.

(d) You must report one of the following crude oil types in the product code field of Form ONRR-2014:

(1) Sweet (code 61);

(2) Sour (code 62);

(3) Asphaltic (code 63);

(4) Black Wax (code 64); or

(5) Yellow Wax (code 65).

(e) All of the remaining requirements of this subpart apply.