[Federal Register Volume 79, Number 118 (Thursday, June 19, 2014)]
[Proposed Rules]
[Pages 35102-35121]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2014-13967]



[[Page 35102]]

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DEPARTMENT OF THE INTERIOR

30 CFR Parts 1206 and 1210

[Docket No. ONRR-2014-0001; DS63610000; DR2PS0000.CH7000 145D0102R2]
RIN 1012-AA15


Indian Oil Valuation Amendments

AGENCY: Office of Natural Resources Revenue (ONRR), Interior.

ACTION: Proposed rule.

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SUMMARY: ONRR proposes to amend its regulations governing the 
valuation, for royalty purposes, of oil produced from Indian leases. 
The proposed rule would clarify the major portion valuation requirement 
found in the existing regulations for oil production. The proposed rule 
would represent recommendations of the Indian Oil Valuation Negotiated 
Rulemaking Committee. This proposed rule also contains new reporting 
requirements to implement the changes to the major portion valuation 
requirement.

DATES: Comments must be submitted on or before August 18, 2014.

ADDRESSES: You may submit comments to ONRR on this proposed rulemaking 
by one of the following methods (please reference ``1012-AA15'' in your 
comments):
    [ssquf] Electronically go to www.regulations.gov. In the entry 
titled ``Enter Keyword or ID,'' enter ``ONRR-2014-0001,'' and then 
click ``Search.'' Follow the instructions to submit public comments. 
ONRR will post all comments.
    [ssquf] Mail comments to Armand Southall, Regulatory Specialist, 
ONRR, P.O. Box 25165, MS 61030A, Denver, Colorado 80225-0165.
    [ssquf] Hand-carry comments, or use an overnight courier service, 
to the Office of Natural Resources Revenue, Building 85, Room A-614, 
Denver Federal Center, West 6th Ave. and Kipling St., Denver, Colorado 
80225.

FOR FURTHER INFORMATION CONTACT: For questions on technical issues, 
contact John Barder at (303) 231-3702, Sarah Inderbitzin at (303) 231-
3082, Karl Wunderlich at (303) 231-3663, or Elizabeth Dawson at (303) 
231-3653, ONRR. For comments or questions on procedural issues, contact 
Armand Southall, Regulatory Specialist, ONRR, telephone (303) 231-3221, 
or email [email protected].

SUPPLEMENTARY INFORMATION:

I. Background

    The Minerals Revenue Management (MRM) program of the Minerals 
Management Service (MMS), now ONRR, published the existing rule for the 
major portion provision for the valuation of oil produced from Indian 
leases, codified at 30 CFR part 1206, subpart B, in the Federal 
Register on January 15, 1988 (53 FR 1184), effective March 1, 1988. 
Since then, many changes have occurred in the oil market. Also, 
concerns have arisen about the need for revised valuation methodologies 
to address the major portion requirement in paragraph 3(c) of standard 
Indian oil and gas leases for valuation of oil produced from leases on 
Indian land.
    MRM published proposed rules for Indian oil valuation on February 
12, 1998 (63 FR 7089) and on January 5, 2000 (65 FR 403). MRM 
subsequently withdrew each of these proposed rules because of market 
changes and the passage of time. In addition, MRM held eight public 
meetings during 2005 to obtain information from, and consult with, 
Indian Tribes and Indian mineral owners and other interested parties. 
Then, MRM published a third proposed rule on February 13, 2006 (71 FR 
7453). Tribal and industry commenters on the 2006 proposed rule did not 
agree on most issues regarding oil valuation, and none of the 
commenters supported the major portion provisions.
    Also in 2006, the Royalty Policy Committee's Indian Oil Valuation 
Subcommittee evaluated the proposed rule but was unable to reach 
consensus on recommendations to the Department of the Interior on how 
to proceed. Thus, MRM decided to make only technical amendments to the 
existing Indian oil valuation regulations and convene a negotiated 
rulemaking committee to make specific recommendations regarding the 
major portion provision. MRM published its final rule addressing the 
technical amendments on December 17, 2007 (72 FR 71231). The preamble 
of the final rule stated ONRR's intent to convene a negotiated 
rulemaking committee to address the major portion valuation requirement 
for oil produced from Indian leases.
    On December 1, 2011, the Secretary of the Interior (Secretary) 
signed the charter of the Indian Oil Valuation Negotiated Rulemaking 
Committee (Committee). On December 8, 2011, ONRR published, in the 
Federal Register, a notice (76 FR 76634) that the Department of the 
Interior established and created the Committee authorized under the 
Federal Advisory Committee Act. The Secretary established the Committee 
to make recommendations to replace existing regulations governing the 
valuation of oil on Indian lands, specifically the portion of the 
regulations governing the major portion requirement found in most 
standard Indian leases. The Committee met in May, June, August, 
September, and October 2012 and in April, June, August, and September 
2013.
    There were 18 members of the Committee. Members of the Committee 
consisted of representatives of Tribes, individual Indian mineral owner 
associations, oil companies with interests in Indian lands, oil and gas 
trade associations, and the United States government. 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, and Blackfeet Nation represented Tribes 
and individual Indian mineral owner associations. The American 
Petroleum Institute, Council of Petroleum Accountants Societies, 
Western Energy Alliance, Chesapeake Energy, Peak Energy Resources, and 
Resolute Energy Corporation represented industry. ONRR and the Bureau 
of Indian Affairs (BIA) represented the United States government. A 
third-party neutral facilitator led all of the meetings, coordinated 
caucuses, provided the official minutes, and drafted the final report.
    The policy of the Department of the Interior (DOI) is, whenever 
practicable, to afford the public an opportunity to participate in the 
rulemaking process. ONRR announced all of the Committee sessions in the 
Federal Register. The meetings were open to the public to provide it 
the opportunity to participate in the rulemaking process.
    ONRR commends the Committee and its facilitator for reaching 
agreement on addressing the major portion requirement component of the 
regulations governing the value of Indian oil. The members' ability to 
compromise and work together resulted in a valuation proposal that 
would assure Indian Tribes and individual Indian mineral owners will 
receive, in a timely fashion, royalties based on the highest price paid 
for a major portion of production from a field or area. In addition, 
the proposed rule would help members of industry avoid significant 
administrative costs and will assure that the Department of the 
Interior meets its trust responsibilities to Indian Tribes and 
individual Indian mineral owners.

II. General Description of the Proposed Rule

    In September 2013, the Committee published its final report 
summarizing the Committee's proposal for addressing the major portion 
requirement for

[[Page 35103]]

valuing Indian oil production. The report forms the basis for this 
proposed rule and is an essential part of the history for this proposed 
rulemaking. You can find the report, along with the minutes and other 
supporting materials for all meetings at the Committee's Web site at 
http://www.onrr.gov/Laws_R_D/IONR/. Alternatively, contact Karl 
Wunderlich listed under FOR FURTHER INFORMATION CONTACT to obtain a 
mailed copy of the report or to answer any other questions regarding 
the Committee or this rulemaking.
    ONRR is mandated to establish regulations concerning Indian oil 
valuation based on its Federal trust responsibility to Indians, 
including the duty to maximize revenue for Indian Tribes and Indian 
mineral owners. As such, any action the United States takes in relation 
to Indian-owned trust property, including Indian minerals, must be that 
of a trustee who must act in a manner that is in the best interest of 
the Indian owner. Keeping in mind the responsibility to maximize 
revenue, when faced with more than one reasonable alternative, the 
Secretary must choose that alternative that most benefits the Indian 
mineral owner.
    Within the context of the Secretary's Federal trust responsibility, 
the purpose of this rulemaking is to ensure that Indian lessors receive 
maximum revenues from their mineral resources. In addition, this rule 
provides simplicity, certainty, clarity, and consistency for Indian oil 
production valuation for Indian mineral revenue recipients and Indian 
mineral lessees.
    The proposed rule would require a lessee to value its oil produced 
on Indian tribal or allotted lands based on the higher of (1) the 
lessee's gross proceeds or (2) an Index-Based Major Portion (IBMP) 
value adjusted by a Location and Crude Type Differential (LCTD), unique 
to each designated area and crude oil type. The LCTD would assure that 
the calculated major portion price represents, on average, the 
equivalent of a 75% major portion price calculated by arraying all of 
the prices reported in a designated area from the highest to the lowest 
price and starting from the top of the array to determine that price 
associated with the 25th percentile by volume plus one barrel of oil. 
ONRR will base the IBMP on the calendar month average of prices the New 
York Mercantile Exchange (NYMEX) sets, less a differential based on the 
location and crude oil type of the oil. Generally, ONRR will base the 
designated areas on reservation boundaries, with exceptions, as 
discussed further below.
    Each sales month, ONRR would monitor each of the designated areas' 
reported sales volumes to identify when oil sales volumes reported as a 
lessee's gross proceeds are either more than 28 percent, or less than 
22 percent, of the total volumes sold in that designated area for the 
specified crude oil type. In months where the volumes in a designated 
area for a particular crude oil type fall outside 22 to 28 percent of 
the total volumes sold, ONRR would adjust the current month's LCTD up 
or down by 10 percent. ONRR would then use the adjusted LCTD, along 
with the NYMEX Calendar Month Average, to calculate the next month's 
IBMP value. ONRR would continue to adjust the LCTD until the percentage 
of oil sales volumes reported as gross proceeds reflect between 28 and 
22 percent of all sales volumes within a designated area for the 
specified crude oil type. ONRR would publish the monthly IBMP value on 
its Web site at http://www.onrr.gov.
    In addition, the proposed rule modifies some language in the 
current regulations to align with the Federal mandate that agencies 
write all rules in plain language.

III. Section-by-Section Analysis

    Before reading the additional explanatory information below, please 
turn to the proposed rule language that immediately follows the List of 
Subjects in 30 CFR parts 1202 and 1206 and signature page in this 
proposed rule. DOI will codify this language in the CFR if we finalize 
the proposed rule as written.
    After you have read this proposed rule, please return to the 
preamble discussion below. The preamble contains additional information 
about this proposed rule, such as why we defined a term in a certain 
manner and why we chose a certain method to value oil from Indian 
leases.
    The derivation table below only shows a crosswalk of the recodified 
sections of the current and the proposed regulations in part 1206, 
subpart B.

                     Derivation Table for Part 1206
------------------------------------------------------------------------
                                                            Are derived
              The requirements of section:                 from section:
------------------------------------------------------------------------
                                Subpart B
------------------------------------------------------------------------
1206.57.................................................      1206.57(a)
1206.58.................................................     1206.57(b),
                                                            (f), and (g)
1206.59.................................................      1206.57(d)
1206.60.................................................  1206.57(c) and
                                                                     (e)
1206.61.................................................         1206.58
1206.62.................................................         1206.59
1206.63.................................................         1206.60
1206.64.................................................         1206.61
1206.65.................................................         1206.62
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A. Section-by-Section Analysis of Proposed Changes to 30 CFR part 
1206--Product Valuation, Subpart B--Indian Oil

    ONRR proposes to amend part 1206, subpart B, applicable only to 
Indian oil valuation. Many of the provisions are the same as in the 
existing rule in substance. However, ONRR rewrote some sections for 
purposes of clarity. The main substantive change in the proposed rule 
is proposed at Sec.  1206.54, which reflects the Committee's 
recommendations on how lessees should value their oil when their leases 
have a major portion provision or have a provision where the Secretary 
has the authority to establish value.
Purpose (Section 1206.50)
    This section would substantively remain the same as current Sec.  
1206.50. However, we propose to write this section in plain language 
for clarity.
Definitions (Section 1206.51)
    While ONRR will retain all existing definitions, ONRR is adding new 
terms and definitions in this proposed rule to support the new IBMP 
value used in the proposed rule at Sec.  1206.54. ONRR proposes new 
definitions for: Designated area, Location and Crude Type Differential, 
Major Portion Price, Prompt month, Roll, and Trading month. ONRR also 
proposes renaming the term NYMEX price to NYMEX Calendar Month Average 
Price and revising its definition. Finally, ONRR proposes a minor 
revision to the definition Audit to specify that ONRR will conduct 
audits pursuant to the Governmental Auditing Standards.
    Designated Area would be defined as the area ONRR designates for 
purposes of calculating Location and Crude Type Differentials applied 
to the IBMP value. Generally, ONRR would establish designated areas by 
the reservation boundaries where location and crude oil types are 
similar to each other. In some cases, such as Oklahoma, several fields 
may exist within an area that has similar transportation costs and 
crude oil types. In those cases, more than one reservation or field may 
be included within a designated area. ONRR would post designated areas 
on its Web site at www.onrr.gov.

[[Page 35104]]

    If there is a significant change that affects the differential for 
a designated area, affected Tribes, Indian mineral owners, or lessees/
operators may petition ONRR to consider convening a technical committee 
to review, modify, or add designated areas. Criteria to determine any 
future changes include, but are not limited to:
    [ssquf] Markets served, examples include refineries and/or market 
centers, such as Cushing, OK;
    [ssquf] Access to markets, examples include, access to similar 
infrastructure, such as pipelines, rail lines, and trucking; and/or
    [ssquf] Similar geography, for example, no challenging geographical 
divides, large rivers and/or mountains.
    Initially, ONRR proposes the following designated areas:
    1. Fort Berthold--Two designated areas:
    [ssquf] North Fort Berthold--all lands within the Fort Berthold 
Reservation boundary north of the Little Missouri River, including the 
Turtle Mountain public domain lease lands north of the Little Missouri 
River that the Fort Berthold Agency of the BIA administers.
    [ssquf] South Fort Berthold--all lands within the Fort Berthold 
Reservation boundary south of the Little Missouri River, including the 
Turtle Mountain public domain lease lands south of the Little Missouri 
River that the Fort Berthold Agency of the BIA administers.
    2. Uintah & Ouray--Two designated areas: Uintah and Grand Counties; 
Duchesne County.
    3. Oklahoma--One statewide designated area encompassing all oil 
production on trust lands, excluding Osage County.
    4. Fort Peck--designated area includes all lands within the Fort 
Peck Reservation boundary and the Turtle Mountain public domain lease 
lands administered by the Fort Peck Agency of the BIA.
    5. Fort Belknap--designated area includes all lands within the Fort 
Belknap Reservation boundary and the Turtle Mountain public domain 
lease lands administered by the Fort Belknap Agency of the BIA.
    6. Turtle Mountain--designated area includes all lands within the 
Turtle Mountain Reservation and the Turtle Mountain public domain lease 
lands administered by the Turtle Mountain Agency of the BIA.
    7. The designated area for all other reservations would be the 
reservation boundary, including any off-reservation allotments or 
dependent Indian communities. They include, but are not limited to, 
the:
    [ssquf] Blackfeet Indian Reservation.
    [ssquf] Crow Indian Reservation.
    [ssquf] Jicarilla Apache Indian Reservation.
    [ssquf] Isabella Indian Reservation (Saginaw Chippewa).
    [ssquf] Navajo Indian Reservation.
    [ssquf] Ute Mountain Ute Indian Reservation.
    [ssquf] Wind River Indian Reservation.
    [ssquf] Alabama/Coushatta Indian Reservation.
    [ssquf] Southern Ute Indian Reservation.
    [ssquf] Rocky Boy's Indian Reservation.
    Location and Crude Type Differential (LCTD) would mean the 
difference in value between the average of the monthly NYMEX Calendar 
Month Average (CMA) for the previous 12 months and the average of the 
monthly Major Portion Prices for the previous 12 months for a 
designated area for any given crude oil type. The LCTD also captures 
the difference in value due to location and quality differences between 
Light Sweet Crude (WTI) at Cushing, Oklahoma and other crude oil types 
in each designated area.
    Initially, ONRR would establish the LCTD based on the previous 
year's average annual difference between the NYMEX CMA and the Major 
Portion Price. ONRR would calculate the Major Portion Price by arraying 
all of the prices reported in a designated area from the highest to the 
lowest price and starting from the top of the array to determine that 
price associated with the 25th percentile by volume plus one barrel of 
oil. ONRR would calculate a separate LCTD for each crude oil type 
within each designated area using all calculated values (arm's-length 
and non-arm's-length) payors report on Form ONRR-2014. The array to 
establish the initial LCTD also would include sales reported on Form 
ONRR-2014 as royalty-in-kind (Transaction Code 06). In addition, the 
sales values ONRR uses in the array would be net of transportation 
allowances.
    To calculate the initial LCTD, ONRR would require payors to report 
new crude oil types on ONRR Form-2014 using the existing Product Code 
field. ONRR anticipates having 12 months of new reported data to 
calculate the initial LCTD. However, should ONRR not have the full 12 
months of crude oil types prior to the effective date of the rule, ONRR 
would assume the crude oil type is the same for those leases/agreements 
for the months for which ONRR does have crude oil type data reported on 
Form ONRR-2014s for the same leases and/or agreements.
    For leases from which royalty is taken in kind now or in the 
future, ONRR would require lessees to report their total sales volume 
and base the sales value reported on Form ONRR-2014 on the higher of: 
(1) The IBMP value (reported as OINX), or (2) the price the lessee 
receives for volumes sold (reported as something other than OINX). ONRR 
would not consider the royalty-in-kind share of production in 
determining whether ONRR must modify the LCTD for a specific designated 
area and crude oil type.
    Major Portion Price would mean 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.
    Prompt month would mean the nearest month of delivery for which 
NYMEX futures prices are published during the trading month.
    Roll would mean a method for adjusting current month prices for 
future prices to smooth the variation in oil trading prices and reflect 
market expectations. ONRR proposes to apply a ``roll'' to the initial 
NYMEX oil prices from leases in Oklahoma. Because NYMEX prices are 
future price estimates, and, therefore, inherently reflect increases or 
decreases in prices based upon expected trends, an adjustment to such 
estimates is necessary to extrapolate back to current price estimates 
upon which royalty calculations are based. This adjustment is the 
``roll.'' The roll is added to the initial NYMEX price when the market 
is falling (to correct for the fact that the current price should be 
higher than the future price in a falling market) and subtracted from 
the initial NYMEX prices when the market is rising (to correct for the 
fact that the current price should be lower than the future price if 
the market is rising). We propose to use the roll because we believe it 
represents current market practice in establishing the sales price for 
crude oil production in Oklahoma.
    The roll formula includes the future prices for the two months 
beyond the prompt month, which is not the same as the prompt month used 
to determine the initial NYMEX price, and assigns a progressively 
smaller weight to the second and third months. This is consistent with 
ONRR's understanding of the common industry practice, including the 
weights and basis for the prices in the formula below. Specifically, 
the roll would be calculated as follows:

Roll = .6667 x (P0-P1) + .3333 x (P0-
P2),

Where:

[ssquf] 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.

[[Page 35105]]

[ssquf] P1 = the average of the daily NYMEX settlement 
prices for deliveries during the 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.
[ssquf] 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.

    Note that although prices P0, P1, and 
P2 represent separate prices for periods 1, 2, and 3 months 
beyond the trading month, respectively, they are all determined during 
the same trading month. The roll may be a positive or a negative 
number, and, therefore, increase or decrease the royalty value, 
depending on whether the futures market is falling or rising. For 
example, assume that the month of production for which you must 
determine royalty value is March 2013. March was the prompt month on 
the NYMEX from January 23 through February 20, which is the trading 
month in this case. April is the first month following the month of 
production, and May is the second month following the month of 
production. As explained above, to determine the initial NYMEX price 
which the roll will adjust, for March 2013 production you first take 
the average of the daily settlement prices published for each business 
day from March 1 through March 20 for deliveries in April (the prompt 
month) and for each business day from March 21 through March 31 for 
deliveries in May (after May becomes the prompt month).
    To calculate P0, a different set of days is used. 
P0 is the average of the daily NYMEX settlement prices for 
deliveries during March published for each business day between January 
23 and February 20 (the trading month). P1 is the average of 
the daily NYMEX settlement prices for deliveries during April published 
for each business day during the same trading month, i.e. between 
January 23 and February 20. Similarly, P2 is the average of 
the daily NYMEX settlement prices for deliveries during May published 
for each business day during the same trading month used for 
P0 and P1. In this example, assume that 
P0 = $98.00 per bbl; P1 = $97.70 per bbl; and 
P2 = $97.10 per bbl. In this declining market, the roll = 
.6667 x ($98.00 minus 97.70) + .3333 x ($98.00 minus 97.10) = $0.20 + 
$0.30 = $0.50. Fifty cents per barrel would then be added to the 
initial NYMEX settlement price used as the basis for royalty valuation.
    In this example, since the market is falling, prices that traders 
anticipate during the trading month (March) for deliveries in a future 
prompt month are lower than the prices at which oil actually is selling 
during March. The roll accounts for that trend. The roll will have the 
opposite effect in a rising market. The roll will be a subtraction from 
the initial NYMEX price calculation (adding a negative number to the 
NYMEX price) because traders anticipate higher prices for the future 
prompt months than actually are occurring during the calendar month of 
production.
    The roll would be added to the initial NYMEX price used as the 
basis for royalty valuation for Indian leases in Oklahoma. This is 
because sales contracts for Indian oil in Oklahoma typically include 
the roll, whereas current sales contracts in other designated areas do 
not.
    While ONRR expects the basic operation of the NYMEX market to be 
the same for the foreseeable future, it is not clear the roll will be a 
permanent feature of the marketplace. Therefore, ONRR proposes that the 
Director of ONRR would have the option of terminating use of the roll 
when ONRR believes that using the roll is no longer a common industry 
practice. To terminate the roll, ONRR will publish a notice in the 
Federal Register. Further, ONRR also proposes to have the option to 
redefine how the roll is calculated to comport with changes in industry 
practice through a notice published in the Federal Register. ONRR will 
explain its rationale when it publishes such notice. ONRR believes this 
flexibility is appropriate so the valuation standards more closely 
reflect market developments. ONRR specifically requests comments on 
whether these options are necessary.
    Trading month would mean 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.
Royalty Value for Oil I or My Affiliate Sells or Exchanges Under an 
Arm's-Length Contract (Section 1206.52)
    This section is unchanged from the existing rule with the 
exceptions of clarifying (1) that value is the higher of the value 
calculated under this section or the new major portion provision under 
Sec.  1206.54, (2) that you bear the burden of demonstrating that the 
contract is arm's-length and may be required to certify that the 
contract includes all consideration, and (3) that this provision 
applies notwithstanding any contrary Code of Federal Regulation 
provisions. Other portions of existing Sec.  1206.52 have been moved to 
other sections of the new regulations.
Oil Royalty Value Not Sold Under an Arm's-Length Contract (Section 
1206.53)
    This section is unchanged from the existing rule with the exception 
of clarifying that value is the higher of the value calculated under 
this section or the new major portion provision under Sec.  1206.54.
Value of Production Based on the Major Portion of Like-Quality Oil 
(Section 1206.54)
    This section is the principal new provision of the proposed 
regulation and is based on the recommendations of the Committee. This 
proposal removes the existing text of Sec.  1206.54 and replaces it 
with new language explaining how a lessee fulfills the obligation under 
its lease to value crude oil produced from Indian leases based on the 
highest prices paid for a major portion of production of like-quality 
oil from the field. Proposed paragraph (a) states that this would apply 
to any Indian lease that has a major portion provision. This section 
also applies to Indian leases where the Secretary of Interior may 
determine value. For such leases, paragraph (a) would state that the 
value for royalty purposes is the higher of the value determined under 
the section or your gross proceeds under Sec.  1206.52 or Sec.  
1206.53.
    Under paragraph (b) of the proposed rule, lessees would report 
royalties on the Form ONRR-2014 using the higher of (1) an IBMP value, 
or (2) the lessee's gross proceeds.
    Where the value of the lessee's oil is the gross proceeds accruing 
to the lessee under an arm's-length contract, the lessee would report 
its gross proceeds on its Form ONRR-2014 using Sales Type Code (STC) 
other than OINX. If the IBMP value is higher than gross proceeds, then 
the lessee must report the IBMP value using STC OINX. If

[[Page 35106]]

there is no sale of the crude oil and the lessee bases its value on a 
weighted average of the affiliates' arm's-length purchases and/or sales 
under Sec.  1206.53, then the lessee must report using STC NARM.
    Under paragraph (c) of the proposed rule, ONRR would calculate the 
IBMP value using the NYMEX CMA (excluding weekends and holidays) for 
each designated area less the LCTD. As explained above, the LCTD is 
based on the average difference between the NYMEX CMA and the major 
portion price at the 25th percentile by volume plus one barrel from 
highest price to lowest price, starting from the top (the top means 
that volume associated with the highest price for any given month). For 
leases in Oklahoma, the IBMP value would include the ``roll,'' as 
defined above.
    The IBMP value would be calculated as follows:
    [GRAPHIC] [TIFF OMITTED] TP19JN14.002
    
    Paragraph (d) describes how ONRR would calculate the LCTD for each 
designated area. As explained above, LCTD captures the difference in 
value due to location and quality differences between Light Sweet Crude 
(WTI) at Cushing, Oklahoma and other crude oil types in each designated 
area. The LCTD also ensures that the IBMP price closely reflects the 
75% major portion value of a particular crude type within the 
applicable designated area.
    Paragraph (d) provides details on how ONRR would calculate the LCTD 
for each designated area. Initially, ONRR would establish the LCTD 
based on the previous year's average annual difference between the 
NYMEX CMA and the Major Portion Price calculated by arraying all of the 
prices reported in a designated area from the highest to the lowest 
price and starting from the top of the array, determining that price 
associated with the 25th percentile by volume plus one barrel of oil. 
Paragraph (1) would explain that ONRR would calculate a separate LCTD 
for each crude type within each designated area using all data (arm's-
length and non-arm's-length) payors report on Form ONRR-2014 for the 
previous 12 production months prior to the effective date of the rule. 
If ONRR does not have 12 months of data prior to the effective date of 
the rule, then it would assume the data is the same as that for the 
months for which data was reported. ONRR would apply this initial LCTD 
the first month after the effective date of the rule.
    As an example, assume that for the initial LCTD for a specific 
designated area and crude type, ONRR calculated a prior year average 
annual major portion value of $81.54. Further, assume that ONRR 
calculated a prior year average annual NYMEX CMA of $95.12. Then assume 
that the effective date of the rule is March 30, 2015. Lastly, assume 
the NYMEX CMA for April 2015 is $94.56. ONRR would calculate the LCTD 
for Designated Area X as follows:
[GRAPHIC] [TIFF OMITTED] TP19JN14.003

    ONRR would then apply the initial LCTD to the April 2015 NYMEX CMA 
to calculate the IBMP value as follows:

$94.56 x (1 - 0.1428) = $81.06

If your gross proceeds value is more than the $81.06 IBMP value, you 
would have to report your gross proceeds on Form ONRR-2014 using the 
appropriate STC other than OINX, such as ARMS. If your gross proceeds 
value is less than the $81.06 IBMP value, then you would have to report 
the IBMP value using STC OINX.
    Paragraph (d)(2) of the proposed rule outlines how ONRR would 
monitor the LCTD after its initial calculation. ONRR would monitor each 
of the designated areas' monthly sales volumes lessees report on their 
Form ONRR-2014s to identify when oil sales volumes not reported as STC 
OINX are either more than 28 percent or less than 22 percent of the 
total sales volumes reported in that designated area for a specific 
crude oil type. When sales volumes not reported as OINX for a specific 
crude oil type in a designated area exceed 28 percent or fall below 22 
percent of the total volumes sold, ONRR would adjust the next month's 
LCTD down or up by 10 percent of the current month's LCTD. ONRR would 
then use the adjusted LCTD, along with the NYMEX CMA to calculate the 
next month's IBMP value. ONRR would continue to adjust the LCTD each 
month until the percentage of oil sales volumes not reported as OINX 
reflects between 28 and 22 percent of all sales volumes within a 
designated area for the specified crude oil type. ONRR would publish 
the monthly IBMP value on its Web site at http://www.onrr.gov. The 
proposed rule provides two examples demonstrating how the trigger for 
the LCTD works. Paragraph (e) provides that ONRR would use its 
discretion to determine an appropriate IBMP value where there are 
insufficient royalty lines reported to ONRR on Form ONRR-2014 to 
determine a differential for a specific crude oil type. For example, 
there will be some instances, including, but not limited to, sales of 
condensate, where it is impossible for ONRR to calculate an appropriate 
differential. In those circumstances, ONRR would determine the IBMP 
value. ONRR is concerned that if an LCTD were to vary to a significant 
degree, for example +/-20 percent, it could take ONRR numerous months 
to bring the LCTD back to within +/-3 percent of the 25 percent of 
total oil sales volumes reported in a designated area for a specific 
crude oil type. Therefore, we specifically request comments on whether 
ONRR should modify paragraph (e) to provide that ONRR would use its 
discretion to determine an appropriate IBMP value where there are 
insufficient lines reported to ONRR on Form ONRR-2014 to determine a 
differential for a specific crude oil type or when the LCTD varies more 
than +/-20 percent. We also request comments on what could constitute a 
significant variation.
Responsibility To Place Production Into Marketable Condition and Market 
Production (Section 1206.55)
    This section would remain the same as current Sec.  1206.55. 
However, we propose to divide this section into two subsections, (a) 
and (b), and to write this section in plain language for clarity.
General Transportation Allowance Requirements (Section 1206.56)
    This section would remain the same as current Sec.  1206.56 except 
for adding language from (1) the current Sec.  1206.57(a) stating that 
transportation allowances are subject to monitoring, review, 
adjustment, and audit and (2)

[[Page 35107]]

the current Sec.  1206.51 and Sec.  1206.52 stating that you may not 
deduct gathering costs as transportation allowances or deductions. In 
addition, we propose to rewrite this section and its section name in 
plain language to provide clarity.
Arm's-Length Contract Transportation Allowances (Section 1206.57); Non-
Arm's-Length Contract or No Contract Transportation Allowances (Section 
1206.58); Late Payment Interest for Improper Transportation Allowance 
Reporting (Section 1206.59); Reporting Adjustments for Transportation 
Allowances (Section 1206.60)
    ONRR would reorganize Sec.  1206.57 into proposed new Sec. Sec.  
1206.57, 1206.58, 1206.59, and 1206.60. Proposed Sec.  1206.57 would 
govern how to determine and report transportation allowances if there 
is an arm's-length transportation contract, currently in Sec.  
1206.57(a) and (c)(1). Proposed Sec.  1206.58 would govern how to 
determine and report transportation allowances under non-arm's-length 
transportation contracts, which is currently in Sec.  1206.57(b) and 
(c)(2). Section 1206.58 also includes existing paragraphs (f) and (g) 
of Sec.  1206.57 as proposed Sec.  1206.58(c) and (d). ONRR proposes to 
add Sec.  1206.59 to show how ONRR would calculate interest where a 
lessee improperly reports a transportation allowance. Currently, 
interest assessments for transportation allowances can be found in 
Sec.  1206.57(d). ONRR proposes to move the current provision in Sec.  
1206.57(e)--adjusting transportation allowances--under proposed Sec.  
1206.60.
ONRR Determination of Correct Royalty Payments (Section 1206.61)
    Because of the changes in the proposed rule regarding 
transportation allowances, the proposed rule redesignates Sec.  1206.58 
as Sec.  1206.61. In the proposed rule, the provisions are the same as 
in the existing rule in Sec.  1206.58 in substance but clarify how ONRR 
will determine if royalty payments are correct and what to do when 
royalty payments are incorrect.
Valuation Determination Requests (Section 1206.62)
    Because of the changes in the proposed rule regarding 
transportation allowances, the proposed rule redesignates Sec.  1206.59 
as Sec.  1206.62. This new section is the same as in the existing rule 
in substance in 1206.59. However, the proposed rule provides clarity by 
expanding how to request a valuation determination and how ONRR 
responds to such requests.
Determination of Royalty Quantity and Quality (Section 1206.63)
    Because of the changes in the proposed rule regarding 
transportation allowances, the proposed rule redesignates Sec.  1206.60 
as Sec.  1206.63. The provisions are the same as in the existing Sec.  
1206.60.
Recordkeeping Requirements (Section 1206.64)
    This proposed section is the same as current Sec.  1206.61. 
However, we propose to write this section in plain language for 
clarity.
ONRR's Protection of Information Submitted (Section 1206.65)
    This proposed section is the same as current Sec.  1206.62. 
However, we propose to divide this section into three subsections, (a), 
(b), and (c), and to write in plain language for clarity.

B. Section-by-Section Analysis of Proposed Changes to 30 CFR Part 
1210--Forms and Reports, Subpart B--Royalty Reports--Oil, Gas, and 
Geothermal Resources

    ONRR proposes to amend Part 1210 by adding Sec.  1210.61 that 
contains additional reporting requirements for crude oil. The new 
proposed Sec.  1210.61(a) requires payors to report Sales Type Code 
ARMS on their Form ONRR-2014 when valuing oil under Sec.  1206.52. The 
new proposed Sec.  1210.61(b) requires payors to report Sales Type Code 
NARMS on their Form ONRR-2014 when valuing oil under Sec.  1206.53. The 
new proposed Sec.  1210.61(c) requires payors to report Sales Type Code 
OINX on their Form ONRR-2014 when valuing oil under Sec.  1206.54. 
Under Sec.  1210.61(d), crude oil type payors would report five crude 
oil types: (1) Sweet as product code 61; (2) sour as product code 62; 
(3) asphaltic as product code 63; (4) black wax as product code 64; and 
(5) yellow wax as product code 65.
    Before the effective date of the rule, ONRR would explain that 
payors should report using the additional product codes reflecting the 
crude oil type of the Indian oil within a particular designated area on 
the payors' Form ONRR-2014s. Prior to the effective date of the rule, 
ONRR would issue a letter to all payors explaining when to begin 
reporting such product codes and how to report the crude oil types.

IV. Other Possible Changes ONRR May Consider

A. Transportation Allowances--Form Filing

    For arm's-length transportation agreements, ONRR would like 
comments on removing the requirement under the current rule to file a 
Form ONRR-4110, Oil Transportation Allowance Report. Instead, the 
lessee would have to submit to ONRR copies of its arm's-length 
transportation contract(s) and any amendments thereto within 2 months 
after the lessee reported a transportation allowance on its Form ONRR-
2014. This change would mirror the requirement to file arm's-length 
transportation contracts with ONRR, instead of a form, under the 
current Indian Gas Valuation Rule at Sec.  1206.178(a)(1)(i).
    For non-arm's-length transportation arrangements, ONRR would like 
comments on eliminating the requirement that lessees submit a Form 
ONRR-4110 in advance with estimated information. Lessees would still be 
required to submit the Form ONRR-4110. However, the lessee would submit 
actual cost information in support of the allowance on its Form ONRR-
4110 within 3 months after the end of the 12-month period to which the 
allowance applies. This change would also mirror the 1999 Indian Gas 
Rule.
    Of note, under the proposed rule, there would be no form filing 
requirements where a lessee values its oil under the IBMP value 
(proposed rule Sec.  1206.54). Thus, these changes to the form filing 
requirements would only apply to those lessees reporting their oil 
royalties as either gross proceeds under Sec.  1206.52 or as non-arm's-
length under Sec.  1206.53.
    As ONRR explained when it proposed these changes in the 1999 Indian 
Gas Rule, ONRR believes these changes ``would ease the burden on 
industry and still provide ONRR with documents useful to verify the 
allowance claimed.''
    ONRR requests comments on (1) eliminating the form filing 
requirement for arm's-length contracts and instead submitting the 
contract(s) to ONRR; and (2) removing the current rule's requirement 
that lessees reporting non-arm's-length transportation arrangements 
submit a Form ONRR-2014 with estimated information prior to taking the 
transportation allowance.

B. Transportation Factors

    ONRR requests comments on eliminating transportation factors from 
the regulations. Currently, Sec.  1206.57(a)(5) allows lessees to 
reduce their gross proceeds where their arm's-

[[Page 35108]]

length transportation contract includes a provision reducing the 
applicable price by a transportation factor. Under the current rule, 
lessees report their gross proceeds net of the transportation factor on 
their Form ONRR-2014s. Thus, unlike the transportation allowances, 
which lessees report on their Form ONRR-2014s, ONRR cannot tell if 
lessees are taking a deduction for transportation when lessees report 
their gross proceeds net of a transportation factor. As such, the 
reporting requirements for transportation factors are not transparent. 
Eliminating the ability to net an arm's-length transportation fee would 
require lessees to report these transportation fees as a transportation 
allowance. ONRR specifically requests comments on whether to eliminate 
transportation factors completely, which would require reporting of the 
arm's-length transportation as a transportation allowance on Form ONRR-
2014.

C. Limiting Allowances

    ONRR is also considering removing the exception to the 50-percent 
limitation on transportation allowances. Under the current rule at 
Sec.  1206.56(b)(2), a lessee may request an exception to the rule that 
transportation allowances cannot exceed 50 percent of the value of the 
oil at the point of sale. ONRR seeks input on whether it would be a 
better exercise of the Secretary's trust responsibility to not allow 
cost allowances for transporting production from Indian leases to 
exceed 50 percent of the value of the oil. To date, ONRR has not 
received any requests to exceed the 50-percent limitation for 
transportation allowances. ONRR specifically requests comments on 
removing any exceptions to the 50-percent limitation on transportation 
allowances, under Sec.  1206.56(b)(1).

V. 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. The proposed amendment would result in an estimated 
annual increase in royalty collections of between $19.4 million and 
$20.6 million to be disbursed 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 ONRR collected in 2012. We also 
estimate that Industry and the Federal Government would 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 costs that Industry would incur in the first year (excluding one-
time system costs). Industry would 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, we propose to add 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. The proposed rule 
defines the monthly IBMP value that 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 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 & Ouray--Uintah and Grand Counties.
    2. Uintah & 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.
    Last, 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 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 LCTD is used 
in the IBMP value to keep 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 the 
rule would allow. Instead, we created a +/-3 percent range of royalty 
impacts above and below the estimated additional royalties, reflected 
in the table above.
Cost--System Changes To Accommodate Reporting of Crude Oil Type
    ONRR needs to know crude oil types to calculate and publish the 
IBMP value. Therefore, proposed Sec.  1210.61 requires a lessee to 
report crude oil types using new product codes on the Form ONRR-2014. 
ONRR anticipates a lessee would need to 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 less). 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 less employees. We classified 58 companies as 
medium companies and 115 companies as small companies.

[[Page 35109]]

    ONRR first identified the changes we must make to our systems 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 proposed 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 
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.

----------------------------------------------------------------------------------------------------------------
                                                                                      Medium
                 System changes                        ONRR       Large business     business     Small business
----------------------------------------------------------------------------------------------------------------
Adding product codes to ONRR 2014-PS............             100             100             100              50
Adding product codes to ONRR 2014-eCommerce.....             100               0               0               0
Adding new edit.................................             150              75               0               0
Changing reports................................             250             100               0               0
Changes to CPT..................................             150               0               0               0
Changes to Web publishing.......................             150               0               0               0
Changes to OGOR/PASR form.......................             150             100             100              50
                                                 ---------------------------------------------------------------
    Total hours.................................           1,050             375             200             100
Average hourly rate.............................          x $235          x $235          x $100           x $75
                                                 ---------------------------------------------------------------
Cost per entity.................................        $246,750         $88,125         $20,000          $7,500
[Total hours x Average 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 proposed changes, based on the mid-range 
estimate of costs:

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

    After the first year, we anticipate the estimated cost to Industry 
to be approximately $20,000,000 each year, based on 2012 data.
B. Indian Lessors
    The impact to Indian Lessors would be a net overall increase in 
royalties as a result of this proposed change. This royalty increase 
would 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 would incur system costs to accommodate 
crude oil type reporting similar to Industry. As detailed above, ONRR 
estimates that it would take 1,050 hours to implement system changes 
related to the proposed rule equating to a total cost of $246,750.
    This rulemaking would have no impact on Federal royalties. We also 
believe that there would be no administrative cost increases to the 
Federal Government because the additional work needed to monitor and 
adjust the LCTD and IBMP value would be offset by administrative 
savings due to decreased audit and litigation costs.
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 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
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, the proposed rule will cost industry 
approximately $20 million a year and Indian lessors will increase their 
annual royalty receipts by approximately $20 million. The Federal

[[Page 35110]]

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 proposed 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. 
The 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 proposed rule in a manner 
consistent with these requirements.

3. Regulatory Flexibility Act

    The Department of the Interior certifies that this proposed rule 
would 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.). 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 remaining 173 
companies are considered to be small business.
    As provided in 1A Industry in the Procedural Matters section, we 
believe industry would incur a one-time cost to comply with the 
proposed rule. On average, ONRR estimates that each small business 
would incur a one-time cost of between of $7,500 and $20,000 to modify 
their systems to comply with this rulemaking.
    As we stated earlier, we believe, based on 2012 Indian oil sales, 
the proposed rule would cost industry approximately $20 million dollars 
a 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 proposed major portion provision would cost all 
small-business lessors approximately $2,710,000 per year. The amount 
would vary for each company depending on the volume of production each 
small business produces and sells each year. We believe reduced 
administrative costs, such as reduced accounting, auditing, and 
litigation expenses, would offset some of these costs.
    In sum, we do not believe this rulemaking would 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 would be between $7,500 and $20,000; and (2) this proposed rule 
would cost the small businesses a collective total of $2,710,000 per 
year.
    ONRR encourages small businesses to comment on this proposed rule.

4. Small Business Regulatory Enforcement Fairness Act (SBREFA)

    This proposed rule would not be a major rule under 5 U.S.C. 804(2), 
the Small Business Regulatory Enforcement Fairness Act. This 
rulemaking:
    a. Would not have an annual effect on the economy of $100 million 
or more. The effect would be limited to a maximum estimated at 
$2,710,000 which equals the $20,000,000 yearly cost of the proposed 
rule to industry at large multiplied by 13.55% (volumes sold 
attributable to small businesses).
    b. Would not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, Indian, or local 
government agencies, or geographic regions.
    c. Would 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 proposed rule would not impose an unfunded mandate on State, 
local, or Tribal governments or the private sector of more than $100 
million per year. This rulemaking would not have a significant or 
unique effect on State, local, or Tribal governments or the private 
sector. A statement containing the information required by the Unfunded 
Mandates Reform Act (2 U.S.C. 1501 et seq.) would not be required.

6. Takings (E.O. 12630)

    Under the criteria in section 2 of E.O. 12630, this proposed rule 
would not have any significant takings implications. This proposed rule 
would not impose conditions or limitations on the use of any private 
property. Therefore, a takings implication assessment is not required.

7. Federalism (E.O. 13132)

    Under the criteria in section 1 of E.O. 13132, this proposed rule 
would not have sufficient federalism implications to warrant the 
preparation of a Federalism summary impact statement. This rulemaking 
would 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 all royalties 
ONRR collects from Indian leases are distributed to Tribes and 
individual Indian mineral owners. Because this proposed rule would not 
alter that relationship, a Federalism summary impact statement is not 
required.

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

    This rulemaking would comply with the requirements of E.O. 12988. 
Specifically, this proposed rule:
    a. Would meet the criteria of section 3(a) requiring that all 
regulations be reviewed to eliminate errors and ambiguity and be 
written to minimize litigation.
    b. Would meet the criteria of section 3(b)(2) requiring that all 
regulations be written in clear language and contain clear legal 
standards.

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

    The Department of the Interior 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 proposed rule and determined that it would 
have no tribal implications that would impose substantial direct 
compliance costs on Indian tribal governments. 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 three different locations for 
the purpose of consulting with Indian tribes and individual Indian 
mineral owners and

[[Page 35111]]

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; and December 
14, 2013, at the Wes Watkins Technology Center at Wetumka, Oklahoma. 
ONRR plans to schedule additional consultation sessions with Tribes and 
individual Indian mineral owners to discuss and hear comments, 
including sessions in Albuquerque, New Mexico; Browning, Montana; and 
Ft. Duchesne, Utah.

10. Paperwork Reduction Act of 1995

    This rulemaking would not contain new information collection 
requirements, and a submission to the Office of Management and Budget 
(OMB) would not be required under the Paperwork Reduction Act of 1995 
(44 U.S.C. 3501 et seq.). The proposed rule would 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 Form ONRR-2014s under 
OMB Control Number 1012-0004. ONRR estimates no additional burden 
hours, beyond the initial hours that industry must incur to modify 
systems to accommodate the rule, to report the applicable crude oil 
type in the product code field.

11. National Environmental Policy Act

    This proposed rule would 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 proposed 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 rulemaking is 
not involved in any of the extraordinary circumstances listed in 43 CFR 
46.215 that would require further analysis under NEPA. The procedural 
changes resulting from the IBMP value would have no consequence on the 
physical environment. This proposed rule would not alter, in any 
material way, natural resources exploration, production, or 
transportation.

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

    This rulemaking would not be a significant energy action under the 
definition in E.O. 13211, and, therefore, would not require a Statement 
of Energy Effects.

13. Clarity of This Regulation

    We are required by E.O. 12866 (section 1(b)(12)), E.O. 12988 
(section 3(b)(1)(B)), E.O. 13563 (section 1(a)), and Presidential 
Memorandum of June 1, 1998, to write all rulemaking in plain language. 
This means that each rulemaking we publish must: (a) Be logically 
organized; (b) use the active voice to address readers directly; (c) 
use common, everyday words, and clear language rather than jargon; (d) 
be divided into short sections and sentences; and (e) use lists and 
tables wherever possible.
    If you feel that we have not met these requirements, send us 
comments by one of the methods listed in the ADDRESSES section. To help 
revise the proposed rule, write your comments as specific as possible. 
For example, you should tell us the numbers of the sections or 
paragraphs that you find unclear, which sections or sentences are too 
long, and the sections where you feel lists or tables would be useful, 
etc.

14. Public Availability of Comments

    We will post all comments, including names and addresses of 
respondents, at www.regulations.gov. Before including Personally 
Identifiable Information (PII), such as address, phone number, email 
address, or other personal information in your comment(s), be advised 
that your entire comment (including PII) may be made available to the 
public at any time. While you can ask us, in your comment, to withhold 
PII from public view, we cannot guarantee that we will be able to do 
so.

List of Subjects in 30 CFR Parts 1206 and 1210

30 CFR Parts 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, Indian leases, Geothermal energy, Government 
contracts, Indians-lands, Mineral royalties, Oil and gas reporting, 
Phosphate, Potassium, Reporting and recordkeeping requirements, 
Royalties, Sales contracts, Sales summary, Sodium, Solid minerals, 
Sulfur.

    Dated: May 13, 2014.
Rhea Suh,
Assistant Secretary for Policy, Management and Budget.

Authority and Issuance

    For the reasons discussed in the preamble, ONRR proposes to amend 
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?

[[Page 35112]]

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 noncontrol that ONRR may 
rebut.
    (2) If there is ownership or common ownership of 10 through 50 
percent of the voting securities or instruments of ownership, or other 
forms of ownership, of another person, ONRR will consider the following 
factors in determining whether there is control in a particular case:
    (i) The extent to which there are common officers or directors;
    (ii) With respect to the voting securities, or instruments of 
ownership, or other forms of ownership:
    (A) The percentage of ownership or common ownership;
    (B) The relative percentage of ownership or common ownership 
compared to the percentage(s) of ownership by other persons;
    (C) Whether a person is the greatest single owner; and
    (D) Whether there is an opposing voting bloc of greater ownership;
    (iii) Operation of a lease, plant, or other facility;
    (iv) The extent of participation by other owners in operations and 
day-to-day management of a lease, plant, or other facility; and
    (v) Other evidence of power to exercise control over or common 
control with another person.
    (3) Regardless of any percentage of ownership or common ownership, 
relatives, either by blood or marriage, are affiliates.
    Area means a geographic region at least as large as the defined 
limits of an oil and/or gas field in which oil and/or gas lease 
products have similar quality, economic, and legal characteristics.
    Arm's-length contract means a contract or agreement between 
independent persons who are not affiliates and who have opposing 
economic interests regarding that contract. To be considered arm's 
length for any production month, a contract must satisfy this 
definition for that month, as well as when the contract was executed.
    Audit means a review, conducted under the generally accepted 
Governmental Auditing Standards, of royalty reporting and payment 
activities of lessees, designees, or other persons who pay royalties, 
rents, or bonuses on Indian leases.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    Condensate means liquid hydrocarbons (generally exceeding 40 
degrees of API gravity) recovered at the surface without resorting to 
processing. Condensate is the mixture of liquid hydrocarbons that 
results from condensation of petroleum hydrocarbons existing initially 
in a gaseous phase in an underground reservoir.
    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by 
law that with due consideration creates an obligation.
    Designated area means an area ONRR designates for purposes of 
calculating Location and Crude Type Differentials applied to an IBMP 
value. ONRR will post designated areas on its 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 its 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, for example, 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, and other consideration. 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

[[Page 35113]]

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 the lease, 
unit, or communitized area as approved by BLM operations personnel.
    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 covered by that 
authorization.
    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); and
    (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 average of the monthly NYMEX Calendar Monthly 
Averages (CMA) for the previous 12 months and the average of the 
monthly Major Portion Prices for the previous 12 months for a 
designated area for each crude oil type calculated under Sec.  1206.54.
[GRAPHIC] [TIFF OMITTED] TP19JN14.004

    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; and
    (2) Divide the sum by the number of days on which those prices are 
published (excluding weekends and holidays).
    Oil means a mixture of hydrocarbons that existed in the liquid 
phase in natural underground reservoirs and remains liquid at 
atmospheric pressure after passing through surface separating 
facilities and is marketed or used as such. Condensate recovered in 
lease separators or field facilities is considered to be oil.
    ONRR means the Office of Natural Resources Revenue of the 
Department of the Interior.
    Operating rights owner, also known as a working interest owner, 
means any person who owns operating rights in a lease subject to this 
subpart. A record title owner is the owner of operating rights under a 
lease until the operating rights have been transferred from record 
title (see Bureau of Land Management regulations at 43 CFR 3100.0-
5(d)).
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Processing means any process designed to remove elements or 
compounds (hydrocarbon and nonhydrocarbon) 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

[[Page 35114]]

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).

    (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; and
    (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 the lease, unit area, or communitized area. The 
transportation allowance does not include gathering costs.
    WTI means West Texas Intermediate.
    You means a lessee, operator, or other person who pays royalties 
under this subpart.


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; or
    (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 volume-weighted average of the 
values established under this section for all contracts for the sale of 
oil produced from that lease.
    (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.

[[Page 35115]]

    (e) ONRR may require you to certify that the provisions in your or 
your affiliate's contract include all of the consideration the buyer 
paid 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 to permit you to avoid your royalty 
payment obligation in situations where a purchaser fails to pay, in 
whole or in part, or timely, 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.
    (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.  
1206.56 and Sec.  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 you 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.  1206.56 and Sec.  1206.57 or 
Sec.  1206.58.
    (3) You must adjust your gross proceeds for any location or quality 
differential, or other adjustments, 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 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, ONRR will allow a 
deduction, under Sec.  1206.56 and Sec.  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; and
    (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 (c)(1) nor (c)(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.  1206.56 and Sec.  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, 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.

    Example (1) to paragraph (b):  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.
----------------------------------------------------------------------------------------------------------------


[[Page 35116]]

    Example (2) to paragraph (b):  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).
----------------------------------------------------------------------------------------------------------------

    Example (3) to paragraph (b):  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.  1206.56 and Sec.  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; and
    (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, the ONRR 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 
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 of this chapter.
    (c) ONRR will determine the monthly IBMP value for each designated 
area and crude oil type and post those values on its Web site at 
www.onrr.gov. The monthly IBMP value by designated area and crude oil 
type is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP19JN14.005

    (d) ONRR will calculate the 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:
[GRAPHIC] [TIFF OMITTED] TP19JN14.006

    (1) For the first full production month after this rule is 
effective, ONRR will calculate the monthly Major Portion Prices using 
data reported on the Form ONRR-2014 for the previous 12 production 
months prior to the effective date of this rule (Previous Twelve 
Months). To the extent 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, ONNR will add the monthly Major Portion 
Prices calculated in paragraph (A) and divide by 12.
    (2) 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.
    (i) ONRR will use the oil sales volume reported by lessees on Form 
ONRR-2014 to monitor and, if necessary, to modify the LCTD used in the 
IBMP value.

[[Page 35117]]

    (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 +/-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 the 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 the Form ONRR-2014 fall within 
the +/-3 percent range. In Example 1, assume the IBMP value is $81.06 
and the LCTD for the designated area is 14.28%. In the table below, the 
Percent of Volume not as OINX reported is less than 22%, which triggers 
a modification to the LCTD. ONRR will adjust the LCTD upward by 10% 
(14.28% x 1.10). Therefore, for the next month the LCTD will be 15.71%. 
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% of 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 the 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 the Form ONRR-2014 fall within the +/-3 
percent range. In Example 2, assume the IBMP value is $81.06 and the 
LCTD is 14.28%. However, as noted in the table below, the Percent of 
Volume not reported as OINX is 32.69%, exceeding the 28% threshold, 
which triggers a modification to the LCTD. ONRR will adjust the LCTD 
downward by 10% (14.28% x 0.90). Therefore, for the next month the LCTD 
will be 12.85%. 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% of 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
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 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 30 CFR 1206.52 or 1206.53, you must 
increase those gross proceeds to the extent that the purchaser, or any 
other person, provides certain services that the seller normally would 
be responsible to perform 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 the lease under Sec.  
1206.52 or Sec.  1206.53, as

[[Page 35118]]

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 of this subpart. 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 you incur to transport oil under that 
contract. You have the burden of demonstrating that your contract is 
arm's-length.
    (2) Before you may take any deduction, you must submit a completed 
page one and Schedule 1 of Form ONRR-4110, Oil Transportation Allowance 
Report, under paragraph (b)(1) of this section. You may claim a 
transportation allowance retroactively for a period of not more than 3 
months prior to the first day of the month that you filed Form MMS-4110 
with ONRR, unless ONRR approves a longer period upon you showing good 
cause.
    (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, you may not take an allowance for the costs 
of transporting lease production which is not royalty-bearing without 
ONRR approval.
    (ii) Notwithstanding the requirements of paragraph (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 it is not consistent with the purposes of 
the regulations in this part.
    (5) If an arm's-length transportation contract includes both 
gaseous and liquid products, and the transportation costs attributable 
to each product cannot be determined from the contract, you must 
propose an allocation procedure to ONRR.
    (i) You may use the oil transportation allowance determined in 
accordance with its proposed allocation procedure until ONRR issues its 
determination on the acceptability of the cost allocation.
    (ii) You must submit to ONRR all available data to support your 
proposal.
    (iii) You must submit your initial proposal within 3 months after 
the last day of the month for which you request a transportation 
allowance, whichever is later (unless ONRR approves a longer period).
    (iv) ONRR will determine the oil transportation allowance based on 
your proposal and any additional information 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 
approval.
    (b) Reporting requirements. (1) With the exception of the 
transportation allowances specified in paragraph (b)(5) of this 
section, you must submit page one and Schedule 1 of the initial Form 
ONRR-4110, Oil Transportation Allowance Report, prior to, or at the 
same time as you report the transportation allowance you determined 
under an arm's-length contract on Form ONRR-2014, Report of Sales and 
Royalty Remittance. If ONRR receives your Form ONRR-4110 by the end of 
the month the Form ONRR-2014 is due, ONRR will consider it timely 
received.
    (2) Your initial Form ONRR-4110 is effective for a reporting period 
beginning the month you are first authorized to deduct a transportation 
allowance and will continue until the end of the calendar year, or 
until the applicable contract or rate terminates or is modified or 
amended, whichever is earlier.
    (3) After the initial reporting period and for succeeding reporting 
periods, you must submit page one and Schedule 1 of Form ONRR-4110 
within 3 months after the end of the calendar year, or after the 
applicable contract or rate terminates or is modified or amended, 
whichever is earlier, unless ONRR approves a longer period (during 
which period you must continue to use the allowance from the previous 
reporting period).
    (4) ONRR may require you to submit arm's-length transportation 
contracts, production agreements, operating

[[Page 35119]]

agreements, and related documents. You must submit documents within a 
reasonable time ONRR determines.
    (5) ONRR may establish, in appropriate circumstances, reporting 
requirements which 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.
    (2) Before you may take any estimated or actual deduction, you must 
submit a completed Form ONRR-4110 in its entirety under paragraph (b) 
of this section. You may claim a transportation allowance retroactively 
for a period of not more than 3 months prior to the first day of the 
month that you filed Form ONRR-4110 with ONRR, unless ONRR approves a 
longer period upon you showing good cause.
    (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 which 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 which 
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 of 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 approval. A change in ownership of a 
transportation system shall not alter the depreciation schedule the 
original transporter/lessee established for purposes of the allowance 
calculation. With or without a change in ownership, a transportation 
system shall 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 shall 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, you may not 
take an allowance for transporting lease production which is not 
royalty-bearing without ONRR approval.
    (ii) Notwithstanding the requirements of paragraph (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 it determines 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 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 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 (a)(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 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; and
    (B) The tariff significantly exceeds the lessee's actual costs for 
transportation as determined under this section.
    (b) Reporting requirements. (1) With the exception of those 
transportation allowances specified in paragraphs (b)(1)(v), 
(b)(1)(vii) and (b)(1)(viii) of this section, you must submit an 
initial Form ONRR-4110 prior to, or at the same time as, the 
transportation allowance you determine under a non-arm's-length 
contract or no-contract situation is reported on Form ONRR-

[[Page 35120]]

2014. If ONRR receives your Form ONRR-4110 by the end of the month the 
Form ONRR-2014 is due, ONRR will consider it timely received. You may 
base the initial report on estimated costs.
    (ii) Your initial Form ONRR-4110 is effective for a reporting 
period beginning the month you are first authorized to deduct a 
transportation allowance and will continue until the end of the 
calendar year, or until transportation under the non-arm's-length 
contract or the no-contract situation terminates, whichever is earlier.
    (iii) After the initial reporting period, you must submit a 
completed Form ONRR-4110 containing the actual costs for the previous 
reporting period. If oil transportation is continuing, you must include 
on Form ONRR-4110 your estimated costs for the next calendar year. You 
must estimate your oil transportation allowance based on the actual 
costs for the previous reporting period plus or minus any adjustments 
which are based on your knowledge of decreases or increases that will 
affect the allowance. ONRR must receive the Form ONRR-4110 within 3 
months after the end of the previous reporting period, unless ONRR 
approves a longer period (during which period you must continue to use 
the allowance from the previous reporting period).
    (iv) For new transportation facilities or arrangements, your 
initial Form ONRR-4110 must include estimates of the allowable oil 
transportation costs for the applicable period. You must base cost 
estimates on the most recently available operations data for the 
transportation system or, if such data are not available, you must use 
estimates based upon industry data for similar transportation systems.
    (v) Non-arm's-length contract or no-contract transportation 
allowances which are in effect at the time these regulations become 
effective are allowed to continue until such allowances terminate. For 
the purposes of this section, only those allowances ONRR has approved 
in writing qualify as being in effect at the time these regulations 
become effective.
    (vi) ONRR may require you to submit all data you used to prepare 
your Form ONRR-4110. You must submit the data within a reasonable 
period of time ONRR determines.
    (vii) ONRR may establish, in appropriate circumstances, reporting 
requirements which are different from the requirements of this section.
    (viii) 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).
    (3) ONRR may establish reporting dates for you that are different 
from those specified in this subpart to provide more effective 
administration. We will notify you of any change in your reporting 
period.
    (4) You must report transportation allowances as a separate entry 
on Form ONRR-2014 unless ONRR approves a different reporting procedure.
    (c) Notwithstanding any other provisions of this subpart, for other 
than arm's-length contracts, no cost shall be allowed for oil 
transportation which 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 shall 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.  1206.56 and Sec.  
1206.57 or Sec.  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 which 
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 
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 
first day of the first month you were authorized to deduct a 
transportation allowance to the date you repay the difference.
    (b) If the actual transportation allowance is greater than the 
amount 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 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 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); and
    (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; or
    (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:

[[Page 35121]]

    (i) Requests for guidance on hypothetical situations; and
    (ii) Matters that are the subject of pending litigation or 
administrative appeals.
    (c)(1) A value determination 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 the Assistant Secretary signs is the 
final action of the Department and is subject to judicial review under 
5 U.S.C. 701-706.
    (d) Guidance 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; or
    (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 of this subpart based on a quantity and/or 
quality that is different from the quantity and/or quality at the point 
of royalty settlement 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 you reported, including all 
adjustments for location, quality, and transportation; and
    (2) How you complied with these rules.
    (b) On request, you must make available sales, volume, and 
transportation data for production 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 I provide?

    (a) Certain information you or your affiliate submit(s) to ONRR 
regarding valuation of oil, including transportation allowances, may be 
exempt from disclosure.
    (b) To the extent applicable laws and regulations permit, ONRR will 
keep confidential any data 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. 2014-13967 Filed 6-18-14; 8:45 am]
BILLING CODE 4310-T2-P