[Federal Register Volume 80, Number 84 (Friday, May 1, 2015)]
[Rules and Regulations]
[Pages 24794-24814]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-09955]


=======================================================================
-----------------------------------------------------------------------

DEPARTMENT OF THE INTERIOR

Office of Natural Resources Revenue

30 CFR Parts 1206 and 1210

[Docket No. ONRR-2014-0001; DS63610000 DR2PS0000.CH7000 156D0102R2]
RIN 1012-AA15


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 (303) 231-3702, Karl Wunderlich at (303) 231-
3663, or Elizabeth Dawson at (303) 231-3653, 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.

[[Page 24795]]

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 Sec.  1206.178(b)(2)(i); (3) eliminating a 
lessee's ability to use transportation factors in calculating its 
royalties due under Sec.  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

[[Page 24796]]

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

[[Page 24797]]

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

[[Page 24798]]

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 Sec.  
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 Sec.  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

[[Page 24799]]

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;

[[Page 24800]]

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 Sec.  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 Sec.  
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

[[Page 24801]]

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.

[[Page 24802]]

Therefore, Sec.  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-                     100                 0                 0                 0
 eCommerce..............................
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.....................            x $235            x $235            x $100             x $75
Cost per entity [Total hours x Average            $246,750           $88,125           $20,000            $7,500
 hourly rate]...........................
Number of Businesses....................               N/A              x 32              x 58             x 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:

------------------------------------------------------------------------
                                                         Annual (cost)/
                      Description                        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
----------------------------------------------------------------------------------------------------------------
                                                                                                     Federal
                                                                Industry           Indian          Government
----------------------------------------------------------------------------------------------------------------
Annual Additional Royalties Paid..........................     ($20,000,000)                $0                $0

[[Page 24803]]

 
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

[[Page 24804]]

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 Sec.  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.


[[Page 24805]]


    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

0
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.


0
2. Revise subpart B of part 1206 to read as follows:
Subpart B--Indian Oil
Sec.
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


Sec.  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.


Sec.  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

[[Page 24806]]

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 
Sec.  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

[[Page 24807]]

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 x (P0-P1) + .3333 x 
(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. P0, 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 x 
($95.08-$95.03) + .3333 x ($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. P0, 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 x ($91.28-$91.65) + .3333 x ($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.

[[Page 24808]]

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


Sec.  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 Sec.  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 Sec.  1206.56 or Sec.  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 Sec.  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 
Sec. Sec.  1206.56 and 1206.57 or Sec.  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 Sec. Sec.  1206.56 and 1206.57 or 
Sec.  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 Sec. Sec.  1206.56 and 1206.57 or Sec.  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.


Sec.  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 Sec.  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 Sec. Sec.  1206.56 and 1206.57 or Sec.  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 Sec.  1206.56 and Sec.  1206.57 or Sec.  
1206.58,

[[Page 24809]]

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[deg]. 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[deg]  $34.70/bbl...............  Purchased in the field.
8,000 bbl.............................       24.0[deg]  $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[deg]  $33.25/bbl...............  Purchased in the field.
4,000 bbl.............................       22.0[deg]  $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[deg]. Normalized to 23.5[deg] (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[deg]  $34.50/bbl...............  (1.0[deg] difference over
                                                                                    23.5[deg] = $0.20 deducted).
9,000 bbl.............................       23.0[deg]  $33.35/bbl...............  (0.5[deg] difference under
                                                                                    23.5[deg] = $0.10 added).
4,000 bbl.............................       22.0[deg]  $33.30/bbl...............  (1.5[deg] difference under
                                                                                    23.5[deg] = $0.30 added).
----------------------------------------------------------------------------------------------------------------

    (3) Example 3. The volume-weighted average price is ((10,000 bbl x 
$34.50/bbl) + (9,000 bbl x $33.35/bbl) + (4,000 bbl x $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 Sec. Sec.  1206.56 and 1206.57 or Sec.  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.


Sec.  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 Sec.  1206.52 or Sec.  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 Sec.  1206.52 or Sec.  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:
    [GRAPHIC] [TIFF OMITTED] TR01MY15.012
    
    (2) For all other Indian leases:
    [GRAPHIC] [TIFF OMITTED] TR01MY15.013
    
    (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:

[[Page 24810]]

[GRAPHIC] [TIFF OMITTED] TR01MY15.007

    (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 x 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
----------------------------------------------------------------------------------------------------------------
                                                                                    Cumulative      Percent of
             Lease               Sales volume     Unit price     Sales type code      volume          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 x 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
----------------------------------------------------------------------------------------------------------------
                                                                                    Cumulative      Percent of
             Lease               Sales volume     Unit price     Sales type code      volume          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

[[Page 24811]]

 
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.


Sec.  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 Sec.  1206.52 or Sec.  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.


Sec.  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 Sec.  
1206.52 or Sec.  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 Sec.  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 Sec.  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 Sec.  1218.54 of this chapter or 
report a credit for, or request a refund of, any overpaid royalties 
without interest under Sec.  1218.53 of this chapter.
    (g) You may not deduct any costs of gathering as part of a 
transportation deduction or allowance.


Sec.  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

[[Page 24812]]

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.


Sec.  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

[[Page 24813]]

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 Sec.  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.


Sec.  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 Sec. Sec.  1206.56 and Sec.  
1206.57 or 1206.58, you must pay additional royalties due plus late 
payment interest calculated under Sec.  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 Sec.  1218.54 
of this chapter.


Sec.  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 Sec.  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 
Sec.  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.


Sec.  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 Sec.  1218.54 of this chapter, or you may report a credit for, or 
request a refund of, any overpaid royalties without interest under 
Sec.  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.


Sec.  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 
Sec.  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.

[[Page 24814]]

    (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 Sec.  
1206.65.


Sec.  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 Sec.  1206.52, Sec.  
1206.53, or Sec.  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.


Sec.  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 Sec. Sec.  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.


Sec.  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

0
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

0
4. Add Sec.  1210.61 to subpart B to read as follows:


Sec.  1210.61  What additional reporting requirements must I meet for 
Indian oil valuation purposes?

    (a) If you must report and pay under Sec.  1206.52 of this chapter, 
you must use Sales Type Code ARMS on Form ONRR-2014.
    (b) If you must report and pay under Sec.  1206.53 of this chapter, 
you must use Sales Type Code NARM on Form ONRR-2014.
    (c) If you must report and pay under Sec.  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.

[FR Doc. 2015-09955 Filed 4-30-15; 8:45 am]
 BILLING CODE 4335-30-P