[Federal Register Volume 73, Number 223 (Tuesday, November 18, 2008)]
[Rules and Regulations]
[Pages 69489-69517]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E8-26410]



[[Page 69489]]

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Part V





Department of the Interior





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Mineral Management Service



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30 CFR Parts 203 and 260



Royalty Relief--Ultra-Deep Gas Wells and Deep Gas Wells on Leases in 
the Gulf of Mexico; Extension of Royalty Relief Provisions to Leases 
Offshore of Alaska; Final Rule

Federal Register / Vol. 73, No. 223 / Tuesday, November 18, 2008 / 
Rules and Regulations

[[Page 69490]]


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DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Parts 203 and 260

[Docket ID MMS-OMM-2007-0071]
RIN 1010-AD33


Royalty Relief--Ultra-Deep Gas Wells and Deep Gas Wells on Leases 
in the Gulf of Mexico; Extension of Royalty Relief Provisions to Leases 
Offshore of Alaska

AGENCY: Minerals Management Service (MMS), Interior.

ACTION: Final rule.

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SUMMARY: This final rule amends existing deep gas royalty relief 
regulations to reflect statutory changes enacted in the Energy Policy 
Act of 2005. It provides additional royalty relief for certain ultra-
deep wells on Outer Continental Shelf leases in shallow water in the 
Gulf of Mexico. It extends both the existing and the additional deep 
gas royalty relief to Outer Continental Shelf leases in deeper water 
than before. Finally, this final rule applies discretionary royalty 
relief procedures that have been used by deepwater leases in the Gulf 
of Mexico to leases offshore of Alaska.

EFFECTIVE DATES: This final rule becomes effective December 18, 2008.

FOR FURTHER INFORMATION CONTACT: Marshall Rose, Chief, Economics 
Division, at (703) 787-1538.

SUPPLEMENTARY INFORMATION:

A. Background

    On May 18, 2007, MMS published a proposed rule in the Federal 
Register (72 FR 28396) to implement Sections 344 and 346 of the Energy 
Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594, 702 (codified at 
42 U.S.C. 15904). This final rule is substantially the same as the 
proposed rule except for fixing price thresholds used with application-
based royalty relief for leases offshore Alaska and for newer deepwater 
leases in the Gulf of Mexico (GOM), and the ability of operators to 
temporarily remove drilling rigs in certain cases without forfeiting 
the original well status of deep wells. Minor editorial or clarifying 
language changes were also made. The statutorily-mandated royalty 
relief provisions in this final rule for deep gas wells in the GOM 
supplement royalty relief that MMS previously included in 30 CFR 
203.40-203.48, hereafter referred to as the existing regulations.
    Under the existing regulations, MMS offered a temporary royalty 
relief incentive for deep gas production from GOM leases in less than 
200 meters of water that lie wholly west of 87 degrees, 30 minutes West 
longitude for wells spudded since March 26, 2003.
    The incentive in the existing regulations consists of a royalty 
suspension volume (RSV) for the first qualifying well on a lease for 
two basic categories of deep gas production: (1) 15 billion cubic feet 
(BCF) of RSV for a qualifying well with a perforated interval the top 
of which is between 15,000 and 18,000 feet true vertical depth subsea 
(TVD SS); or (2) 25 BCF of RSV for a qualifying well completed at least 
18,000 feet TVD SS. The existing regulations provide lesser amounts of 
royalty relief for a deep sidetrack, for a subsequent deeper well on 
the lease, and for drilling an unsuccessful deep well. All qualified 
deep wells on the lease that begin production before May 3, 2009, may 
use the relief provided in the existing regulations, but only for 
production that occurs during years when the average price of natural 
gas on the New York Mercantile Exchange (NYMEX) does not exceed the 
price threshold of $10.15 per million British thermal units (MMBtu), 
expressed in 2007 dollars.
    The supplemental incentive added by this final rule implementing 
section 344 of the Energy Policy Act is an RSV of 35 BCF for a third 
well depth category--an ultra-deep well (defined in section 
344(a)(3)(A) as wells with a perforated interval the top of which is at 
least 20,000 feet TVD SS). The final rule provides that this ultra-deep 
well incentive has no expiration date, applies only if the lease has no 
prior deep well production, and is subject to a price threshold of 
$4.55 per MMBtu, expressed in 2007 dollars.
    Also, this final rule provides the same incentive for gas produced 
from a deep well on leases in waters 200 meters or deeper but less than 
400 meters deep as the existing regulation provides on leases in less 
than 200 meters of water, with 2 exceptions:
    1. The incentive in 200 to less than 400 meters of water applies to 
qualified deep wells spudded on or after May 18, 2007, rather than 
March 26, 2003, and that begin production before May 3, 2013, rather 
than before May 3, 2009; and
    2. The royalty relief in 200 to 400 meters of water applies to 
production from qualified wells occurring in years when the average 
NYMEX natural gas price does not exceed a price threshold of $4.55 per 
MMBTU, rather than $10.15 per MMBTU, expressed in 2007 dollars.
    Finally, to implement section 346 of the Energy Policy Act, this 
final rule utilizes established royalty relief application and 
evaluation procedures found under Sec. Sec.  203.60 through 203.80 for 
any lease offshore Alaska that seeks royalty relief before production 
on the lease begins. These case-by-case procedures for seeking royalty 
relief are the same as can be used by a deepwater lease in the GOM that 
was issued before the Deep Water Royalty Relief Act of 1995 (DWRRA) or 
after 2000. Prior to this rulemaking, the pre-production royalty relief 
procedures in Sec. Sec.  203.60-203.80 did not apply to leases offshore 
Alaska. Consistent with section 346 of the Energy Policy Act of 2005, 
the current rulemaking addresses that omission.

B. Comments Leading to Rule Modifications

    Eight respondents submitted comments on the proposed rule. Separate 
letters from Chevron and from the American Petroleum Institute (API), 
as well as a joint letter from six oil and gas industry associations 
(National Ocean Industries Association (NOIA), Independent Petroleum 
Association of America, U.S. Oil & Gas Association, International 
Association of Drilling Contractors, American Exploration and 
Production Council, and Natural Gas Supply Association) expressed 
concerns mostly about various restrictions in the proposed deep and 
ultra-deep well provisions. A joint letter from five environmental 
organizations (Northern Alaska Environmental Center (NAEC), Alaska 
Wilderness League, Natural Resources Defense Council, Pacific 
Environment, and Resisting Environmental Destruction on Indigenous 
Lands) and a separate letter from a representative of another 
environmental organization (Defenders of Wildlife (DoW)) raised a 
variety of concerns about royalty relief mostly for leases offshore 
Alaska. A letter from a private citizen (T. Tupper) critiqued some 
processes and assumptions included in the proposed rule. Finally, a 
letter from an energy consuming industry organization (Industrial 
Energy Consumers of America) expressed general support for the added 
domestic production incentive, while a letter from another private 
citizen (K. Sellers) voiced general opposition to royalty relief. 
Copies of all the comments we received are available on our Web site 
at: http://www.mms.gov/federalregister/PublicComments/AD33.htm.
    In response to these comments, the final rule substantively changes 
one provision of the proposed rule. Also, we have clarified some text 
in the regulations in response to about one-third of the items on a 
detailed list in the API comments. Further, we have

[[Page 69491]]

reorganized parts of the rule by moving provisions from some sections 
to other sections where they are more appropriately located. These 
moves do not alter the meaning of the provisions. Finally, we have 
updated the various base price threshold values from 2006 dollars to 
2007 dollars.
    The proposed rule explained how the applicable base price 
thresholds would be determined in the case of a lease offshore Alaska 
that applies and qualifies for pre-production royalty relief. For a 
lease issued with royalty relief and price thresholds, those same price 
thresholds would apply to any additional discretionary relief awarded 
on a case-by-case basis through the provisions of the proposed rule. 
For a lease issued without royalty relief and price thresholds, the 
base price threshold terms in the DWRRA would apply to all royalty 
relief awarded.
    Given the comments received on the proposed rule and further review 
of our process for evaluating pre-production royalty relief 
applications, we add flexibility to the price thresholds prescribed in 
the regulation for leases both offshore Alaska and those in deep water 
in the GOM issued after 2000. We do this by providing the authority to 
grant an exception to the price thresholds fixed in Sec.  203.78 in 
cases where we find a project would not be economic without royalty 
relief subject to price thresholds above those fixed in the rule. Our 
process for determining whether development (pre-production) projects 
or expansion projects need relief requires use of future oil and gas 
price paths that we specify so as to insure that current oil and gas 
price expectations are impartially reflected in the evaluation. Should 
an applicant demonstrate that even at this price path, royalty relief 
is necessary to transform development of a discovery from an uneconomic 
to an economic proposition, we may decide that production of the 
resource with a higher royalty relief price threshold is preferable to 
stranding the resource.
    This exception recognizes that, in many cases, generic price 
thresholds established in lease terms or for a general category of 
leases (e.g., all those leases eligible for deep gas or deepwater 
royalty relief) may be set conservatively to avoid providing excessive 
relief, since the relief to which the thresholds apply inevitably turns 
out to be unnecessary for many of those that use it. In those cases, a 
more parsimonious price threshold properly limits the size of the 
forgone royalty from those leases that would have been explored and 
developed without royalty relief. However, it may not be the proper 
price threshold in specific cases where the individual applicant can 
demonstrate convincingly that royalty relief is the difference between 
a prospective profit and loss situation, and thus this relief would 
directly affect the lessee's decision between development and 
abandonment of a discovery. In such cases, there is less concern about 
forgone royalties because it would be presumed that no royalties would 
be collected without the production that results from providing some 
initial royalty relief.
    We intend to select the price threshold in the case of an exception 
using the same criteria we do for determining the size of the RSV. That 
is, we set or raise the oil and gas price thresholds, like we set or 
raise the RSV, only enough to make development economic on the lease, 
unit or project that has applied and qualified for royalty relief.
    This change responds to comments from both NOIA, et al., and NAEC, 
et al. The concern expressed by NOIA, et al., was that the proposed 
implementation of section 346 ``stopped in its tracks'' an initial 
positive reaction to that incentive. While the comment went on to 
request a step not authorized by the statute, that ultra-deep gas 
relief be applied to Alaska, it did cause us to look at other 
ramifications of the provisions applied to Alaska. The proposed base 
price threshold for certain older leases in Alaska has a greater chance 
of being exceeded than is the case for the actual price threshold 
included in newer leases offshore Alaska. These older leases have no 
royalty relief in their lease terms and so would have been subject, 
under the proposed rule, to the DWRRA threshold for any newly approved 
royalty relief. The intent of the proposed rule's provision to 
implement section 346 was to provide added flexibility to consider, on 
a case-by-case basis, additional royalty relief for projects that may 
otherwise prove uneconomic to develop. However, strictly applying the 
base price threshold to any such relief granted under this provision 
could have the unintended effect of negating that relief if the project 
would remain uneconomic at prices above the threshold. The flexibility 
added by the final rule provision allows for the possibility to apply a 
different price threshold to relief granted on a case-by-case basis, 
consistent with the specific circumstances of the project being granted 
relief.
    Further, we observed only a small response to the original deep gas 
relief in the GOM, which justifies a lower, more restrictive price 
threshold there to avoid providing excessive royalty relief on 
production that would occur without that relief. In contrast, the 
meager Outer Continental Shelf (OCS) production history in Alaska does 
not provide the same justification for a lower, more restrictive price 
threshold.
    As part of this reconsideration of the Alaska price threshold, we 
discovered a modification we needed but neglected to propose in Sec.  
203.80. That modification authorizes case-by-case applications before 
production starts for royalty relief in special cases that fall outside 
our established categorical or formal application-based royalty relief 
programs from leases offshore Alaska, as well as from leases located 
wholly west of 87 degrees 30 minutes West longitude in the GOM. This 
special case royalty relief is available to all leases on the OCS after 
production begins. Section 346 of the Energy Policy Act of 2005 added 
leases offshore Alaska to the subset of OCS leases that may seek 
royalty relief before production begins. Along with this modification, 
we clarify that our formal royalty relief programs include both the 
size of the relief (e.g., RSV) we may grant and the conditions (e.g., 
price threshold) we may impose on use of that relief.
    The API provided an extensive list of suggested text clarifications 
to improve readability and comprehension of the terms under which this 
royalty relief is available. We have adopted many of those 
clarifications. Clarifying rule text has been added to: (1) Sec.  203.0 
definitions for certified unsuccessful well and ultra-deep short 
sidetrack; (2) to Sec.  203.2; (3) to section lists at the beginning of 
the new and revised deep gas and ultra-deep gas sections in subpart B; 
and (4) to Sec. Sec.  203.33 and 203.43. Also, we have expanded the 
explanations in the examples in Sec. Sec.  203.31, 203.36, 203.41, and 
203.43(a) to include not only what the answer is but also why that 
answer results from the regulation. The API also suggested wording 
changes in the rule to implement some conceptual changes they favor. 
Discussion at the end of the next section explains why we did not make 
these conceptual changes.
    During review of the comments on the proposed rule, we discovered a 
needed technical correction to an existing definition. This technical 
correction allows temporary removal of a drill rig due to weather 
(e.g., hurricane) or safety (e.g., unexpected pressure) concerns 
without sacrificing the well's status as an original well. Provided 
that drilling resumes within 1 year after drilling was halted due to a 
weather or safety hazard which we agree justified removing the rig, we 
will still consider the well an

[[Page 69492]]

original well for purposes of royalty relief. The sunset dates in the 
qualified deep and ultra-deep well definition are still applicable in 
this situation. We do this to avoid creating a moral hazard of 
encouraging continued operation with a rig that has been or may be 
damaged by weather or is unsafe to use with newly revealed geologic 
conditions for the sake of preserving access to royalty relief. When we 
are encouraging operators with royalty relief to take a chance in 
untested horizons and areas, we do not want to penalize prudent 
operation. This flexibility is more important in the case of ultra-deep 
wells where the change in a well's designation from original well to 
sidetrack loses all royalty relief.
    Finally, we moved provisions appearing in the proposed rule in 
Sec.  203.31(c) and Sec.  203.41(d) that describe how to apply the RSV 
to Sec.  203.33(a) and Sec.  203.43(a), respectively, where other 
provisions concerning the application of an RSV appear. Also, we 
rearranged the provisions appearing in Sec.  203.35 to match the 
chronological order in which these administrative actions that secure 
the RSV should occur, and clarified requirements for an extension of 
the deadline for beginning production in both Sec. Sec.  203.35 and 
203.44. These changes do not alter the substance of any of the moved 
provisions.

C. Comments Not Leading to Rule Modifications

    The following discussion is arranged into 10 issue topics for 
purposes of organizing responses to comments for which no changes in 
the rule were made. The oil and gas industry letters generally objected 
to 3 parts of the proposed rule: (1) The price threshold level, (2) a 
sunset for royalty relief in the 200 to 400 meter water depth, and (3) 
the ability of only the first deep or ultra-deep well on a lease to 
earn the RSV. Both the industry and environmental representatives 
submitted comments on (4) the fiscal cost of the proposed rule. The 
letters from the environmental organizations also expressed concerns 
about: (5) the propriety of any royalty relief in Alaska, (6) the 
analysis accompanying this rule, and (7) the competence of MMS to 
administer royalty relief provisions. The substantive private citizen 
letter pointed out possible problems with: (8) price thresholds in 
connection with royalty in-kind, (9) the rule's information collection 
provisions, and (10) estimates of the size of the incentive's effect. 
The next section reviews and responds to the particular comments in 
each of these categories, as well as the detailed API recommendations 
not adopted.
    1. Price Threshold Level: Industry comments on this issue ranged 
from statements that the proposed price threshold level is too low, 
that the threshold should be consistent with the one in the existing 
regulation, that it ought to be even higher than the threshold in the 
existing regulation, or that setting an appropriate threshold should 
have no connection to the lack of a sunset date.
    The most direct criticism about this issue is reflected in the 
following quote from Chevron.

    MMS's proposed price threshold of $4.47 per MMBTU is too low and 
will have the effect of nullifying the stipulated royalty relief 
incentive * * * the new deep gas royalty relief incentives [will be 
given] little or no value in making lease acquisition and drilling 
decisions. The effect of establishing a low price threshold in the 
proposed rule circumvents Section 344's purpose.

    The MMS considered but declined to set a higher price threshold for 
several reasons. In general, high gas prices provide all the incentive 
needed for additional production. Moreover, Congress established this 
gas price threshold for a previous royalty relief program that it 
mandated for pre-existing deepwater leases in the GOM (DWRRA), albeit 
when market prices were much lower than now. Given the discretion 
afforded the Secretary of the Department of the Interior by Congress to 
engage in this rulemaking, MMS has decided to adopt that previous gas 
price threshold, concluding that an across-the-board royalty incentive 
is not necessary inasmuch as current prices are far above historic 
levels. We note, however, that we believe this new royalty relief 
provision still has value as a cushion against a possible gas price 
collapse after drilling decisions have been made.
    A variation of this criticism of the proposed level of the gas 
price threshold is the recommendation to use the same price threshold 
as set in the existing deep gas regulation:

    * * * our recommendation is that at minimum the existing rule's 
$9.88 per MMBTU base price threshold (adjusted over time for 
inflation) be adopted as the applicable price limitation (API).

    This argument for consistency is not compelling. The high price 
threshold in the existing program was adopted in connection with a 
fixed sunset date, a feature not included in the statute in connection 
with the ultra-deep well incentive, the most significant part of the 
new program. Indeed, the existing deep gas incentive will begin to 
phase out in less than a year. Further, technological capabilities have 
improved and price-cost margins have increased since the existing 
regulation was issued. Finally, the lower price threshold coincides 
with the gas price threshold level set for deepwater leases MMS issued 
from 2002 to 2004 and since 2007. As such, this level of gas price 
threshold applies to the large and growing number of deepwater leases 
issued under that incentive. A deep gas price threshold that matches 
one used in deepwater will mitigate inconsistency between the deep gas 
and deepwater relief programs. The enhanced consistency of incentive 
terms across different leases will reduce confusion in the long run 
after the existing deep gas program has expired and will reduce the 
distortion in lease development decisions associated with different 
likelihoods of realizing royalty relief. Use of this same price 
threshold for the new ultra-deep gas drilling incentive thereby 
improves consistency of market terms for gas produced under both of the 
major long term OCS royalty relief programs that have gas price 
thresholds.
    Related comments advocated an even higher price threshold.

    The price threshold of $4.47/MMBtu * * * is substantially less 
than the price threshold applicable to royalty suspension volumes 
under the existing rule * * * rather than raising the threshold to 
respond to the fact that it costs more for companies to make the 
investment into these frontier areas than it did before, the MMS has 
instead gone in the opposite direction by proposing an extremely low 
threshold (NOIA, et al.).
    MMS further justifies the lower price threshold based on the 
lack of response to deep gas relief to date. The current relief, 
with a $9.88/mmbtu price threshold, did not result in significant 
deep drilling because of the high cost and technical risk associated 
with drilling at these depths. The historical lack of response under 
the $9.88/mmbtu [threshold] logically argues that an even higher 
price threshold than $9.88/mmbtu may be necessary to entice lessees 
to take on the financial and technical risks of ultra-deep drilling 
(API).

    These arguments are not persuasive. The commenters did not provide 
evidence that drilling costs for ultra-deep wells have gone up as much 
or more than the price of natural gas. Further, relating price 
thresholds, under which royalty relief is realized, to cost indexes 
would tend to reduce normal incentives to resist or avoid increases in 
drilling costs. Also, matching price thresholds to market conditions 
would increase the amount of royalty relief or, in other words, the 
subsidy or transfer from taxpayers to industry at the same time that 
industry's profits are rising. Finally, the higher price threshold did 
not cause the lack of response to the

[[Page 69493]]

existing deep gas relief. On the contrary, because it was not exceeded 
and probably not expected to be exceeded, it allowed the full 
enticement effect of the incentive to occur--yet the incremental 
drilling results have been small.
    A final price threshold issue concerned its connection to a sunset 
date.

    MMS justifies the lower price threshold level based on the lack 
of a sunset provision. The lack of a sunset provision for ultra-deep 
drilling is necessary given the immense technical challenge posed by 
these wells. The need to develop experience and technology will 
require long lead times, making a sunset provision impractical. The 
lack of a sunset provision is appropriate for ultra-deep wells and 
is not a sound reason for a lower price threshold (API).
    The price thresholds must be set through economic modeling to 
establish the price at which lessees no longer need an incentive to 
drill deep or ultra-deep gas wells. Frustration over the ability to 
establish a sunset for royalty relief hardly meets that standard and 
is simply further evidence that, through this proposed rule, the MMS 
is seeking to undermine Congress' intent to provide new incentives 
for deep and ultra-deep gas production (NOIA, et al.).

    In fact, the statutory silence with respect to a sunset date 
restricts policy flexibility. A sunset would have allowed for automatic 
ending of a policy, such as was implemented in the existing deep gas 
incentive regulations, in which a price threshold in conjunction with 
other program elements beforehand appeared in step with market 
conditions but then performed poorly. Congress chose, in section 344 of 
the statute, to set no sunset; but by authorizing the Secretary to 
limit relief based on market prices, it did impose the responsibility 
on the Secretary of containing the loss from a policy that has been 
considerably less effective than anticipated. The price threshold is 
the only instrument the Secretary has to perform the important task of 
potentially saving taxpayers hundreds-of-millions of dollars in forgone 
royalties to lessees with deep gas wells that would have been drilled 
even without the incentive. Further, long term gas price forecasts 
change over time, so it is not possible to fix a single optimum gas 
price threshold for the entire period over which gas may be produced 
under the ultra-deep gas incentive. If we retained the ability to 
adjust the price threshold as conditions warrant, we would add 
uncertainty that undermines the ability of companies to make the long 
term plans necessary to develop challenging prospects. Therefore, we 
judge selection of a fixed, if conservative, price threshold that 
balances an added incentive for ultra-deep drilling with fiscal 
prudence over the long term to be the best price threshold policy in 
the absence of a sunset provision and a weak response to existing 
incentives.
    2. Sunset date in 200 to 400 meters: This issue received 
recommendations that a sunset is not required by the statute; that a 
sunset contravenes the statute; and that, if necessary, a rolling 
sunset date should be used.
    One objector to a sunset provision appealed for a less rigorous 
interpretation of the statute.

    * * * MMS has chosen to adopt the sunset concept in the new 
implementing proposed royalty relief regulations for 200 to 400 
meter water depth to match the current regulations. While adopting 
the existing regulations is mandated by Congress, a reasonable 
person could interpret * * * that the Secretary should use the 
current methodology in determining well depth and completion 
interval restriction along with relief volume factors as complying 
with the intent of Congress. The time limitation is not stipulated * 
* * an argument could be made that the time limitation in the 
current regulations is not a part of the ``methodology'' the 
Secretary must use in implementing the application of the existing 
regulations to leases issued in water depths from 200 to 400 meters 
(API).

Nevertheless, we consider the sunset to be an essential part of the 
methodology because it affects the nature of the appropriate relief 
terms. The sunset forecloses an indefinite duration for what might turn 
out to be an ineffective or even wasteful policy. Under that 
protection, the size and breadth (e.g., relief for unsuccessful wells, 
sidetracks, and subsequent deep wells) of the incentive can be made 
more enticing than otherwise.
    Another objector suggested:

    * * * the MMS's proposed May 3, 2013 sunset provision * * * also 
contravenes Section 344's purpose of encouraging deep gas 
production. Because of the complexity and expense involved in deep 
gas exploration, especially where acquisition of new leases is 
involved, in many cases it will likely take lessees many years to 
bring new deep gas wells to production. * * * the cost reduction 
incentive Congress created * * * is negated * * * (Chevron).

The fairly short sunset provision is intended to reward expedited 
development of deep gas production from this most quickly accessible 
alternative. Longer term, alternative sources of natural gas such as 
deepwater fields, LNG imports, and Alaskan reserves have time to 
develop and reduce the burden on supplies from shallow water leases.
    As with the price threshold, commenters recommended a flexible 
alternative if sunset dates must be used.

    * * * we recommend MMS reconsider implementation of the sunset 
provision by either eliminating it or tying the sunset provision to 
the commencement of production from a qualifying well. Instead of a 
specific sunset date (i.e., May 3, 2013) MMS could use five (5) 
years from the date operations on a qualifying well are completed 
(API).

    Yet, while a floating date, such as 5 years after operations on a 
qualifying well are completed, may facilitate installation of 
infrastructure and arrangement of transportation, the starting event is 
too vague a standard to enforce effectively and efficiently. More 
importantly, this rolling sunset still leaves an endless program 
cessation date. Not only is such a formulation likely to be very costly 
in terms of forgone revenues, but it frustrates the original intent of 
deep gas royalty relief--to accelerate deep depth drilling.
    3. Relief for only the first ultra-deep well on a lease: This 
provision elicited comments about its rationale, the legitimacy for the 
limits it creates, and the chance that the new rule could provide less 
relief for a qualified well than would have the existing rule.
    One objection to this provision urged a departure from the logic of 
the existing incentive.

    MMS has failed to provide any rationale for its decision to deny 
granting 35 BCF of royalty relief for a second well on a lease. The 
agency has chosen instead to unilaterally and arbitrarily thwart 
Congress' expressed intent to incentivize [sic] ultra-deep 
production by denying royalty relief for ultra-deep wells on leases 
with existing deep wells or ultra-deep wells regardless of the 
situation that exists on the lease (NOIA, et al.).
    The rule fails to explain why the existence of a reservoir at 
15,000 feet in any way reduces the cost or risk of drilling an 
ultra-deep well with a target depth of 22,000 feet. Similarly, the 
rule does not explain why an ultra-deep well producing from a 
reservoir on the east side of a lease reduces the cost or risk of 
drilling an ultra-deep well to produce from a different reservoir on 
the west side of the lease (NOIA, et al.).

    This charge fails to acknowledge that the proposed rule continued 
the same principle found in the existing deep gas relief rule of 
granting less or no relief to subsequent deep wells on the same lease. 
The rationale for this principle is that the first deep well on a lease 
reduces risk by establishing that hydrocarbons exist and are producible 
from deep depths from the geology found within the relatively small 
area covered by the lease. Also, production from the first deep well on 
the lease reduces the cost for subsequent deep wells by financing the 
acquisition and installation of any necessary production and 
transportation infrastructure for

[[Page 69494]]

deep production in the vicinity of the subsequent well.
    Related comments suggest that the rule is more restrictive than it 
actually is:

    Limiting royalty relief to `ultra deep' wells that are the first 
deep gas wells to produce on a lease, however, flouts Section 344's 
intent by arbitrarily eliminating the cost reduction incentive of 
royalty relief for an `ultra deep' well that merely happens not to 
be the first deep gas well to produce on the lease. * * * we 
recommend MMS not limit royalty relief to `ultra deep' gas wells 
that are the first wells to produce on a lease, but rather allow 
relief to be applied to new deep gas wells whenever they are drilled 
on a lease after implementation of the rule (Chevron).

    The proposed rule departed from the structure of the existing rule 
only where the statute provided no other reasonable choice. As the 
proposed rule explains, language in the statute requires an all-or-none 
choice, i.e., granting either full relief or no relief to sidetracks 
and subsequent ultra-deep wells. The MMS chose not to double or more 
the size of relief for a short sidetrack or for a second well on the 
lease just because it happens to be an ultra-deep well. Moreover, the 
commenter's argument ignores the fact that the additional incentive 
will apply to other qualified wells on the lease. The first deep or 
ultra-deep well on a lease earns a royalty suspension volume for the 
lease. If the first deep well is an ultra-deep well, it earns a larger 
royalty suspension volume than under the existing rule, as directed by 
Congress. Subsequent deep or ultra-deep wells and shorter sidetracks to 
deep depths on the lease share that larger relief. Moreover, the 
decision on the second ultra-deep well is not arbitrary because it 
follows the pattern of the existing rule. The second well benefits from 
the presence of the first deep producing well on the lease, and 
therefore, needs less incentive.
    Another comment highlights a quirk resulting from our cautious 
approach to the all-or-none choice created by the statutory language:

    The proposed rule would in many cases provide less royalty 
relief than is currently available under the existing rules. The 
rule would result in wells drilled at greater depths earning the 
same or less of an incentive or no incentive at all. Additionally, 
the rule would lead to wells drilled between 200 and 400 meters 
possibly earning less of an incentive than wells drilled in less 
than 200 meters. Under the existing rule, a lessee with an existing 
well drilled to a depth of 15,000 feet would receive an additional 
10 BCF of suspension volume for an ultra-deep well drilled on the 
lease. However, under the proposed rule, for most leases, the lessee 
will receive no additional royalty suspension volume for drilling a 
second, ultra-deep well on a lease that already has a well drilled 
to 15,000 feet (NOIA, et al.).

    While technically possible, experience indicates that few if any 
actual cases will result in a well earning less royalty relief under 
this rule than under the existing rule. For that peculiar situation to 
occur, an ultra-deep well would have to be spudded on or after May 18, 
2007, and put into production on a lease that already has a well 
producing from at least 15,000 feet deep. Further, this event must 
occur on a lease partly or entirely in less than 200 meters of water 
during the slightly less than 2 years before the expiration of the 
incentives under the existing deep gas rule on May 3, 2009. The MMS 
records indicate that only 2 leases have met those conditions during 
the 4 years after the existing incentive became available on March 26, 
2008.
    For an ultra-deep well to earn a smaller amount of relief than a 
deep well completed at a lesser depth (18,000 to 20,000 feet) on a 
lease, both the ultra-deep and less deep wells would have to be spudded 
after May 17, 2007, and put into production on a lease that already has 
a well producing from at least 15,000 feet deep. The MMS records show 
no case, during the first 4 years after the existing incentive became 
available, of a well between 18,000 and 20,000 feet deep that was 
spudded and began production on a lease with a producing well at least 
15,000 feet deep. On leases partly or entirely in less than 200 meters 
of water, this unprecedented event must occur during the slightly less 
than 2 years between issuance of the proposed rule on May 18, 2007, and 
prior to expiration of the incentives under the existing deep gas rule 
on May 3, 2009. On leases in 200 to 400 meters of water, both wells 
must be spudded and put into production during a longer period, from 
May 18, 2007 and before May 3, 2013. However, since the 200 to 400 
meter water depth interval contains only about 6 percent of the number 
of active leases as does the 0 to 200 meter water depth interval, the 
chances of this event occurring in the deeper water interval appear 
even lower than in the shallower water depth interval.
    A very limited number of non-symmetric cases could occur across 
water depth categories. Leases in 200 to 400 meters of water became 
eligible on May 18, 2007, to earn the same amount of relief for 
drilling a deep or ultra-deep well, as would a lease in less than 200 
meters of water, with one exception. The exception applies to leases in 
partly or entirely less than 200 meters of water and issued during 2004 
and 2005. These leases have deep gas royalty relief terms from the 
existing rule explicitly stated in their lease instruments. To earn 
relief that a lease in 200 to 400 meters of water could not, the 
exception lease located in 200 meters of water or less and issued in 
2004 or 2005 would have to have production from a well at least 15,000 
feet deep and then start production from an ultra-deep well, all within 
the abbreviated period prior to May 3, 2009.
    A final criticism in this vein is that it is possible for an ultra-
deep well to earn less relief than a deep well completed to a lesser 
depth:

    In the few instances where the proposed rule would provide an 
incentive for a deep sidetrack or second well on a lease, the 
proposed rule is still nonsensical. As an example, if a company 
drilled a well to 15,000 feet under the old rule and received a 
suspension volume of 15 BCF, and then drilled a new well under this 
rule to 18,000 feet, the company would receive an additional 10 BCF. 
However, if that same company drilled a new well that was deeper, to 
20,000 feet, it would not get the additional 10 BCF, but instead 
would get no suspension volume at all for that well. Hence, the rule 
is actually a disincentive to drill to deeper depths. This 
interpretation of the statute runs counter to the will of Congress 
(NOIA, et al.).

    As already noted, this particular circumstance has not yet happened 
over a period twice as long as remains for it to happen. Regardless, 
the proposed rule is not a disincentive to drill to deeper depths. It 
provides the full 35 BCF directed by Congress for an ultra-deep well if 
the drilling activity pioneers production on the lease at deep depth 
with its unique temperature, pressure, and corrosion conditions. If the 
ultra-deep well is a subsequent deep well or a short sidetrack, the 
proposed rule provides no additional relief, but the second or 
sidetrack ultra-deep well still share any remaining relief available to 
the lease. The problem is that the statutory language dictates this 
all-or-none situation by precluding the opportunity to provide relief 
at a reduced level that is more appropriate for a subsequent ultra-deep 
well or short sidetrack. Thus, while our rule could have avoided this 
odd and unlikely situation, the statute would have forced adoption of a 
much less defensible policy position resulting in the granting of far 
greater royalty relief than would be warranted.
    4. Fiscal costs of the relief: This issue drew opposing comments 
about the loss of Government revenue due to the royalty relief in this 
rule.
    One of the industry comments conveys a false impression that 
categorical or ``incentive based'' royalty relief may be costless to 
taxpayers:


[[Page 69495]]


    Under the `need' based relief program, lessees must prove that 
their oil and natural gas related projects require some form of 
royalty reduction or suspension to make their project economic. * * 
* `Incentive' based royalty relief has the purpose of enticing 
potential lessees to invest in oil and natural gas projects knowing 
additional financial benefit could be derived should a commercial 
discovery be made and subsequently oil and/or gas produced. * * * 
Considering the fact that most leases issued are not drilled, the 
Federal Government collected significant revenue in the form of 
bonuses and rentals from these new leases, some of which would 
probably not have been leased without royalty relief. * * * Congress 
recognizes the benefits associated with `incentive' based royalty 
relief programs by its passage of EPACT [the Energy Policy Act of 
2005] (API).

    However, categorical royalty relief results in forgone royalty, 
from deep wells that would have been drilled and produced even without 
the royalty relief. Thus, such royalty relief is unlikely to be a net 
revenue generating program for the Federal Government when applied to 
already existing leases that have no more bonus bid to pay. For new 
leases, relief largely serves to speed-up leasing by suspending 
royalties that would have been collected later when the lease would 
likely be sold after the emergence of better technology, higher prices, 
or lower costs. Moreover, even though higher bonuses would be expected 
in the presence of royalty suspensions, we note that bid premiums 
associated with the categorical relief provided to DWRRA leases proved 
to be modest at best.
    Comments by environmental groups on our proposal to apply 
discretionary, need based royalty relief procedures in Alaska indicated 
concern about the high fiscal or administrative costs of such a 
program:

    * * * MMS needs to ensure that it has adequately scrutinized all 
of the regulation's effects to the public interest both in 
protecting the environment of the OCS and adjacent coastal 
environment, and to ensure that the public yields [receives] a fair 
price for the exploitation of the oil and natural gas resources from 
federal OCS waters. * * * Please provide the analysis used to 
determine that there would be `no negative effect on federal 
revenue' from this rulemaking. If there is royalty relief granted, 
those revenues will not come to the federal treasury. * * * 
Certainly, if MMS must respond to requests for relief for an 
additional vast area in Alaska encompassed by four different 
planning areas (at this time), and then must audit and account for 
the relief granted, it is illogical to assume that MMS will not face 
costs in implementing this section, and that there would be no 
economic effect. * * * Would this royalty relief for the Alaska OCS 
have any implications for revenue distribution from leases in the 
8(g) zone? These were not addressed by your proposal (NAEC, et al.).

    This rule proposes to apply a royalty relief process to offshore 
Alaska leases that is specifically designed to avoid unnecessary 
royalty relief. Projects that are forecast to be profitable paying full 
royalty would not get relief, while those not anticipated to be 
profitable while paying full royalty are unlikely to proceed to 
development and production unless some modifications to royalty terms 
are made. Projects that do not go into production generate no royalty 
revenue for the Federal treasury. With royalty relief, production in 
excess of the suspension volume will generate royalty revenue on such 
projects. Thus, we do not expect negative effects on Federal revenue 
from our discretionary case-by-case royalty relief program in Alaska.
    While MMS may face administrative costs, no net program costs 
should result since relief applications carry a user-fee designed to 
cover the cost of review. The MMS determines how much royalty relief, 
if any, would be needed and would provide only the amount of royalty 
suspension needed to change an anticipated decision not to develop. Any 
production beyond that suspension amount promises royalty receipts that 
would not have materialized otherwise. Finally, the rule will not 
adversely affect expected section 8(g) revenues, since the process for 
approving royalty relief seeks to ensure that any production occurring 
under royalty relief would not have occurred without that relief. Thus, 
we do not anticipate that any royalty revenues, including those subject 
to section 8(g), would be lost as a result of this program.
    5. Propriety of Royalty Relief in Alaska: Comments on this issue 
question how and even whether royalty relief should be offered in 
Alaska.
    One sentiment seems to underlie many of the comments from both 
environmental organizations:

    Royalty relief is not appropriate for application in Alaskan 
waters, and the proposed rule provides no adequate description of 
the proposed scenario for the discretionary application of royalty 
relief within Alaska OCS Planning Areas: The Federal Register Notice 
for RIN 1010-AD33 * * * includes virtually no detailed discussion of 
how, where, and under what circumstances Secretarial Discretion will 
be applied to expand royalty relief into Alaskan waters. * * * It is 
therefore premature * * * for MMS to be prescribing terms and 
conditions for royalty relief in these regions (DoW).

    This and several related comments reflect confusion about what the 
proposed rule adds to existing royalty relief for leases offshore 
Alaska. As it happens, most offshore Alaska leases already have 
categorical royalty relief under the terms with which they were 
originally issued. Section 346 of the Energy Policy Act of 2005 gives 
the owners of other offshore Alaska leases a chance to request relief 
but MMS will grant relief only on a demonstrated economic need basis. 
Further, the royalty relief covered by these regulations has been 
available to offshore Alaska leases since the statute was enacted in 
2005. This rule cannot change that fact, but it can and does establish 
a standardized process for the lessee of a lease offshore Alaska to 
follow in submitting a complete application for relief. It also 
explains how MMS will evaluate whether that application would result in 
approval of some royalty relief.
    Related comments do not take into account the existing rigorous 
qualifying procedures set forth in regulations starting at 30 CFR 
203.60 that more fully define the relief process being applied to 
Alaska by this rule:

    MMS procedures for granting Alaska OCS royalty relief appear to 
be arbitrary and not founded on any economic modeling, or have any 
specific criteria for Alaska that it will use to base its decisions. 
* * * No criteria are discussed specific to the Alaska OCS regarding 
MMS's basis for granting royalty relief on leases. * * * MMS needs 
to ensure that its decision to grant it [royalty relief] is not 
arbitrary, and describe the basis upon which it will determine 
whether or not a project is `economic' or `uneconomic' without the 
relief. What information will the applicant need to provide? There 
may be unique information needs for the Alaska OCS but MMS does not 
provide or require these. Why shouldn't the applicant have to 
provide its assessment of the profit it would take out of the leases 
with and without the royalty relief requested (NAEC, et al.)?

    The proposed rule discussed only those parts of the existing 
regulation that are being changed to include leases offshore Alaska. 
The other parts of existing regulations that will apply to leases 
offshore Alaska that seek relief are not being changed by this rule, 
including those that detail how Secretarial discretion will be 
exercised, can be found in 30 CFR Part 203. The CFR sections referenced 
in this rule (see 30 CFR 203.60, 62, 67-70, 73, 76-79) detail the 
extensive information and profit assessment the applicant needs to 
provide and the process MMS would use to determine if a project 
requires relief to be economic. In general, the process for evaluating 
and granting royalty relief is based on an individual analysis of the 
proposed project, which allows inclusion of any condition

[[Page 69496]]

affecting project economics that is specific to the lease and to 
Alaska.
    6. Analysis accompanying rule: Comments in this area emphasize 
doubts about the adequacy of economic and environmental impact analysis 
behind the rule.
    One line of comments indicates a lack of awareness of the extent of 
the analysis that was associated with this rulemaking:

    * * *[I]t is incumbent on any proposed rule for expanding 
royalty relief to include a full and documented economic impact 
analysis of the expanded royalty relief program being proposed, both 
in the Gulf of Mexico as well as in Alaskan waters. This economic 
impact analysis must include a full delineation of the effects of 
market price on the application of royalty relief in any waters to 
which it may be applied (DoW).
    MMS did not conduct any economic analysis projecting the total 
loss of potential royalties to the taxpayer nationally, or from the 
new Alaska OCS royalty holiday. MMS does not make clear in the rule-
making the maximum loss of royalties that could occur. * * * MMS did 
not evaluate whether economic conditions such as the greatly 
increased price per barrel of oil since 1999 would significantly 
change the situation now and whether this could lead to 
substantially increased losses to the public. * * * MMS states that 
`this rulemaking raises novel legal or policy issues' (72 FR 28409) 
yet does not discuss these legal or policy issues in any depth with 
respect to Alaska (NAEC, et al.).

    The proposed rule included the full suite of economic analysis 
required by OMB and under various laws, beginning on page 72 FR 28409. 
A more extensive analysis of the effects of section 344 in the GOM is 
referenced in the rule and is available on the MMS Web site at: http://www.mms.gov/econ/PDFs/2007AddendumDeepGasEA%20_2_.pdf. Further, the 
expansion of the royalty relief program implemented by this rule is 
mandated by statute. In fact, the rule grants no more relief than the 
statute compels, despite the flexibility of the statute that would 
allow MMS to offer potentially much greater amounts of relief. The 
novel policy issues in the proposed rule arise in connection with 
section 344's expansion of the categorical deep gas royalty relief 
program in the GOM, not with section 346's inclusion of Alaska leases 
in a long established pre-production royalty relief process that relies 
on case-by-case analysis of a project's economic need for relief.
    This rule does not mandate any royalty relief be granted in Alaska, 
nor does it automatically provide relief in specified amounts. Whether 
relief is granted in Alaska, and how much to grant, would be based on 
careful evaluation of any complete application. Accordingly, there 
should be no lost royalties under the proposed rule's implementation of 
section 346. The process prescribed invokes an evaluation and follow-up 
procedure that is not intended nor designed to grant royalty relief 
unless production would not occur otherwise. If no production would 
have occurred without royalty relief, no royalty would have been 
generated to lose. Furthermore, the inclusion of price thresholds both 
in the categorical relief under section 344 and in the process invoked 
by the rule for section 346 relief will preclude royalty relief at 
greatly increased prices for oil or gas. It even may result in extra 
royalties if the promise of potential relief manages to encourage 
production which would not have occurred otherwise.
    Other comments raise an environmental concern with the proposed 
royalty relief:

    * * * MMS needs to analyze the environmental impacts of this 
royalty relief in order to determine if the subsidy is in the public 
interest. For example, if taxpayer help is needed in order for an 
oil field to be developed in sensitive Alaska waters that threaten 
subsistence, or endangered species, marine mammals, polar bears, 
migratory birds, etc., we question that such action is really in the 
public interest. * * * The royalty relief issue was not evaluated in 
the Beaufort Sea Sale 186, 195, or 202 Environmental Impact 
Statements, or the current Chukchi Sea Sale 193 EISs, even though 
these subsidies may apply to those leases. Therefore, if MMS states 
that the fields for which it would grant royalty relief would not be 
developed without the subsidy, it must be anticipating additional 
oil field development beyond what was described in those 
environmental reviews, and therefore it cannot grant this relief for 
those leases due to the lack of this issue being addressed, or 
alternatively, MMS must provide supplemental environmental review 
prior to granting any royalty relief for those leases from prior 
sales in Alaska (NAEC, et al.).

    These comments do not take into account that the original lease 
issuance grants the lessee the right to explore and then develop 
discoveries after full consideration of environmental impacts and any 
potential threats to local species. Congress decided to supplement this 
right in section 346 by providing MMS with the authority to consider 
royalty relief as a means to ``promote development or increased 
production on * * * non-producing leases * * *'' The relief process 
implemented by this rulemaking applies to tracts located offshore 
Alaska that have been issued in previous lease sales or will be issued 
in future sales. The lease sale process has or will consider the 
effects of potential exploration and development activity on biological 
resources in that area. In addition, environmental impact studies 
cannot predict with certainty the geologic characteristics of specific 
fields or which ones will be developed. Pre-sale environmental reviews, 
completed at this early stage of Alaska lease exploration, only 
estimate the potential size and possible pace of development. Also, MMS 
provides National Environmental Policy Act analysis on individual 
development and production plans. Royalty relief does not necessarily 
affect that estimate significantly for the aggregate of all fields, in 
part because it is typically the smaller fields that could benefit from 
relief. The sum of production from smaller fields whose development is 
made possible by relief is likely to be a small part of the aggregate 
production estimate for the whole area. Moreover, the royalty relief 
program envisioned only deals with specific marginal fields after 
exploration has clarified the characteristics of the subject field, not 
the whole area.
    7. Competence of MMS to administer royalty relief provisions: 
Comments in this area oppose the relief in this rule on the grounds 
that it may not be managed properly.
    Several comments envisage recurrence of a problem recently 
discovered in another part of the MMS royalty relief program:

    Past errors of management of the royalty relief program provide 
no basis for expanding the same program based upon the same 
categories of misassumptions and data gaps (DoW).
    There have been major problems with the existing Gulf of Mexico 
deep-water royalty provisions * * * and the House of Representatives 
passed an energy bill, H.R. 6 which repealed the EPCA Section 346 * 
* * This section is very controversial, * * * The Government 
Accountability Office has raised questions of the financial impact 
of MMS's deep water royalty relief program * * * However, MMS's 
draft rulemaking does not explain in detail how the past problems 
will be avoided by the new regulations, nor how it will avoid new 
problems by the extension of the program to Alaska (NAEC, et al.).

    The very source of the problems in the deepwater categorical 
royalty relief program in the GOM is precluded by the inclusion in this 
rule of a default price threshold in the changes to the regulations 
proposed by this rule. The rule applies default price thresholds to 
royalty relief for all future GOM leases (see Sec. Sec.  203.36, 
203.48, 203.78, and 260.122) and explains that this action will 
eliminate any omission of a price threshold for leases with royalty 
suspension volumes in future lease sales (see 72 FR 28409). Further, 
the royalty relief process applied to offshore Alaska

[[Page 69497]]

leases by this rule is designed to ensure that no unnecessary royalty 
relief will be granted. This process has been refined through more than 
10 years of use, and is applied to existing leases in a case-specific 
discretionary relief program that is very different from the one for 
leases in the GOM issued under the DWRRA.
    Other comments worry about the way the price threshold would be 
set:

    MMS needs to describe the price thresholds for all the royalty 
relief provisions and for Alaska leases specifically, including how 
it will determine this basis and what the expected results are. 
Failure to issue regulations or leases with proper price thresholds 
led to a ``costly mistake and loss of billions in royalties in the 
Gulf of Mexico, * * * there is no evidence that MMS has adequate 
systems in place to assure a fair system is in place that does not 
harm the U.S. taxpayers generally * * * (NAEC, et al.).

    Price thresholds set in lease documents are chosen at the time of 
the lease sale and the process by which they are originally set is 
explained in the associated decision documents. This rule establishes 
default price thresholds for royalty relief for GOM leases in the 
regulations, which are applied should the lease documents not specify 
another price threshold. Moreover, MMS has adopted many new internal 
control procedures apart from this rule to ensure that the previous 
error does not occur again. In the past 8 years, it never has. When 
price thresholds are established as part of the process for evaluating 
whether an Alaska lease needs royalty relief, the determination of the 
applicable price threshold will be explained in that decision. In 
general, that process will include judgments made at the time of the 
application about projected oil and gas price levels and volatility, 
development costs, and other factors influencing project profitability.
    Another assertion is that this rule is premature:

    * * * The apparent rush by MMS to publish this proposed rule, 
even as Congress now revisits the issue of royalty relief and its 
role in denying fair market value to the federal treasury, seems to 
fly in the face of legislative intent. It would be wholly consistent 
with present congressional deliberations to abate any final action 
on this proposed rule until new legislation, now pending, supersedes 
the 2005 Energy Policy Act and clarifies legislative intent on the 
issue of royalty relief (DoW).

    Ongoing Congressional deliberations do not supersede existing law 
and any new laws that may be passed will not negate the need for this 
rule to address the requirements of the Energy Policy Act of 2005. 
First, there is no assurance repeal will become law. Second, even if 
section 344 is repealed, this rule still must be promulgated because 
its terms apply to 605 leases issued in the 2006 and 2007 lease sales 
plus about 900 issued under lease sales in 2008. Lease documents for 
those sales include language granting lessees the royalty relief 
provided by the still effective statute, subject to the implementing 
MMS rule. This rule sets up the specific terms and conditions on this 
relief that may not otherwise be enforceable, and at the very least, 
will remain ambiguous until the final rule is published. It is also 
worth noting in relation to the stated ``rush by MMS to publish this 
rule'' that MMS's thorough review and analysis have resulted in issuing 
a rule more than 2 years after the deadline set by section 344 of the 
statute in part to ensure the fiscal integrity of the adopted program.
    A related comment laments the need to rely on MMS evaluations:

    Unfortunately, due to the proprietary nature of economic 
information for oil and gas exploration, development, or production 
projects, it means that even if the MMS does obtain such 
information, the public will not have access to it to evaluate the 
fairness or adequacy of MMS's decisions over the royalty holidays 
that are granted (NAEC, et al.).

    Release of proprietary information would violate rights of 
companies to protection of commercially sensitive information. To 
compensate, MMS employs objective technical experts, a sophisticated 
and rigorous analytical approach, and a robust review process to 
evaluate fully an applicant's economic need for royalty relief. That 
capability is used to fulfill the OCSLA and DWRRA charge to the 
Secretary (delegated to MMS) to consider the granting of royalty relief 
to increase production or promote development of oil and gas resources, 
while balancing protection of human, coastal, and marine environments, 
ensuring the public a fair and equitable return on OCS resources and 
maintaining free enterprise competition.
    8. Incompatibility of price thresholds and royalty in-kind: One 
comment raises a possible burden this rule places on leases that pay 
royalty in-kind (RIK) instead of in-value. That burden has to do with 
the need to pay back royalty relief in-value after the year because the 
average gas price exceeded the price threshold.

    * * * The proposed rule and support documents are silent on RIK 
* * * This places a burden on the lease owner depending on violent 
fluctuations of the gas market price. This burden is the staffing up 
or down in order to meet the requirement associated with royalty in 
value. I suggest a more economic process would be that the MMS take 
possession of the potential RIK product and market it. Then, based 
on market price and price threshold, send the proceeds of the RIK to 
the lease owner or the U.S. Treasury as appropriate. This provides 
efficiency to both lease owners and MMS (Tupper).

    Mr. Tupper's suggestion for resolving the issue of payback of 
royalties taken in kind is not practical. This is the case because the 
timing of original RIK collections and sales does not correspond to the 
timing of when payback is determined and the amounts due are 
calculated. Regardless, lease owners operating under an RIK arrangement 
are not likely to have either an administrative or fiscal problem 
related to payback of RIK royalties. For one thing, MMS generally does 
not take royalties in kind from deep gas wells because of the 
uncertainty of whether royalties are due from those wells. In 
situations where MMS did take royalties in kind from deep gas wells 
that qualify for a royalty suspension volume, the MMS procedures for 
valuing payback amounts for royalty taken in kind would be included in 
an agreement with the operator. Accordingly, if the price threshold is 
determined by MMS not to have been exceeded on a royalty relief lease 
after the period for which MMS has taken royalties in kind from that 
lease, MMS would refund royalties to the operator based on the monthly 
values MMS received for that production when taken in kind. On the 
other hand, if the price threshold is determined by MMS to have been 
exceeded on a royalty relief lease after the period for which MMS has 
taken royalties in kind from that lease, no payback is necessary and 
the operator would have met its royalty obligation by delivery of 
royalties in kind during the period. The MMS decisions on whether or 
not to take production in kind are based on the economics of each 
property and whether doing so is favorable to the Government.
    9. Redundant information collection: A procedural comment suggests 
MMS is unnecessarily requesting redundant information from OCS 
operators:

    * * * MMS is already collecting most if not all of the 
information needed as a routine business * * * the first step [in 
qualifying for deep gas royalty relief] is to notify the MMS 
Regional Supervisor for Production and Development of intent to 
begin drilling operations. The MMS is independently informed of this 
intent with the submission of the Application for Permit to Drill 
which is via Form MMS-123 * * * MMS is proposing a new information 
collection process with significant overlap with the information 
collection already in place.

[[Page 69498]]

* * * The paradigm of the proposed rule is that the lease operator 
needs to figure out if a well may be eligible for an RSV and then 
request it. The MMS validates the application and sends a 
confirmation back to the lease operator. I suggest that the correct 
approach is that MMS use its existing information collection data 
stream to determine if an RSV is available under the rules and 
inform the lease operator that RSV is granted (Tupper).

    This suggestion glosses over a subtle but critical aspect of the 
rule. The categorical relief in this rule is intended to serve as an 
incentive for a lessee or operator to drill deep and ultra-deep wells. 
The notification initiating the relief process authenticates that the 
relief is an ex ante part of the decision to drill, rather than an ex 
post windfall, which it might be if MMS initiates the process. Also, 
since companies are already providing most of this information, the 
administrative burden of making a copy to demonstrate response to a 
valuable incentive is minimal. Finally, normal lags in the Government's 
data entry and query process might delay relief and increase the 
chances that an erroneous collection or avoidable refund step might be 
launched if the critical wells are not flagged ahead of time by the 
private sector for relief consideration.
    10. Estimates of the size of the incentive's effect: One comment 
faults an assumption made in the analysis behind this rule:

    * * * The supporting document Programmatic Effects of the Deep 
Gas Incentives in the Energy Policy Act 2005 * * * makes an 
assumption of a constant reservoir size * * * I believe this 
assumption is suspect * * * Gas Fields in water depth of 200 meters 
or less * * * have the following statistical attributes: * * * This 
surrogate data suggests the size of discovery is declining with 
time. This is not an arcane statistical issue, but rather key 
attribute of the effectiveness of the policy. Are the 10 to 12 
percent of the wells drilled which the study indicates are 
associated with royalty relief incentives located in average sized 
reservoirs or are they located in smaller reservoirs that are only 
economic with the royalty relief? If the MMS assumption on reservoir 
size is correct, then around 10 percent of the production is due to 
the incentive. If the reservoirs are much smaller then the share of 
production due to incentive will be corresponding smaller. Size does 
matter (Tupper).

    This observation serves to reinforce the validity of the 
conservative implementation policy adopted in this rule. The estimated 
10-12 percent effect on well drilling cited by the commenter is 
associated with the provision of suspension volumes in the absence of 
price thresholds. Once price thresholds are introduced, the estimated 
original effects on drilling (and, equivalently, production) are 
reduced considerably, and are then estimated to represent one to three 
percent of the new total deep drilling and production levels, which 
include both market price and net incentive effects. Thus, our analysis 
is already very conservative with regard to estimates of programmatic 
effects attributable to the deep gas royalty relief incentives. 
Moreover, there are some grounds for support of the constant discovery 
size assumption even if one focuses on the strict numerical results 
alone, rather than on their relative magnitudes and policy 
implications. This is the case because most of the incremental effects 
estimated for this analysis from royalty relief occur for ultra-deep 
wells, of which very few have been drilled outside the unique Norphlet 
trend offshore Alabama. Thus, it may well be that the larger 
discoveries in the ultra-deep zone apart from the Norphlet trend have 
yet to be made, in which case the average field size still to be 
discovered could be greater than postulated in our analysis. In that 
not unlikely scenario, use of a constant discovery size would mitigate 
somewhat our underestimate of future incremental effects from the 
royalty relief incentive.
    Miscellaneous issues: A number of technical requests in the API 
comments indicate misunderstandings about some of the features of this 
rule. As a result, we will not make the changes requested:
     The request to add limits on the dates when the host 
leases were issued to the definition of phase 1 ultra-deep well is not 
generally appropriate since such a well can be located on most existing 
shallow water leases regardless of when the lease was issued. Other 
than the relatively few leases excluded by virtue of having been issued 
with royalty relief under DWRRA (see Sec.  203.40), the only date that 
matters is when the well was spudded and began producing.
     The request to change the definition to allow a qualified 
well to be drilled into a reservoir that has been penetrated on an 
adjacent or other lease neglects a condition unique to the variant of 
deep gas relief that we granted to leases issued between 2001 and 2003, 
but discontinued for leases issued later. For leases issued in those 
years, lease terms authorized relief only for a well drilled into a 
deep gas reservoir that has not produced on any current lease. Thus, we 
retain that condition for a qualified deep well on a lease issued 
between 2001 and 2003.
     The request to cite in Sec.  203.2 those later sections 
that describe what must be done to demonstrate an expansion or 
development project is uneconomic under the regulations would only 
duplicate our citation of the relevant CFR sections in the parentheses 
at the end of the sentences in the third column of the table.
     The request to specify that a sidetrack measured depth 
must be 20,000 feet TVD SS would confuse diagonal drilling length with 
vertical depth subsea.
     The request to add a deeper bound to the water depth range 
specified in Sec. Sec.  203.34 and 203.43 misses the fact that no such 
bound is needed because these two sections deal with situations where 
the royalty relief in this rule does not apply and deep and ultra-deep 
gas royalty relief never applies to leases in water deeper than 400 
meters.
     The request to add another example of a situation, such as 
equipment failure justifying a delay in the sunset date is not 
necessary as those listed are intended to be just illustrations and not 
an exhaustive list. Other situations than those listed may be a good 
reason for extending the deadline for production start in individual 
cases.
     The request to add wording that does not count gas 
production which is not normally royalty-bearing (fuel gas) against the 
RSV is not practical. As we explained in the original deep gas rule, 
MMS collects only production data at the well level (where deep depth 
wells can be distinguished from shallow depth wells) while royalty-
bearing versus royalty-free production is only identified at the lease 
level where production from all wells on the lease is commingled.
     The request to add text to Sec.  203.69 to distinguish 
between RS leases and other leases issued after November 28, 2000, is 
not appropriate because there is a basis to distinguish between them. 
In particular, there is the possibility that leases may be issued after 
November 28, 2000, that do not have a royalty suspension, i.e., would 
not be RS leases.

D. Summary of the Deep Gas Royalty Relief Program in this Rule

    The following five tables summarize the deep gas royalty relief 
incentives adopted in this rule. Each table refers to a different lease 
type. Abbreviations used in each table include:

------------------------------------------------------------------------
 
------------------------------------------------------------------------
BCF....................................  Billion cubic feet.
K......................................  Thousand.
MD.....................................  Measured depth (length in
                                          thousands of feet).
MMBtu..................................  Million British thermal units.
NA.....................................  Not applicable.
PT.....................................  Price Threshold (2007$ per
                                          MMBtu).
RSS....................................  Royalty Suspension Supplement
                                          (in BCF).
RSV....................................  Royalty Suspension Volume (in
                                          BCF).

[[Page 69499]]

 
ST.....................................  Sidetrack.
TVD SS.................................  True Vertical Depth Sub-Sea.
------------------------------------------------------------------------

    The last two columns of each of the following tables outline the 
royalty relief that exists in the current regulations and the 
additional relief adopted under section 344 rulemaking. The first range 
of numbers in each of these two columns represents the well depth (in 
feet), the second number represents the associated RSV or RSS granted 
(in BCF), and the third number represents the applicable price 
threshold (in $2007/MMBtu).

   Table 1--Terms Applicable to a Lease With No Previous Production From a Deep or Ultra-Deep Well, Located in
                                            Water 0-200 Meters Deep,
      [Issued before 2001 or after 2003 or that Converted to the Royalty Relief Terms in the Existing Rule]
----------------------------------------------------------------------------------------------------------------
                                                                                Depth (feet): RSV [RSS], PT
                                                                         ---------------------------------------
                                                                                               Additional relief
                   Well type           Spud date       1st date produced    Royalty relief       under adopted
                                                                            under existing        section 344
                                                                              regulations         rulemaking
----------------------------------------------------------------------------------------------------------------
A...........  Well 1:    Before 3/26/2003..  Not Relevant......   None.....   NA.
               Original well or
               ST.
B...........  Well 1:    On or after 3/26/   Before 5/3/2009...   If 15K-    ..................
               Original well.      2003 and before 5/                      18K TVD SS: 15      NA.
                                   18/2007.                                BCF, $10.15, or.    NA.
                                                                           If >= 18K
                                                                           TVD SS: 25 BCF,
                                                                           $10.15.
C...........  Well 1:    ..................  ..................   If >= 15K   NA.
               ST.                                                         TVD SS: 4 BCF+
                                                                           (0.6 * MD) BCF up
                                                                           to 15 or 25 BCF,
                                                                           $10.15.
D...........  Well 1:    On or after 5/18/   ..................   If 15K-     NA.
               Original well.      2007.                                   18K TVD SS: 15     ..................
                                                                           BCF, $10.15 \a\,    NA.
                                                                           or.                ..................
                                                                           If 18K-     If >= 20K
                                                                           20K TVD SS: 25      TVD SS: Add 10
                                                                           BCF, $10.15 \a\,    BCF, $4.55 \a\.
                                                                           or.
                                                                           If >= 20K
                                                                           TVD SS: 1st 25
                                                                           BCF, $10.15 \a\.
E...........  Well 1:    ..................  ..................   If >= 20K   If >= 20K
               ST with MD >= 20K                                           TVD SS: 1st 25      TVD SS: Add 10
               ft.                                                         BCF, $10.15 \a\.    BCF, $4.55 \a\.
F...........  Well 1:    ..................  ..................   If >= 15K   None.
               ST with MD < 20K                                            TVD SS: 4 BCF +
               ft.                                                         (0.6 * MD) BCF up
                                                                           to 15 or 25 BCF,
                                                                           $10.15 \a\.
G...........  Well 1:    ..................  On or after 5/3/     None.....   If >= 20K
               Original well or                        2009.                                   TVD SS: 35 BCF,
               ST with MD >= 20K                                                               $4.55 \a\.
               ft.
H...........  Well 1:    On or after 3/26/   Never.............   If 15K-     NA.
               Original well.      2003 and before 5/                      18K TVD SS:
                                   3/2009.                                 [None], or.
                                                                           If >= 18K
                                                                           TVD SS: [5 BCF],
                                                                           $10.15 \a\.
I...........  Well 1:    ..................  ..................   If 15K-     NA.
               ST with MD >= 10K                                           18K TVD SS:
               ft.                                                         [None], or.
                                                                           If >= 18K
                                                                           TVD SS: [0.8 BCF
                                                                           + (0.12 * MD) BCF
                                                                           up to 5 BCF],
                                                                           $10.15 \a\.
----------------------------------------------------------------------------------------------------------------
\a\ For wells on leases issued after December 18, 2008, the price threshold will be $4.55/MMBtu (adjusted for
  inflation after 2007) unless the lease terms prescribe a different price threshold.

    For example, suppose an original well (one that does not use an 
existing wellbore) was drilled to a depth of 23,000 feet TVD SS between 
September and December 2007 (after the proposed rule was issued), on a 
lease that has had no production from a well completed at a depth 
deeper than 15,000 ft TVD SS. If the well starts producing in 2008, 
Table 1, row D indicates the well earns an RSV of 35 BCF. Further, the 
first 25 BCF of that RSV is subject to a price threshold of $10.15 per 
MMBtu (adjusted for inflation after 2007), while the remaining RSV of 
10 BCF is subject to a price threshold of $4.55 per MMBtu (adjusted for 
inflation after 2007). Alternatively, if delays prevent production from 
starting until July of 2009, Table 1, row G indicates this well still 
earns an RSV of 35 BCF, but the entire RSV is subject to a price 
threshold of $4.55 per MMBtu (adjusted for inflation after 2007). If 
this well were unsuccessful rather than productive, Table 1, row H 
indicates that it earns an RSS of 5 BCF that is subject to a price 
threshold of $10.15 per MMBtu (adjusted for inflation after 2007).

                                      Table 2--Terms Applicable to a Lease
 [With Previous Production from a Deep Well completed between 15,000 and 18,000 feet TVD SS, Located in Water 0-
200 Meters Deep, Issued before 2001 or after 2003 or Converted to the Royalty Relief Terms in the Existing Rule]
----------------------------------------------------------------------------------------------------------------
                                                                                Depth (feet): RSV [RSS], PT
                                                                         ---------------------------------------
                                                                                               Additional relief
                   Well type           Spud date       1st date produced    Royalty relief       under adopted
                                                                            under existing        section 344
                                                                              regulations         rulemaking
----------------------------------------------------------------------------------------------------------------
A...........  Well 2:    On or after 3/26/   Before 5/3/2009...   If 15K-     NA.
               Original well.      2003 and before 5/                      18K TVD SS: None,
                                   18/2007.                                or
                                                                           If >= 18K
                                                                           TVD SS: 10 BCF,
                                                                           $10.15.

[[Page 69500]]

 
B...........  Well 2:    ..................  ..................   If 15K-     NA.
               ST.                                                         18K TVD SS: None,
                                                                           or
                                                                           If >= 18K
                                                                           TVD SS: 4 BCF+
                                                                           (0.6 * MD) BCF up
                                                                           to 10 BCF, $10.15.
C...........  Well 2:    On or after 5/18/   ..................   If 15K-     If >= 20K
               Original well.      2007.                                   18K TVD SS: None,   TVD SS: + 10 BCF
                                                                           or                  if lease issued
                                                                           If 18K-     in lease sale
                                                                           20K TVD SS: 10      held between 1/1/
                                                                           BCF, $10.15 a.      2004 and 12/31/
                                                                                               2005 otherwise
                                                                                               none, $10.15.
D...........  Well 2:    ..................  ..................   If 15K-     If >= 20K
               ST with MD >= 20K                                           18K TVD SS: None,   TVD SS: + 10 BCF
               ft.                                                         or                  if lease issued
                                                                                               in lease sale
                                                                                               held between 1/1/
                                                                                               2004 and 12/31/
                                                                                               2005 otherwise
                                                                                               none, $10.15.
E...........  Well 2:    ..................  ..................   If 18K-     If >= 20K
               ST with MD < 20K                                            20K TVD SS: 4 BCF   TVD SS: + 4BCF +
               ft.                                                         + (0.6 * MD) BCF    (0.6 * MD) BCF if
                                                                           up to 10 BCF,       lease issued in
                                                                           $10.15 a.           lease sale held
                                                                                               between 1/1/2004
                                                                                               and 12/31/2005
                                                                                               otherwise none,
                                                                                               $10.15.
F...........  Well 2:    ..................  On or after 5/3/     None.....   None.
               Original well or                        2009.
               ST.
G...........  Well 2:    On or after 3/26/   Never.............   If 15K-     NA.
               Original well or    2003 and before 5/                      18K TVD SS:
               ST with MD >= 10K   3/2009.                                 [None], or
               ft.                                                         If >= 18K
                                                                           TVD SS: [2 BCF],
                                                                           $10.15 a.
----------------------------------------------------------------------------------------------------------------
\a\ For wells on leases issued after December 18, 2008, the price threshold will be $4.55/MMBtu (adjusted for
  inflation after 2007) unless the lease terms prescribe a different price threshold.

    For example, suppose a sidetrack with a measured depth or length of 
7,000 feet is drilled to a depth of 23,000 feet TVD SS beginning in 
September 2007 (after the proposed rule was issued), and begins 
production in December 2007 on a lease issued in 1998 that already has 
production from a well completed at 16,000 feet TVD SS. This well earns 
no additional RSV because Table 2, row E, last column shows that this 
1998 lease is too old to come within the exception proposed for leases 
issued in lease sales held between January 1, 2004, and December 31, 
2005. However, this ultra-deep short sidetrack is a qualified well 
entitled to share the remaining RSV, if any, earned by the deep well.

   Table 3--Terms Applicable to a Lease With no Previous Production from a Deep or Ultra-Deep Well, Located in
                                        Water Between 200-400 Meters Deep
----------------------------------------------------------------------------------------------------------------
                                                                                Depth (feet): RSV [RSS], PT
                                                                         ---------------------------------------
                                                                                               Additional relief
                   Well type           Spud date       1st date produced    Royalty relief       under adopted
                                                                            under existing        section 344
                                                                              regulations         rulemaking
----------------------------------------------------------------------------------------------------------------
A...........  Well 1:    Before 5/18/2007..  Not Relevant......   None.....   None.
               Original well or
               ST.
B...........  Well 1:    On or after 5/18/   Before 5/3/2013...  ..................   If 15K-
               Original well.      2007.                                                       18K TVD SS: 15
                                                                                               BCF, $4.55 \a\,
                                                                                               or
                                                                                               If 18K-
                                                                                               20K TVD SS: 25
                                                                                               BCF, $4.55 \a\,
                                                                                               or
                                                                                               If >= 20K
                                                                                               TVD SS: 35 BCF,
                                                                                               $4.55 \a\.
C...........  Well 1:    ..................  ..................  ..................   If 15K-
               ST with MD >= 20K                                                               20K TVD SS: 4 BCF
               ft.                                                                             + (0.6 * MD) BCF
                                                                                               up to 15 or 25
                                                                                               BCF, $4.55 \a\,
                                                                                               or
                                                                                               If >= 20K
                                                                                               TVD SS: 35 BCF,
                                                                                               $4.55 \a\.
D...........  Well 1:    ..................  ..................  ..................   If >= 15K
               ST with MD < 20K                                                                TVD SS: 4 BCF+
               ft.                                                                             (0.6 * MD) BCF up
                                                                                               to 15 or 25 BCF,
                                                                                               $4.55 \a\.
E...........  Well 1:    ..................  On or after 5/3/    ..................   If 15K-
               Original well.                          2013.                                   20K TVD SS: None,
                                                                                               or
                                                                                               If >= 20K
                                                                                               TVD SS: 35 BCF,
                                                                                               $4.55 \a\.
F...........  Well 1:    ..................  ..................  ..................   If 15K-
               ST with MD >= 20K                                                               20K TVD SS: None,
               ft.                                                                             or
                                                                                               If >= 20K
                                                                                               TVD SS: 35 BCF,
                                                                                               $4.55 \a\.
G...........  Well 1:    ..................  ..................  ..................   None.
               ST with MD < 20K
               ft.

[[Page 69501]]

 
H...........  Well 1:    On or after 5/18/   Never.............  ..................   If 15K-
               Original well.      2007 and before 5/                                          18K TVD SS:
                                   3/2013.                                                     [None], or
                                                                                               If >= 18K
                                                                                               TVD SS: [5 BCF],
                                                                                               $4.55 \a\.
I...........  Well 1:    ..................  ..................  ..................   If 15K-
               ST with MD >= 10K                                                               18K TVD SS:
               ft.                                                                             [None], or
                                                                                               If >= 18K
                                                                                               TVD SS: [0.8 BCF+
                                                                                               (0.12 * MD) BCF
                                                                                               up to 5 BCF],
                                                                                               $4.55 \a\.
----------------------------------------------------------------------------------------------------------------
\a\ Unless the lease terms of a lease issued after December 18, 2008, prescribe a different price threshold.

    For example, suppose a sidetrack with a measured depth or length of 
9,000 feet is drilled to a depth of 18,000 feet TVD SS between February 
and October 2010 (after the proposed rule was issued) on a lease that 
has had no production from a well completed deeper than 15,000 ft TVD 
SS. If it starts producing in 2011, Table 3, row D indicates the well 
earns an RSV of 9.4 BCF subject to a price threshold of $4.55 per MMBtu 
(adjusted for inflation after 2007). Alternatively, if delays prevent 
production starting until July of 2013, Table 3, row G indicates this 
well earns no RSV. If this well were unsuccessful, Table 3, row I 
indicates that it would not qualify for an RSS because its measured 
depth is too short.

   Table 4--Terms Applicable to a Lease With Previous Production From a Deep Well Completed Between 15,000 and
                        18,000 Feet TVD SS, Located in Water Between 200-400 Meters Deep
----------------------------------------------------------------------------------------------------------------
                                                                                Depth (feet): RSV [RSS], PT
                                                                         ---------------------------------------
                                                                                               Additional relief
                   Well type           Spud date       1st date produced    Royalty relief       under adopted
                                                                            under existing        section 344
                                                                              regulations         rulemaking
----------------------------------------------------------------------------------------------------------------
A...........  Well 2:    On or after 5/18/   Before 5/3/2013...   None.....   If 15K-
               Original well.      2007 and before 5/                                          18K TVD SS: None,
                                   3/2013.                                                     or
                                                                                               If 18K-
                                                                                               20K TVD SS: 10
                                                                                               BCF, $4.55 \a\,
                                                                                               or
                                                                                               If >= 20K
                                                                                               TVD SS: None.
B...........  Well 2:    ..................  ..................  ..................   If 15K-
               ST.                                                                             18K TVD SS: None,
                                                                                               or
                                                                                               If 18K-
                                                                                               20K TVD SS: 4 BCF
                                                                                               + (0.6 * MD) BCF
                                                                                               up to 10 BCF,
                                                                                               $4.55 \a\, or
                                                                                               If >= 20K
                                                                                               TVD SS: None.
C...........  Well 2:    On or after 5/18/   On or after 5/3/    ..................   None.
               Original well or    2007.               2013.
               ST.
D...........  Well 2:    On or after 5/18/   Never.............  ..................   If 15K-
               Original well or    2007 and before 5/                                          18K TVD SS:
               ST with MD >= 10K   3/2013.                                                     [None], or
               ft.                                                                             If >= 18K
                                                                                               TVD SS: [2 BCF],
                                                                                               $4.55 \a\.
----------------------------------------------------------------------------------------------------------------
\a\ Unless the lease terms of a lease issued after December 18, 2008, prescribe a different price threshold.

    For example, suppose an original well is drilled to a depth of 
19,000 feet TVD SS between June and November 2011 (after the proposed 
rule was issued) on a lease that already has production from a well 
completed at 16,000 ft TVD SS. If it starts producing in March 2012, 
Table 4, row A indicates the well earns an RSV of 10 BCF for the lease. 
If the prior deep well also earned an RSV, then this 10 BCF is an 
additional RSV. However, if production is delayed until July 2013, 
Table 4, row C indicates this deep well earns no additional RSV; nor 
may any remaining RSV that the prior deep well may have earned be 
applied to production from this well.

 Table 5--Terms Applicable to a Lease Located in Water 0-200 Meters Deep, Issued From 2001 Through 2003 That Did
                       Not Convert From the Royalty Relief Terms With Which It Was Issued
----------------------------------------------------------------------------------------------------------------
                                                                                Depth (feet): RSV [RSS], PT
                                                                         ---------------------------------------
                                                                                               Additional relief
                   Well type           Spud date       1st date produced   Existing royalty      under adopted
                                                                          relief in original      section 344
                                                                              lease terms         rulemaking
----------------------------------------------------------------------------------------------------------------
A...........  Well 1:    Before 5/18/ 2007.  Within 5 years of    If >= 15K   None.
               Original well or                        lease effective     in new reservoir:
               ST.                                     date.               20BCF, $4.08
                                                                           (Sale 178), or.
                                                                           If >= 15K
                                                                           in new reservoir:
                                                                           20BCF, $5.83
                                                                           (Sales 180, 182,
                                                                           184, 185, or 187).

[[Page 69502]]

 
B...........  ..................  On after 5/18/      ..................   If 15K-     If 15K-
                                   2007.                                   20K in new          20K TVD SS: None,
                                                                           reservoir: 20BCF,   or
                                                                           $4.08 (Sale 178),   If >= 20K
                                                                           or                  TVD SS: Add 15
                                                                           If 15K-     BCF, $4.55.
                                                                           20K in new
                                                                           reservoir: 20BCF,
                                                                           $5.83 (Sales 180,
                                                                           182, 184, 185, or
                                                                           187), or.
                                                                           If >= 20K
                                                                           in new reservoir:
                                                                           1st 20 BCF, $4.08
                                                                           (Sale 178) or
                                                                           $5.83 (Sales 180,
                                                                           182, 184, 185, or
                                                                           187).
C...........  ..................  ..................  More than 5 years    None.....   If 15K-
                                                       after lease                             20K TVD SS: None,
                                                       effective date.                         or
                                                                                               If >= 20K
                                                                                               in new reservoir:
                                                                                               35BCF, $4.55.
----------------------------------------------------------------------------------------------------------------

    For example, suppose an original well or sidetrack is drilled to a 
depth of 23,000 feet TVD SS between August 2007 and March 2008 (after 
the proposed rule was issued) on a lease issued in November 2002. If 
this well starts producing from a reservoir that has not produced on 
any current lease, Table 5, row B indicates the well earns an RSV of 35 
BCF. Further, the first 20 BCF of that RSV is subject to a price 
threshold of $5.83 per MMBtu (adjusted for inflation after 2007) while 
the remaining RSV of 15 BCF is subject to a price threshold of $4.55 
per MMBtu (adjusted for inflation after 2007).
    Additional information on the structure of the deep gas royalty 
relief incentives both in existing regulations and in this rule can be 
found on the MMS Web site at: http://www.mms.gov/econ/.

Procedural Matters

Regulatory Planning and Review (Executive Order (E.O.) 12866)

    This final rule is a significant rule as determined by the Office 
of Management and Budget (OMB) and is subject to review under E.O. 
12866. We have made the assessments required by E.O. 12866 and the 
results are:
    (1) This final rule will not have an economic effect of $100 
million or more in any year.
    The added eligibility of leases in water depths from 200 to 400 
meters for the deep gas royalty incentive will represent a 12 percent 
increase in the estimated gas resources that will be eligible for the 
deep gas incentive, and only a fraction of those resources will 
actually qualify because the program would sunset in May 2013. Further, 
existing relief terms already grant leases located partly or entirely 
in less than 200 meters of water with ultra-deep wells over 70 percent 
of the relief this rule prescribes (25 BCF increasing to 35 BCF for 
successful ultra-deep wells). However, because this incentive will have 
no explicit sunset date, it conceivably could apply to all undiscovered 
ultra-deep resources.
    One of the few areas of significant programmatic discretion MMS has 
in implementing section 344 is in the choice of the price threshold for 
RSVs. This rule sets a different and lower price threshold for RSVs 
earned and used by ultra-deep wells, except to the extent of the 
royalty relief that an ultra-deep well would earn under the existing 
rule on leases in existence on the effective date of this final rule. 
This different price threshold is low enough to cancel relief whose 
value might otherwise have been over $100 million at current and 
projected gas prices.
    The MMS has updated key parts of the economic analysis done for the 
original deep gas rule to reflect both higher gas prices and the larger 
open-ended duration of RSVs for ultra-deep wells. The update estimates 
the incremental production and net fiscal cost which would result from 
the added incentives on ultra-deep wells and additional deep wells for 
a range of price thresholds applied to the anticipated gas market 
environment. The price threshold adopted in this rule for ultra-deep 
gas royalty relief is the same as the price threshold used for 
deepwater royalty relief for leases issued before 2001, after adjusting 
for inflation ($4.55 per MMBtu in 2007 dollars, to be further adjusted 
for inflation after 2007). For comparison, MMS estimates that the 
ultra-deep well and additional deep well incentives required by the 
Energy Policy Act, together with a reduced price threshold of $4.55 per 
MMBtu (adjusted for inflation after 2007) would, over the next 15 
years, increase deep gas production by 54 BCF instead of by 223 BCF, 
and reduce the aggregate loss in Federal royalty receipts by $955 
million (present value $508 million, or about $34 million in an average 
year) relative to using the same price threshold as in the existing 
regulations. Over the next 15 years, we estimate that the adopted price 
threshold of $4.55 per MMBtu would keep the present value of the 
aggregate fiscal cost of this rulemaking below $100 million resulting 
in an average annual fiscal cost of about $7 million, generate a social 
welfare measure of consumer plus producer surplus of only about $4,200 
in present value, and add over 50 billion cubic feet of deep gas 
production to the domestic energy supply. The full economic analysis 
for the original deep gas rule, as well as this update, is available 
at: http://www.mms.gov/econ.
    As of the beginning of fiscal year 2008, this rule also adds 750 
currently active Alaska leases to the roughly 2,700 deepwater leases in 
the GOM, as well as future leases in both areas, that could apply for 
an RSV (for both oil and gas) before production or to expand 
production. Again, section 346 of the Energy Policy Act mandates this 
expansion of existing authority to consider and possibly grant 
discretionary royalty relief. So, the provisions in this rule simply 
provide a framework for a process--by themselves they have no direct 
economic effect over and above that which may result from the statutory 
language in section 346.
    Historically, we have received less than one application per year 
in the GOM under the procedure now being extended to leases offshore of 
Alaska. Those leases that previously have qualified for this form of 
relief have

[[Page 69503]]

avoided an average of $30 million annually in royalties since 1999, an 
amount that would have been much larger but for price thresholds. 
Accordingly, the value of the relief that may be granted indirectly by 
this added rulemaking action may not significantly ease the daunting 
obstacles to developing offshore Alaska. In any event, the award of 
royalty relief in this form to leases offshore of Alaska is 
discretionary, and MMS will only approve relief in the appropriate 
amount or provide an exception to the established price thresholds if 
MMS deemed the applicable project uneconomic absent relief. Thus, for 
these reasons, there will be no negative effect on Federal revenues 
from this rulemaking.
    (2) This final rule will not create any inconsistencies or 
otherwise interfere with actions by other Federal agencies. Careful 
review of the lease sale notices, along with stringent leasing policies 
now in force, ensure that the Federal OCS leasing program, of which 
royalty relief is only a component, will not conflict with the work of 
other Federal agencies.
    (3) This final rule will not alter the budgetary effects of 
entitlements, grants, user fees, or loan programs or the rights or 
obligations of their recipients.
    (4) This final rule raises novel legal or policy issues because it 
implements a statutory requirement to expand a previously established, 
but so far disappointing royalty relief program for deep gas in the 
GOM. The rule also serves to eliminate any recurrence of an unintended 
policy issue by establishing default price thresholds for all future 
leases that may be issued with royalty relief incentives. The other 
part of the rule, which extends a long established but little used 
discretionary royalty relief authority to leases offshore Alaska, 
raises no unusual issues because, with the exception of explicit 
statutory requirements under the DWRRA, programmatically the price 
thresholds have always been treated as a complementary policy variable 
to the royalty suspension volumes for dealing with applications of 
discretionary royalty relief on a case-by-case basis.

Regulatory Flexibility Act

    The Department of the Interior certifies that this final rule will 
not have a significant economic effect on a substantial number of small 
entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.).
    The provisions of this final rule will not have a significant 
adverse economic effect on offshore lessees and operators, including 
those that are classified as small businesses.
    This rule expands existing deep gas well production incentives. A 
detailed analysis of the small business impacts and alternatives for 
the deep gas provisions established in 2004 were considered and can be 
found in the economic analysis of the original version of this 
regulation available at: http://www.mms.gov/econ. This rule will not 
materially alter the findings of that analysis because it will expand 
by less than 5 percent the set of leases affected, based on the number 
of existing and potential leases in the interval from entirely deeper 
than 200 to entirely less than 400 meters of water relative to those in 
the interval from 0 to partly or entirely less than 200 meters of water 
that are already covered by the existing rule.
    The rule also extends the potential for discretionary royalty 
relief to 263 OCS leases located offshore Alaska, some of which may 
qualify as marginally uneconomic. Five of the eight companies involved 
are ``majors'' and therefore are not small entities. In any single 
year, MMS is likely to receive only a small number of royalty relief 
applications, if indeed it receives any at all. That limits the number 
of entities this rule may affect. In the past, we have received less 
than one application a year from a candidate set of 2,700 leases in the 
GOM. Also, because firms initiate applications, they have the ability 
to avoid adverse effects they foresee. A Regulatory Flexibility 
Analysis is not required. A Small Entity Compliance Guide is not 
required.

Small Business Regulatory Enforcement Fairness Act

    The final rule is not a major rule under 5 U.S.C. 804(2) the Small 
Business Regulatory Enforcement Fairness Act. This final rule:
    a. Will expand coverage of existing royalty relief programs by 15 
percent, adding about 800 leases to the set of about 5,000 leases 
eligible either for (1) the deep gas incentive or (2) to apply for 
royalty relief before production begins on the lease. These leases 
represent only a fraction of the leases already eligible for these 
incentives as a result of earlier rules. The effects of the provisions 
in this rule will not add substantially to those estimated for the 
earlier rules because relatively little relief is likely to be granted 
under the new provisions.
    b. Will not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, local government 
agencies, or geographic regions. The additional deep gas incentive 
provisions will not cause an increase in prices and should result in 
some downward pressure on prices, but its degree and ultimate effect is 
difficult to anticipate.
    c. Will not have significant adverse effects on competition, 
employment, investment, or the ability of U.S.-based enterprises to 
compete with foreign-based enterprises. Companies eligible for the new 
royalty relief should produce some more natural gas and earn more 
income while encountering no negative effects.

Unfunded Mandates Reform Act

    This final rule will not impose an unfunded mandate on State, 
local, or tribal governments or the private sector of more than $100 
million per year. The final rule will 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. 1531 et seq.) is not required.

Takings Implication Assessment (E.O. 12630)

    Under the criteria in E.O. 12630, this final rule does not have 
significant takings implications. The final rule is not a governmental 
action capable of interference with constitutionally protected property 
rights. A Takings Implication Assessment is not required.

Federalism (E.O. 13132)

    Under the criteria in E.O. 13132, this final rule will not have 
sufficient federalism implications to warrant the preparation of a 
Federalism Assessment. As noted above, the deep gas provisions in this 
rule should have a small effect relative to the proposed rule, which 
itself may have only a small consequence ($1-$2 million per year) on 
Gulf Coast states in the form of reduced payments under section 8(g) of 
the OCSLA. Any relief awarded to offshore Alaska leases will not affect 
that State's share of OCS revenue because the discretionary royalty 
relief rules extended by this rule to leases offshore of Alaska are 
designed to grant relief only when production and thus royalty payments 
would not otherwise occur.

Civil Justice Reform (E.O. 12988)

    This rule complies with the requirements of E.O. 12988. 
Specifically, this rule:
    (a) Meets the criteria of section 3(a) requiring that all 
regulations be reviewed to eliminate errors and ambiguity and be 
written to minimize litigation; and

[[Page 69504]]

    (b) Meets the criteria of section 3(b)(2) requiring that all 
regulations be written in clear language and contain clear legal 
standards.

Consultation With Indian Tribes (E.O. 13175)

    Under the criteria in E.O. 13175, we have evaluated this final rule 
and determined that it has no potential effects on federally recognized 
Indian tribes. There are no Indian or tribal lands in the OCS.

Paperwork Reduction Act

    An information collection package was submitted to OMB for review 
and approval under section 3507(d) of the PRA. The OMB has approved the 
information collection requirements for this rulemaking and assigned 
OMB Control Number 1010-0173 (exp. 8/31/10; 3 burden hours). The title 
of the collection of information for this final rule is ``30 CFR 203, 
Royalty Relief--Ultra-Deep Gas Wells and Deep Gas Wells on Oil and Gas 
Leases; Extension of Royalty Relief Provisions to Leases Offshore of 
Alaska.'' Respondents are those from the approximately 130 Federal oil 
and gas lessees who may apply for royalty relief. Responses to this 
collection are required to obtain benefits. The frequency of response 
is on occasion. The information collection does not include questions 
of a sensitive nature. The MMS will protect proprietary information 
according to the Freedom of Information Act (5 U.S.C. 552) and its 
implementing regulations (43 CFR 2), 30 CFR part 203, ``Does my 
application have to include all leases in the field?'' and 30 CFR 
250.197, ``Data and information to be made available to the public or 
for limited inspection.''
    We received eight comments due to this rulemaking. Only one 
commenter brought up information collection redundancy; however, MMS 
determined that there is no redundancy and that the requirements were 
new. Therefore, there were no changes in the information collection 
requirements from the proposed rule to the final rule. When the rule 
becomes effective, MMS will merge these hours into the primary 
collection for 30 CFR 203 (OMB Control Number 1010-0071, expiration 12/
31/09).
    An agency may not conduct or sponsor, and you are not required to 
respond to, a collection of information unless it displays a currently 
valid OMB control number. The public may comment, at any time, on the 
accuracy of the information collection burden in this rule and may 
submit any comments to the Department of the Interior; Minerals 
Management Service; Attention: Regulations and Standards Branch; Mail 
Stop 4024; 381 Elden Street; Herndon, Virginia 20170-4817.

National Environmental Policy Act

    We determined this rule is categorically excluded from requirements 
for analysis under the National Environmental Policy Act and the 
Department Manual at 516 DM. This rule deals with financial matters and 
has no direct effect on MMS decisions on oil and gas operations with 
the potential to affect the environment; hence, an Environmental Impact 
Statement is not required. Pursuant to Department Manual 516 DM 2.3A 
(2), section 1.10 of 516 DM 2, Appendix 1 excludes from documentation 
in an environmental assessment or impact statement ``policies, 
directives, regulations and guidelines of an administrative, financial, 
legal, technical or procedural nature; or the environmental effects of 
which are too broad, speculative or conjectural to lend themselves to 
meaningful analysis and will be subject later to the NEPA process, 
either collectively or case-by-case.'' Section 1.3 of the same appendix 
clarifies that royalties and audits are considered routine financial 
transactions that are subject to categorical exclusion from the NEPA 
process. None of the exceptional circumstances set forth in 516 DM 2 
Appendix 2 apply.

Data Quality Act

    In developing this rule, we did not conduct or use a study, 
experiment, or survey requiring peer review under the Data Quality Act 
(Pub. L. 106-554, app. C Sec.  515, 114 Stat. 2763, 2763A-153-154).

Effects on the Energy Supply (E.O. 13211)

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

List of Subjects

30 CFR Part 203

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

30 CFR Part 260

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

    Dated: June 19, 2008.
C. Stephen Allred,
Assistant Secretary--Land and Minerals Management.

0
For the reasons stated in the preamble, the Minerals Management Service 
(MMS) amends 30 CFR Part 203 as follows:

PART 203--RELIEF OR REDUCTION IN ROYALTY RATES

0
1. The authority citation for part 203 is revised to read as follows:

    Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 
U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 
30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 
U.S.C. 15903-15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; 
and 43 U.S.C. 1801 et seq.

0
2. Section 203.0 is amended by revising the definitions for ``certified 
unsuccessful well'', ``deep well'', ``development project'', 
``expansion project'', ``original well'', ``royalty suspension 
supplement'' and ``royalty suspension volume''; removing the definition 
of ``qualified well''; and by adding definitions for ``non-converted 
lease'', ``phase 1 ultra-deep well'', ``phase 2 ultra-deep well'', 
``phase 3 ultra-deep well'', ``qualified deep well'', ``qualified 
ultra-deep well'', ``qualified wells'', and ``ultra-deep well'' to read 
as follows:


Sec.  203.0  What definitions apply to this part?

* * * * *
    Certified unsuccessful well means an original well or a sidetrack 
with a sidetrack measured depth (i.e., length) of at least 10,000 feet, 
on your lease that:
    (1) You begin drilling on or after March 26, 2003, and before May 
3, 2009, on a lease that is located in water partly or entirely less 
than 200 meters deep and that is not a non-converted lease, or on or 
after May 18, 2007, and before May 3, 2013, on a lease that is located 
in water entirely more than 200 meters and entirely less than 400 
meters deep;
    (2) You begin drilling before your lease produces gas or oil from a 
well with a perforated interval the top of which is at least 18,000 
feet true vertical depth subsea (TVD SS), (i.e., below the datum at 
mean sea level);
    (3) You drill to at least 18,000 feet TVD SS with a target 
reservoir on your lease, identified from seismic and related data, 
deeper than that depth;
    (4) Fails to meet the producibility requirements of 30 CFR part 
250, subpart A, and does not produce gas or oil, or meets those 
producibility requirements and MMS agrees it is not commercially 
producible; and

[[Page 69505]]

    (5) For which you have provided the notices and information 
required under Sec.  203.47.
* * * * *
    Deep well means either an original well or a sidetrack with a 
perforated interval the top of which is at least 15,000 feet TVD SS and 
less than 20,000 feet TVD SS. A deep well subsequently re-perforated at 
less than 15,000 feet TVD SS in the same reservoir is still a deep 
well.
* * * * *
    Development project means a project to develop one or more oil or 
gas reservoirs located on one or more contiguous leases that have had 
no production (other than test production) before the current 
application for royalty relief and are either:
    (1) Located in a planning area offshore Alaska; or
    (2) Located in the GOM in a water depth of at least 200 meters and 
wholly west of 87 degrees, 30 minutes West longitude, and were issued 
in a sale held after November 28, 2000.
* * * * *
    Expansion project means a project that meets the following 
requirements:
    (1) You must propose the project in a Development and Production 
Plan, a Development Operations Coordination Document (DOCD), or a 
Supplement to a DOCD, approved by the Secretary of the Interior after 
November 28, 1995.
    (2) The project must be located on either:
    (i) A pre-Act lease in the GOM, or a lease in the GOM issued in a 
sale held after November 28, 2000, located wholly west of 87 degrees, 
30 minutes West longitude; or
    (ii) A lease in a planning area offshore Alaska.
    (3) On a pre-Act lease in the GOM, the project:
    (i) Must significantly increase the ultimate recovery of resources 
from one or more reservoirs that have not previously produced 
(extending recovery from reservoirs already in production does not 
constitute a significant increase); and
    (ii) Must involve a substantial capital investment (e.g., fixed-leg 
platform, subsea template and manifold, tension-leg platform, multiple 
well project, etc.).
    (4) For a lease issued in a planning area offshore Alaska, or in 
the GOM after November 28, 2000, the project must involve a new well 
drilled into a reservoir that has not previously produced.
    (5) On a lease in the GOM, the project must not include a reservoir 
the production from which an RSV under Sec. Sec.  203.30 through 203.36 
or Sec. Sec.  203.40 through 203.48 would be applied.
* * * * *
    Non-converted lease means a lease located partly or entirely in 
water less than 200 meters deep issued in a lease sale held after 
January 1, 2001, and before January 1, 2004, whose original lease terms 
provided for an RSV for deep gas production and the lessee has not 
exercised the option under Sec.  203.49 to replace the lease terms for 
royalty relief with those in Sec.  203.0 and Sec. Sec.  203.40 through 
203.48.
    Original Well means a well that is drilled without utilizing an 
existing wellbore. An original well includes all sidetracks drilled 
from the original wellbore either before the drilling rig moves off the 
well location or after a temporary rig move that MMS agrees was forced 
by a weather or safety threat and drilling resumes within 1 year. A 
bypass from an original well (e.g., drilling around material blocking 
the hole or to straighten crooked holes) is part of the original well.
* * * * *
    Phase 1 ultra-deep well means an ultra-deep well on a lease that is 
located in water partly or entirely less than 200 meters deep for which 
drilling began before May 18, 2007, and that begins production before 
May 3, 2009, or that meets the requirements to be a certified 
unsuccessful well.
    Phase 2 ultra-deep well means an ultra-deep well for which drilling 
began on or after May 18, 2007; and that either meets the requirements 
to be a certified unsuccessful well or that begins production:
    (1) Before the date which is 5 years after the lease issuance date 
on a non-converted lease; or
    (2) Before May 3, 2009, on all other leases located in water partly 
or entirely less than 200 meters deep; or
    (3) Before May 3, 2013, on a lease that is located in water 
entirely more than 200 meters and entirely less than 400 meters deep.
    Phase 3 ultra-deep well means an ultra-deep well for which drilling 
began on or after May 18, 2007, and that begins production:
    (1) On or after the date which is 5 years after the lease issuance 
date on a non-converted lease; or
    (2) On or after May 3, 2009, on all other leases located in water 
partly or entirely less than 200 meters deep; or
    (3) On or after May 3, 2013, on a lease that is located in water 
entirely more than 200 meters and entirely less than 400 meters deep.
* * * * *
    Qualified deep well means:
    (1) On a lease that is located in water partly or entirely less 
than 200 meters deep that is not a non-converted lease, a deep well for 
which drilling began on or after March 26, 2003, that produces natural 
gas (other than test production), including gas associated with oil 
production, before May 3, 2009, and for which you have met the 
requirements prescribed in Sec.  203.44;
    (2) On a non-converted lease, a deep well that produces natural gas 
(other than test production) before the date which is 5 years after the 
lease issuance date from a reservoir that has not produced from a deep 
well on any lease; or
    (3) On a lease that is located in water entirely more than 200 
meters but entirely less than 400 meters deep, a deep well for which 
drilling began on or after May 18, 2007, that produces natural gas 
(other than test production), including gas associated with oil 
production before May 3, 2013, and for which you have met the 
requirements prescribed in Sec.  203.44.
    Qualified ultra-deep well means:
    (1) On a lease that is located in water partly or entirely less 
than 200 meters deep that is not a non-converted lease, an ultra-deep 
well for which drilling began on or after March 26, 2003, that produces 
natural gas (other than test production), including gas associated with 
oil production, and for which you have met the requirements prescribed 
in Sec.  203.35 or Sec.  203.44, as applicable; or
    (2) On a lease that is located in water entirely more than 200 
meters and entirely less than 400 meters deep, or on a non-converted 
lease, an ultra-deep well for which drilling began on or after May 18, 
2007, that produces natural gas (other than test production), including 
gas associated with oil production, and for which you have met the 
requirements prescribed in Sec.  203.35.
    Qualified well means either a qualified deep well or a qualified 
ultra-deep well.
* * * * *
    Royalty suspension supplement (RSS) means a royalty suspension 
volume resulting from drilling a certified unsuccessful well that is 
applied to future natural gas and oil production generated at any 
drilling depth on, or allocated under an MMS-approved unit agreement 
to, the same lease.
    Royalty suspension volume (RSV) means a volume of production from a 
lease that is not subject to royalty under the provisions of this part.
* * * * *
    Ultra-deep well means either an original well or a sidetrack 
completed with a perforated interval the top of

[[Page 69506]]

which is at least 20,000 feet TVD SS. An ultra-deep well subsequently 
re-perforated less than 20,000 feet TVD SS in the same reservoir is 
still an ultra-deep well.
    Ultra-deep short sidetrack means an ultra-deep well that is a 
sidetrack with a sidetrack measured depth (i.e., length) of less than 
20,000 feet.
* * * * *

0
3. In Sec.  203.1, the introductory text and paragraph (b) are revised, 
and new paragraph (d) is added to read as follows:


Sec.  203.1  What is MMS's authority to grant royalty relief?

    The Outer Continental Shelf (OCS) Lands Act, 43 U.S.C. 1337, as 
amended by the OCS Deep Water Royalty Relief Act (DWRRA), Public Law 
104-58 and the Energy Policy Act of 2005, Public Law 109-058 authorizes 
us to grant royalty relief in four situations.
* * * * *
    (b) Under 43 U.S.C. 1337(a)(3)(B), we may reduce, modify, or 
eliminate any royalty or net profit share to promote development, 
increase production, or encourage production of marginal resources on 
certain leases or categories of leases. This authority is restricted to 
leases in the GOM that are west of 87 degrees, 30 minutes West 
longitude, and in the planning areas offshore Alaska.
* * * * *
    (d) Under 42 U.S.C. 15904-15905, we may suspend royalties for 
designated volumes of gas production from deep and ultra-deep wells on 
a lease if:
    (1) Your lease is in shallow water (water less than 400 meters 
deep) and you produce from an ultra-deep well (top of the perforated 
interval is at least 20,000 feet TVD SS) or your lease is in waters 
entirely more than 200 meters and entirely less than 400 meters deep 
and you produce from a deep well (top of the perforated interval is at 
least 15,000 feet TVD SS);
    (2) Your lease is in the designated area of the GOM (wholly west of 
87 degrees, 30 minutes west longitude); and
    (3) Your lease is not eligible for deep water royalty relief.

0
4. In Sec.  203.2, the section heading and paragraphs (b), (d), and (e) 
are revised, and new paragraphs (f), (g), and (h) are added to read as 
follows:


Sec.  203.2  How can I obtain royalty relief?

* * * * *

------------------------------------------------------------------------
                                                       Then we may grant
    If you have a lease . . .      And if you . . .        you . . .
------------------------------------------------------------------------
 
                              * * * * * * *
(b) Located in a designated GOM   Propose an          A royalty
 deep water area (i.e., 200        expansion project   suspension for a
 meters or greater) and acquired   and can             minimum
 in a lease sale held before       demonstrate your    production volume
 November 28, 1995, or after       project is          plus any
 November 28, 2000.                uneconomic          additional
                                   without royalty     production large
                                   relief.             enough to make
                                                       the project
                                                       economic (see
                                                       Sec.  Sec.
                                                       203.60 through
                                                       203.79).
 
                              * * * * * * *
(d) Located in a designated GOM   Propose a           A royalty
 deep water area and acquired in   development         suspension for a
 a lease sale held after           project and can     minimum
 November 28, 2000.                demonstrate that    production volume
                                   the suspension      plus any
                                   volume, if any,     additional volume
                                   for your lease is   needed to make
                                   not enough to       your project
                                   make development    economic (see
                                   economic.           Sec.  Sec.
                                                       203.60 through
                                                       203.79).
(e) Where royalty relief would    Are not eligible    A royalty
 recover significant additional    to apply for end-   modification in
 resources or, offshore Alaska     of-life or deep     size, duration,
 or in certain areas of the GOM,   water royalty       or form that
 would enable development.         relief, but show    makes your lease
                                   us you meet         or project
                                   certain             economic (see
                                   eligibility         Sec.   203.80).
                                   conditions.
(f) Located in a designated GOM   Drill a deep well   A royalty
 shallow water area and acquired   on a lease that     suspension for a
 in a lease sale held before       is not eligible     volume of gas
 January 1, 2001, or after         for deep water      produced from
 January 1, 2004, or have          royalty relief      successful deep
 exercised an option to            and you have not    and ultra-deep
 substitute for royalty relief     previously          wells, or, for
 in your lease terms.              produced oil or     certain
                                   gas from a deep     unsuccessful deep
                                   well or an ultra-   and ultra-deep
                                   deep well.          wells, a smaller
                                                       royalty
                                                       suspension for a
                                                       volume of gas or
                                                       oil produced by
                                                       all wells on your
                                                       lease (see Sec.
                                                       Sec.   203.40
                                                       through 203.49).
(g) Located in a designated GOM   Drill and produce   A royalty
 shallow water area.               gas from an ultra-  suspension for a
                                   deep well on a      volume of gas
                                   lease that is not   produced from
                                   eligible for deep   successful ultra-
                                   water royalty       deep and deep
                                   relief and you      wells on your
                                   have not            lease (see Sec.
                                   previously          Sec.   203.30
                                   produced oil or     through 203.36).
                                   gas from an ultra-
                                   deep well.
(h) Located in planning areas     Propose an          A royalty
 offshore Alaska.                  expansion project   suspension for a
                                   or propose a        minimum
                                   development         production volume
                                   project and can     plus any
                                   demonstrate that    additional volume
                                   the project is      needed to make
                                   uneconomic          your project
                                   without relief or   economic (see
                                   that the            Sec.  Sec.
                                   suspension          203.60, 203.62,
                                   volume, if any,     203.67 through
                                   for your lease is   203.70, Sec.
                                   not enough to       Sec.   203.73 and
                                   make development    203.76 through
                                   economic.           203.79).
------------------------------------------------------------------------


0
5. A new undesignated center heading and new Sec. Sec.  203.30 through 
203.36 are added to subpart B to read as follows:

Royalty Relief for Drilling Ultra-Deep Wells on Leases Not Subject to 
Deep Water Royalty Relief

Sec.
203.30 Which leases are eligible for royalty relief as a result of 
drilling a phase 2 or phase 3 ultra-deep well?
203.31 If I have a qualified phase 2 or qualified phase 3 ultra-deep 
well, what royalty relief would that well earn for my lease?
203.32 What other requirements or restrictions apply to royalty 
relief for a qualified phase 2 or phase 3 ultra-deep well?
203.33 To which production do I apply the RSV earned by qualified 
phase 2 and phase 3 ultra-deep wells on my lease or in my unit?
203.34 To which production may an RSV earned by qualified phase 2 
and phase 3 ultra-deep wells on my lease not be applied?
203.35 What administrative steps must I take to use the RSV earned 
by a qualified phase 2 or phase 3 ultra-deep well?
203.36 Do I keep royalty relief if prices rise significantly?

[[Page 69507]]

Royalty Relief for Drilling Ultra-Deep Wells on Leases Not Subject to 
Deep Water Royalty Relief


Sec.  203.30  Which leases are eligible for royalty relief as a result 
of drilling a phase 2 or phase 3 ultra-deep well?

    Your lease may receive a royalty suspension volume (RSV) under 
Sec. Sec.  203.31 through 203.36 if the lease meets all the 
requirements of this section.
    (a) The lease is located in the GOM wholly west of 87 degrees, 30 
minutes West longitude in water depths entirely less than 400 meters 
deep.
    (b) The lease has not produced gas or oil from a deep well or an 
ultra-deep well, except as provided in Sec.  203.31(b).
    (c) If the lease is located entirely in more than 200 meters and 
entirely less than 400 meters of water, it must either:
    (1) Have been issued before November 28, 1995, and not been granted 
deep water royalty relief under 43 U.S.C. 1337(a)(3)(C), added by 
section 302 of the Deep Water Royalty Relief Act; or
    (2) Have been issued after November 28, 2000, and not been granted 
deep water royalty relief under Sec. Sec.  203.60 through 203.79.


Sec.  203.31  If I have a qualified phase 2 or qualified phase 3 ultra-
deep well, what royalty relief would that well earn for my lease?

    (a) Subject to the administrative requirements of Sec.  203.35 and 
the price conditions in Sec.  203.36, your qualified well earns your 
lease an RSV shown in the following table in billions of cubic feet 
(BCF) or in thousands of cubic feet (MCF) as prescribed in Sec.  
203.33:

------------------------------------------------------------------------
 If you have a qualified phase 2 or
 qualified phase 3 ultra-deep well     Then your lease earns an RSV on
              that is:                  this volume of gas production:
------------------------------------------------------------------------
(1) An original well,                35 BCF.
(2) A sidetrack with a sidetrack     35 BCF.
 measured depth of at least 20,000
 feet,
(3) An ultra-deep short sidetrack    4 BCF plus 600 MCF times sidetrack
 that is a phase 2 ultra-deep well,   measured depth (rounded to the
                                      nearest 100 feet) but no more than
                                      25 BCF.
(4) An ultra-deep short sidetrack    0 BCF.
 that is a phase 3 ultra-deep well,
------------------------------------------------------------------------

    (b)(1) This paragraph applies if your lease:
    (i) Has produced gas or oil from a deep well with a perforated 
interval the top of which is less than 18,000 feet TVD SS;
    (ii) Was issued in a lease sale held between January 1, 2004, and 
December 31, 2005; and
    (iii) The terms of your lease expressly incorporate the provisions 
of Sec. Sec.  203.41 through 203.47 as they existed at the time the 
lease was issued.
    (2) Subject to the administrative requirements of Sec.  203.35 and 
the price conditions in Sec.  203.36, your qualified well earns your 
lease an RSV shown in the following table in BCF or MCF as prescribed 
in Sec.  203.33:

------------------------------------------------------------------------
  If you have a qualified phase 2      Then your lease earns an RSV on
   ultra-deep well that is . . .        this volume of gas production:
------------------------------------------------------------------------
(i) An original well or a sidetrack  10 BCF.
 with a sidetrack measured depth of
 at least 20,000 feet TVD SS,
(ii) An ultra-deep short sidetrack,  4 BCF plus 600 MCF times sidetrack
                                      measured depth (rounded to the
                                      nearest 100 feet) but no more than
                                      10 BCF.
------------------------------------------------------------------------

    (c) Lessees may request a refund of or recoup royalties paid on 
production from qualified phase 2 or phase 3 ultra-deep wells that:
    (1) Occurs before December 18, 2008 and
    (2) Is subject to application of an RSV under either Sec.  203.31 
or Sec.  203.41.
    (d) The following examples illustrate how this section applies. 
These examples assume that your lease is located in the GOM west of 87 
degrees, 30 minutes West longitude and in water less than 400 meters 
deep (see Sec.  203.30(a)), has no existing deep or ultra-deep wells 
and that the price thresholds prescribed in Sec.  203.36 have not been 
exceeded.

    Example 1: In 2008, you drill and begin producing from an ultra-
deep well with a perforated interval the top of which is 25,000 feet 
TVD SS, and your lease has had no prior production from a deep or 
ultra-deep well. Assuming your lease has no deepwater royalty relief 
(see Sec.  203.30(c)), your lease is eligible (according to Sec.  
203.30(b)) to earn an RSV under Sec.  203.31 because it has not yet 
produced from a deep well. Your lease earns an RSV of 35 BCF under 
this section when this well begins producing. According to Sec.  
203.31(a), your 25,000 foot well qualifies your lease for this RSV 
because the well was drilled after the relief authorized here became 
effective (when the proposed version of this rule was published on 
May 18, 2007) and produced from an interval that meets the criteria 
for an ultra-deep well (i.e., is a phase 2 ultra-deep well as 
defined in Sec.  203.0). Then in 2014, you drill and produce from 
another ultra-deep well with a perforated interval the top of which 
is 29,000 feet TVD SS. Your lease earns no additional RSV under this 
section when this second ultra-deep well produces, because your 
lease no longer meets the condition in Sec.  203.30(b)) of no 
production from a deep well. However, any remaining RSV earned by 
the first ultra-deep well on your lease would be applied to 
production from both the first and the second ultra-deep wells as 
prescribed in Sec.  203.33(a)(2), or Sec.  203.33(b)(2) if your 
lease is part of a unit.
    Example 2: In 2005, you spudded and began producing from an 
ultra-deep well with a perforated interval the top of which is 
23,000 feet TVD SS. Your lease earns no RSV under this section from 
this phase 1 ultra-deep well (as defined in Sec.  203.0) because you 
spudded the well before the publication date (May 18, 2007) of the 
proposed rule when royalty relief under Sec.  203.31(a) became 
effective. However, this ultra-deep well may earn an RSV of 25 BCF 
for your lease under Sec.  203.41 (that became effective May 3, 
2004), if the lease is located in water depths partly or entirely 
less than 200 meters and has not previously produced from a deep 
well (Sec.  203.30(b)).
    Example 3: In 2000, you began producing from a deep well with a 
perforated interval the top of which is 16,000 feet TVD SS and your 
lease is located in water 100 meters deep. Then in 2008, you drill 
and produce from a new ultra-deep well with a perforated interval 
the top of which is 24,000 feet TVD SS. Your lease earns no RSV 
under either this section or Sec.  203.41 because the 16,000-foot 
well was drilled before we offered any way to earn an RSV for 
producing from a deep well (see dates in the definition of qualified 
well in Sec.  203.0) and because the existence of the 16,000-foot 
well means the lease is not eligible (see Sec.  203.30(b)) to earn 
an RSV for the 24,000-foot well. Because the lease existed in the 
year 2000, it cannot be eligible for the exception to this 
eligibility condition provided in Sec.  203.31(b).
    Example 4: In 2008, you spud and produce from an ultra-deep well 
with a perforated interval the top of which is 22,000 feet TVD SS, 
your lease is located in water 300 meters deep, and your lease has 
had no previous

[[Page 69508]]

production from a deep or ultra-deep well. Your lease earns an RSV 
of 35 BCF under this section when this well begins producing because 
your lease meets the conditions in Sec.  203.30 and the well fits 
the definition of a phase 2 ultra-deep well (in Sec.  203.0). Then 
in 2010, you spud and produce from a deep well with a perforated 
interval the top of which is 16,000 feet TVD SS. Your 16,000-foot 
well earns no RSV because it is on a lease that already has a 
producing well at least 18,000 feet subsea (see Sec.  203.42(a)), 
but any remaining RSV earned by the ultra-deep well would also be 
applied to production from the deep well as prescribed in Sec.  
203.33(a)(2), or Sec.  203.33(b)(2) if your lease is part of a unit 
and Sec.  203.43(a)(2), or Sec.  203.43(b)(2) if your lease is part 
of a unit. However, if the 16,000-foot deep well does not begin 
production until 2016 (or if your lease were located in water less 
than 200 meters deep), then the 16,000-foot well would not be a 
qualified deep well because this well does not begin production 
within the interval specified in the definition of a qualified well 
in Sec.  203.0, and the RSV earned by the ultra-deep well would not 
be applied to production from this (unqualified) deep well.
    Example 5: In 2008, you spud a deep well with a perforated 
interval the top of which is 17,000 feet TVD SS that becomes a 
qualified well and earns an RSV of 15 BCF under Sec.  203.41 when it 
begins producing. Then in 2011, you spud an ultra-deep well with a 
perforated interval the top of which is 26,000 feet TVD SS. Your 
26,000-foot well becomes a qualified ultra-deep well because it 
meets the date and depth conditions in this definition under Sec.  
203.0 when it begins producing, but your lease earns no additional 
RSV under this section or Sec.  203.41 because it is on a lease that 
already has production from a deep well (see Sec.  203.30(b)). Both 
the qualified deep well and the qualified ultra-deep well would 
share your lease's total RSV of 15 BCF in the manner prescribed in 
Sec. Sec.  203.33 and 203.43.
    Example 6: In 2008, you spud a qualified ultra-deep well that is 
a sidetrack with a sidetrack measured depth of 21,000 feet and a 
perforated interval the top of which is 25,000 feet TVD SS. This 
well meets the definition of an ultra-deep well but is too long to 
be classified an ultra-deep short sidetrack in Sec.  203.0. If your 
lease is located in 150 meters of water and has not previously 
produced from a deep well, your lease earns an RSV of 35 BCF because 
it was drilled after the effective date for earning this RSV. 
Further, this RSV applies to gas production from this and any future 
qualified deep and qualified ultra-deep wells on your lease, as 
prescribed in Sec.  203.33. The absence of an expiration date for 
earning an RSV on an ultra-deep well means this long sidetrack well 
becomes a qualified well whenever it starts production. If your 
sidetrack has a sidetrack measured depth of 14,000 feet and begins 
production in March 2009, it earns an RSV of 12.4 BCF under this 
section because it meets the definitions of a phase 2 ultra-deep 
well (production begins before the expiration date for the pre-
existing relief in its water depth category) and an ultra-deep short 
sidetrack in Sec.  203.0. However, if it does not begin production 
until 2010, it earns no RSV because it is too short as a phase 3 
ultra-deep well to be a qualified ultra-deep well.
    Example 7: Your lease was issued in June 2004 and expressly 
incorporates the provisions of Sec. Sec.  203.41 through 203.47 as 
they existed at that time. In January 2005, you spud a deep well 
(well no. 1) with a perforated interval the top of which is 16,800 
feet TVD SS that becomes a qualified well and earns an RSV of 15 BCF 
under Sec.  203.41 when it begins producing. Then in February 2008, 
you spud an ultra-deep well (well no. 2) with a perforated interval 
the top of which is 22,300 feet that begins producing in November 
2008, after well no. 1 has started production. Well no. 2 earns your 
lease an additional RSV of 10 BCF under paragraph (b) of this 
section because it begins production in time to be classified as a 
phase 2 ultra-deep well. If, on the other hand, well no. 2 had begun 
producing in June 2009, it would earn no additional RSV for the 
lease because it would be classified as a phase 3 ultra-deep well 
and thus is not entitled to the exception under paragraph (b) of 
this section.


Sec.  203.32  What other requirements or restrictions apply to royalty 
relief for a qualified phase 2 or phase 3 ultra-deep well?

    (a) If a qualified ultra-deep well on your lease is within a 
unitized portion of your lease, the RSV earned by that well under this 
section applies only to your lease and not to other leases within the 
unit or to the unit as a whole.
    (b) If your qualified ultra-deep well is a directional well (either 
an original well or a sidetrack) drilled across a lease line, then 
either:
    (1) The lease with the perforated interval that initially produces 
earns the RSV or
    (2) If the perforated interval crosses a lease line, the lease 
where the surface of the well is located earns the RSV.
    (c) Any RSV earned under Sec.  203.31 is in addition to any royalty 
suspension supplement (RSS) for your lease under Sec.  203.45 that 
results from a different wellbore.
    (d) If your lease earns an RSV under Sec.  203.31 and later 
produces from a deep well that is not a qualified well, the RSV is not 
forfeited or terminated, but you may not apply the RSV earned under 
Sec.  203.31 to production from the non-qualified well.
    (e) You owe minimum royalties or rentals in accordance with your 
lease terms notwithstanding any RSVs allowed under paragraphs (a) and 
(b) of Sec.  203.31.
    (f) Unused RSVs transfer to a successor lessee and expire with the 
lease.


Sec.  203.33  To which production do I apply the RSV earned by 
qualified phase 2 and phase 3 ultra-deep wells on my lease or in my 
unit?

    (a) You must apply the RSV allowed in Sec.  203.31(a) and (b) to 
gas volumes produced from qualified wells on or after May 18, 2007, 
reported on the Oil and Gas Operations Report, Part A (OGOR-A) for your 
lease under Sec.  216.53. All gas production from qualified wells 
reported on the OGOR-A, including production not subject to royalty, 
counts toward the total lease RSV earned by both deep or ultra-deep 
wells on the lease.

    (b) This paragraph applies to any lease with a qualified phase 2 or 
phase 3 ultra-deep well that is not within an MMS-approved unit. 
Subject to the price conditions of Sec.  203.36, you must apply the RSV 
prescribed in Sec.  203.31 as required under the following paragraphs 
(b)(1) and (b)(2) of this section.
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of May 18, 2007, or the date the first qualified 
phase 2 or phase 3 ultra-deep well that earns your lease the RSV begins 
production (other than test production).
    (2) You must apply the RSV to only gas production from qualified 
wells on your lease, regardless of their depth, for which you have met 
the requirements in Sec.  203.35 or Sec.  203.44.
    (c) This paragraph applies to any lease with a qualified phase 2 or 
phase 3 ultra-deep well where all or part of the lease is within an 
MMS-approved unit. Under the unit agreement, a share of the production 
from all the qualified wells in the unit participating area would be 
allocated to your lease each month according to the participating area 
percentages. Subject to the price conditions of Sec.  203.36, you must 
apply the RSV prescribed in Sec.  203.31 as follows:
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of May 18, 2007, or the date that the first 
qualified phase 2 or phase 3 ultra-deep well that earns your lease the 
RSV begins production (other than test production).
    (2) You must apply the RSV to only gas production:
    (i) From qualified wells on the non-unitized area of your lease, 
regardless of their depth, for which you have met the requirements in 
Sec.  203.35 or Sec.  203.44; and
    (ii) Allocated to your lease under an MMS-approved unit agreement 
from qualified wells on unitized areas of your lease and on other 
leases in participating areas of the unit,

[[Page 69509]]

regardless of their depth, for which the requirements in Sec.  203.35 
or Sec.  203.44 have been met. The allocated share under paragraph 
(a)(2)(ii) of this section does not increase the RSV for your lease.

    Example: The east half of your lease A is unitized with all of 
lease B. There is one qualified phase 2 ultra-deep well on the non-
unitized portion of lease A that earns lease A an RSV of 35 BCF 
under Sec.  203.31, one qualified deep well on the unitized portion 
of lease A (drilled after the ultra-deep well on the non-unitized 
portion of that lease) and a qualified phase 2 ultra-deep well on 
lease B that earns lease B a 35 BCF RSV under Sec.  203.31. The 
participating area percentages allocate 40 percent of production 
from both of the unit qualified wells to lease A and 60 percent to 
lease B. If the non-unitized qualified phase 2 ultra-deep well on 
lease A produces 12 BCF, and the unitized qualified well on lease A 
produces 18 BCF, and the qualified well on lease B produces 37 BCF, 
then the production volume from and allocated to lease A to which 
the lease A RSV applies is 34 BCF [12 + (18 + 37)(0.40)]. The 
production volume allocated to lease B to which the lease B RSV 
applies is 33 BCF [(18 + 37)(0.60)]. None of the volumes produced 
from a well that is not within a unit participating area may be 
allocated to other leases in the unit.

    (d) You must begin paying royalties when the cumulative production 
of gas from all qualified wells on your lease, or allocated to your 
lease under paragraph (b) of this section, reaches the applicable RSV 
allowed under Sec.  203.31 or Sec.  203.41. For the month in which 
cumulative production reaches this RSV, you owe royalties on the 
portion of gas production from or allocated to your lease that exceeds 
the RSV remaining at the beginning of that month.


Sec.  203.34  To which production may an RSV earned by qualified phase 
2 and phase 3 ultra-deep wells on my lease not be applied?

    You may not apply an RSV earned under Sec.  203.31:
    (a) To production from completions less than 15,000 feet TVD SS, 
except in cases where the qualified well is re-perforated in the same 
reservoir previously perforated deeper than 15,000 feet TVD SS;
    (b) To production from a deep well or ultra-deep well on any other 
lease, except as provided in paragraph (c) of Sec.  203.33;
    (c) To any liquid hydrocarbon (oil and condensate) volumes; or
    (d) To production from a deep well or ultra-deep well that 
commenced drilling before:
    (1) March 26, 2003, on a lease that is located entirely or partly 
in water less than 200 meters deep; or
    (2) May 18, 2007, on a lease that is located entirely in water more 
than 200 meters deep.


Sec.  203.35  What administrative steps must I take to use the RSV 
earned by a qualified phase 2 or phase 3 ultra-deep well?

    To use an RSV earned under Sec.  203.31:
    (a) You must notify the MMS Regional Supervisor for Production and 
Development in writing of your intent to begin drilling operations on 
all your ultra-deep wells.
    (b) Before beginning production, you must meet any production 
measurement requirements that the MMS Regional Supervisor for 
Production and Development has determined are necessary under 30 CFR 
Part 250, Subpart L.
    (c)(1) Within 30 days of the beginning of production from any wells 
that would become qualified phase 2 or phase 3 ultra-deep wells by 
satisfying the requirements of this section:
    (i) Provide written notification to the MMS Regional Supervisor for 
Production and Development that production has begun; and
    (ii) Request confirmation of the size of the RSV earned by your 
lease.
    (2) If you produced from a qualified phase 2 or phase 3 ultra-deep 
well before December 18, 2008, you must provide the information in 
paragraph (c)(1) of this section no later than January 20, 2009.
    (d) If you cannot produce from a well that otherwise meets the 
criteria for a qualified phase 2 ultra-deep well that is an ultra-deep 
short sidetrack before May 3, 2009, on a lease that is located entirely 
or partly in water less than 200 meters deep, or before May 3, 2013, on 
a lease that is located entirely in water more than 200 meters but less 
than 400 meters deep, the MMS Regional Supervisor for Production and 
Development may extend the deadline for beginning production for up to 
1 year, based on the circumstances of the particular well involved, if 
it meets all the following criteria.
    (1) The delay occurred after drilling reached the total depth in 
your well.
    (2) Production (other than test production) was expected to begin 
from the well before May 3, 2009, on a lease that is located entirely 
or partly in water less than 200 meters deep or before May 3, 2013, on 
a lease that is located entirely in water more than 200 meters but less 
than 400 meters deep. You must provide a credible activity schedule 
with supporting documentation.
    (3) The delay in beginning production is for reasons beyond your 
control, such as adverse weather and accidents which MMS deems were 
unavoidable.


Sec.  203.36  Do I keep royalty relief if prices rise significantly?

    (a) You must pay royalties on all gas production to which an RSV 
otherwise would be applied under Sec.  203.33 for any calendar year in 
which the average daily closing New York Mercantile Exchange (NYMEX) 
natural gas price exceeds the applicable threshold price shown in the 
following table.

----------------------------------------------------------------------------------------------------------------
 A price threshold in year 2007 dollars of .
                     . .                                               Applies to . . .
----------------------------------------------------------------------------------------------------------------
 (1) $10.15 per MMBtu.......................   (i) The first 25 BCF of RSV earned under Sec.   203.31(a) by a
                                               phase 2 ultra-deep well on a lease that is located in water
                                               partly or entirely less than 200 meters deep issued before
                                               December 18, 2008; and
                                              (ii) Any RSV earned under Sec.   203.31(b) by a phase 2 ultra-deep
                                               well.
 (2) $4.55 per MMBtu........................   (i) Any RSV earned under Sec.   203.31(a) by a phase 3 ultra-deep
                                               well unless the lease terms prescribe a different price
                                               threshold;
                                              (ii) The last 10 BCF of the 35 BCF of RSV earned under Sec.
                                               203.31(a) by a phase 2 ultra-deep well on a lease that is located
                                               in water partly or entirely less than 200 meters deep issued
                                               before December 18, 2008 and that is not a non-converted lease;
                                              (iii) The last 15 BCF of the 35 BCF of RSV earned under Sec.
                                               203.31(a) by a phase 2 ultra-deep well on a non-converted lease;
                                              (iv) Any RSV earned under Sec.   203.31(a) by a phase 2 ultra-deep
                                               well on a lease in water partly or entirely less than 200 meters
                                               deep issued on or after December 18, 2008 unless the lease terms
                                               prescribe a different price threshold; and
                                              (v) Any RSV earned under Sec.   203.31(a) by a phase 2 ultra-deep
                                               well on a lease in water entirely more than 200 meters deep and
                                               entirely less than 400 meters deep.

[[Page 69510]]

 
 (3) $4.08 per MMBtu........................   (i) The first 20 BCF of RSV earned by a well that is located on a
                                               non-converted lease issued in OCS Lease Sale 178.
 (4) $5.83 per MMBtu........................   (i) The first 20 BCF of RSV earned by a well that is located on a
                                               non-converted lease issued in OCS Lease Sales 180, 182, 184, 185,
                                               or 187.
----------------------------------------------------------------------------------------------------------------

    (b) For purposes of paragraph (a) of this section, determine the 
threshold price for any calendar year after 2007 by:
    (1) Determining the percentage of change during the year in the 
Department of Commerce's implicit price deflator for the gross domestic 
product; and
    (2) Adjusting the threshold price for the previous year by that 
percentage.
    (c) The following examples illustrate how this section applies.

    Example 1: Assume that a lessee drills and begins producing from 
a qualified phase 2 ultra-deep well in 2008 on a lease issued in 
2004 in less than 200 meters of water that earns the lease an RSV of 
35 BCF. Further, assume the well produces a total of 18 BCF by the 
end of 2009 and in both of those years, the average daily NYMEX 
closing natural gas price is less than $10.15 (adjusted for 
inflation after 2007). The lessee does not pay royalty on the 18 BCF 
because the gas price threshold under paragraph (a)(1) of this 
section applies to the first 25 BCF of this RSV earned by this phase 
2 ultra-deep well. In 2010, the well produces another 13 BCF. In 
that year, the average daily closing NYMEX natural gas price is 
greater than $4.55 per MMBtu (adjusted for inflation after 2007), 
but less than $10.15 per MMBtu (adjusted for inflation after 2007). 
The first 7 BCF produced in 2010 will exhaust the first 25 BCF (that 
is subject to the $10.15 threshold) of the 35 BCF RSV that the well 
earned. The lessee must pay royalty on the remaining 6 BCF produced 
in 2010, because it is subject to the $4.55 per MMBtu threshold 
under paragraph (a)(2)(ii) of this section which was exceeded.
    Example 2: Assume that a lessee:
    (1) Drills and produces from well no.1, a qualified deep well in 
2008 to a depth of 15,500 feet TVD SS that earns a 15 BCF RSV for 
the lease under Sec.  203.41, which would be subject to a price 
threshold of $10.15 per MMBtu (adjusted for inflation after 2007), 
meaning the lease is partly or entirely in less than 200 meters of 
water;
    (2) Later in 2008 drills and produces from well no. 2, a second 
qualified deep well to a depth of 17,000 feet TVD SS that earns no 
additional RSV (see Sec.  203.41(c)(1)); and
    (3) In 2015, drills and produces from well no. 3, a qualified 
phase 3 ultra-deep well that earns no additional RSV since the lease 
already has an RSV established by prior deep well production. 
Further assume that in 2015, the average daily closing NYMEX natural 
gas price exceeds $4.55 per MMBtu (adjusted for inflation after 
2007) but does not exceed $10.15 per MMBtu (adjusted for inflation 
after 2007). In 2015, any remaining RSV earned by well no. 1 (which 
would have been applied to production from well nos. 1 and 2 in the 
intervening years), would be applied to production from all three 
qualified wells. Because the price threshold applicable to that RSV 
was not exceeded, the production from all three qualified wells 
would be royalty-free until the 15 BCF RSV earned by well no. 1 is 
exhausted.
    Example 3: Assume the same initial facts regarding the three 
wells as in Example 2. Further assume that well no. 1 stopped 
producing in 2011 after it had produced 8 BCF, and that well no. 2 
stopped producing in 2012 after it had produced 5 BCF. Two BCF of 
the RSV earned by well no. 1 remain. That RSV would be applied to 
production from well no. 3 until it is exhausted, and the lessee 
therefore would not pay royalty on those 2 BCF produced in 2015, 
because the $10.15 per MMBtu (adjusted for inflation after 2007) 
price threshold is not exceeded. The determination of which price 
threshold applies to deep gas production depends on when the first 
qualified well earned the RSV for the lease, not on which wells use 
the RSV.
    Example 4: Assume that in February 2010 a lessee completes and 
begins producing from an ultra-deep well (at a depth of 21,500 feet 
TVD SS) on a lease located in 325 meters of water with no prior 
production from any deep well and no deep water royalty relief. The 
ultra-deep well would be a phase 2 ultra-deep well (see definition 
in Sec.  203.0), and would earn the lease an RSV of 35 BCF under 
Sec. Sec.  203.30 and 203.31. Further assume that the average daily 
closing NYMEX natural gas price exceeds $4.55 per MMBtu (adjusted 
for inflation after 2007) but does not exceed $10.15 per MMBtu 
(adjusted for inflation after 2007) during 2010. Because the lease 
is located in more than 200 but less than 400 meters of water, the 
$4.55 per MMBtu price threshold applies to the whole RSV (see 
paragraph (a)(2)(v) of this section), and the lessee will owe 
royalty on all gas produced from the ultra-deep well in 2010.

    (d) You must pay any royalty due under this section no later than 
March 31 of the year following the calendar year for which you owe 
royalty. If you do not pay by that date, you must pay late payment 
interest under Sec.  218.54 from April 1 until the date of payment.
    (e) Production volumes on which you must pay royalty under this 
section count as part of your RSV.

0
6. Revise Sec. Sec.  203.40 and 203.41 to read as follows:


Sec.  203.40  Which leases are eligible for royalty relief as a result 
of drilling a deep well or a phase 1 ultra-deep well?

    Your lease may receive an RSV under Sec. Sec.  203.41 through 
203.44, and may receive an RSS under Sec. Sec.  203.45 through 203.47, 
if it meets all the requirements of this section.
    (a) The lease is located in the GOM wholly west of 87 degrees, 30 
minutes West longitude in water depths entirely less than 400 meters 
deep.
    (b) The lease has not produced gas or oil from a well with a 
perforated interval the top of which is 18,000 feet TVD SS or deeper 
that commenced drilling either:
    (1) Before March 26, 2003, on a lease that is located partly or 
entirely in water less than 200 meters deep; or
    (2) Before May 18, 2007, on a lease that is located in water 
entirely more than 200 meters and entirely less than 400 meters deep.
    (c) In the case of a lease located partly or entirely in water less 
than 200 meters deep, the lease was issued in a lease sale held either:
    (1) Before January 1, 2001;
    (2) On or after January 1, 2001, and before January 1, 2004, and, 
in cases where the original lease terms provided for an RSV for deep 
gas production, the lessee has exercised the option provided for in 
Sec.  203.49; or
    (3) On or after January 1, 2004, and the lease terms provide for 
royalty relief under Sec. Sec.  203.41 through 203.47 of this part. 
(Note: Because the original Sec.  203.41 has been divided into new 
Sec. Sec.  203.41 and 203.42 and subsequent sections have been 
redesignated as Sec. Sec.  203.43 through 203.48, royalty relief in 
lease terms for leases issued on or after January 1, 2004, should be 
read as referring to Sec. Sec.  203.41 through 203.48.)
    (d) If the lease is located entirely in more than 200 meters and 
less than 400 meters of water, it must either:
    (1) Have been issued before November 28, 1995, and not been granted 
deep water royalty relief under 43 U.S.C. 1337(a)(3)(C), added by 
section 302 of the Deep Water Royalty Relief Act; or
    (2) Have been issued after November 28, 2000, and not been granted 
deep water royalty relief under Sec. Sec.  203.60 through 203.79.


Sec.  203.41  If I have a qualified deep well or a qualified phase 1 
ultra-deep well, what royalty relief would my lease earn?

    (a) To qualify for a suspension volume under paragraphs (b) or (c) 
of this section, your lease must meet the

[[Page 69511]]

requirements in Sec.  203.40 and the requirements in the following 
table.

------------------------------------------------------------------------
                               And if it later . .   Then your lease . .
 If your lease has not . . .            .                     .
------------------------------------------------------------------------
(1) produced gas or oil from  has a qualified deep  earns an RSV
 any deep well or ultra-deep   well or qualified     specified in
 well,                         phase 1 ultra-deep    paragraph (b) of
                               well,.                this section.
(2) produced gas or oil from  has a qualified deep  earns an RSV
 a well with a perforated      well with a           specified in
 interval whose top is         perforated interval   paragraph (c) of
 18,000 feet TVD SS or         whose top is 18,000   this section.
 deeper,                       feet TVD SS or
                               deeper or a
                               qualified phase 1
                               ultra-deep well,.
------------------------------------------------------------------------

    (b) If your lease meets the requirements in paragraph (a)(1) of 
this section, it earns the RSV prescribed in the following table:

------------------------------------------------------------------------
 If you have a qualified deep well
 or a qualified phase 1 ultra-deep     Then your lease earns an RSV on
           well that is:                this volume of gas production:
------------------------------------------------------------------------
(1) An original well with a          15 BCF.
 perforated interval the top of
 which is from 15,000 to less than
 18,000 feet TVD SS,
(2) A sidetrack with a perforated    4 BCF plus 600 MCF times sidetrack
 interval the top of which is from    measured depth (rounded to the
 15,000 to less than 18,000 feet      nearest 100 feet) but no more than
 TVD SS,                              15 BCF.
(3) An original well with a          25 BCF.
 perforated interval the top of
 which is at least 18,000 feet TVD
 SS,
(4) A sidetrack with a perforated    4 BCF plus 600 MCF times sidetrack
 interval the top of which is at      measured depth (rounded to the
 least 18,000 feet TVD SS,            nearest 100 feet) but no more than
                                      25 BCF.
------------------------------------------------------------------------

    (c) If your lease meets the requirements in paragraph (a)(2) of 
this section, it earns the RSV prescribed in the following table. The 
RSV specified in this paragraph is in addition to any RSV your lease 
already may have earned from a qualified deep well with a perforated 
interval whose top is from 15,000 feet to less than 18,000 feet TVD SS.

----------------------------------------------------------------------------------------------------------------
 If you have a qualified deep well or a qualified
       phase 1 ultra-deep well that is . . .           Then you earn an RSV on this amount of gas production:
----------------------------------------------------------------------------------------------------------------
(1) An original well or a sidetrack with a          0 BCF.
 perforated interval the top of which is from
 15,000 to less than 18,000 feet TVD SS,
(2) An original well with a perforated interval     10 BCF.
 the top of which is 18,000 feet TVD SS or deeper,
(3) A sidetrack with a perforated interval the top  4 BCF plus 600 MCF times sidetrack measured depth (rounded
 of which is 18,000 feet TVD SS or deeper,           to the nearest 100 feet) but no more than 10 BCF.
----------------------------------------------------------------------------------------------------------------

    (d) Lessees may request a refund of or recoup royalties paid on 
production from qualified wells on a lease that is located in water 
entirely deeper than 200 meters but entirely less than 400 meters deep 
that:
    (1) Occurs before December 18, 2008; and
    (2) Is subject to application of an RSV under either Sec.  203.31 
or Sec.  203.41.
    (e) The following examples illustrate how this section applies, 
assuming your lease meets the location, prior production, and lease 
issuance conditions in Sec.  203.40 and paragraph (a) of this section:

    Example 1: If you have a qualified deep well that is an original 
well with a perforated interval the top of which is 16,000 feet TVD 
SS, your lease earns an RSV of 15 BCF under paragraph (b)(1) of this 
section. This RSV must be applied to gas production from all 
qualified wells on your lease, as prescribed in Sec. Sec.  203.43 
and 203.48. However, if the top of the perforated interval is 18,500 
feet TVD SS, the RSV is 25 BCF according to paragraph (b)(3) of this 
section.
    Example 2: If you have a qualified deep well that is a 
sidetrack, with a perforated interval the top of which is 16,000 
feet TVD SS and a sidetrack measured depth of 6,789 feet, we round 
the measured depth to 6,800 feet and your lease earns an RSV of 8.08 
BCF under paragraph (b)(2) of this section. This RSV would be 
applied to gas production from all qualified wells on your lease, as 
prescribed in Sec. Sec.  203.43 and 203.48.
    Example 3: If you have a qualified deep well that is a 
sidetrack, with a perforated interval the top of which is 16,000 
feet TVD SS and a sidetrack measured depth of 19,500 feet, your 
lease earns an RSV of 15 BCF. This RSV would be applied to gas 
production from all qualified wells on your lease, as prescribed in 
Sec. Sec.  203.43 and 203.48, even though 4 BCF plus 600 MCF per 
foot of sidetrack measured depth equals 15.7 BCF because paragraph 
(b)(2) of this section limits the RSV for a sidetrack at the amount 
an original well to the same depth would earn.
    Example 4: If you have drilled and produced a deep well with a 
perforated interval the top of which is 16,000 feet TVD SS before 
March 26, 2003 (and the well therefore is not a qualified well and 
has earned no RSV under this section), and later drill:
    (i) A deep well with a perforated interval the top of which is 
17,000 feet TVD SS, your lease earns no RSV (see paragraph (c)(1) of 
this section);
    (ii) A qualified deep well that is an original well with a 
perforated interval the top of which is 19,000 feet TVD SS, your 
lease earns an RSV of 10 BCF under paragraph (c)(2) of this section. 
This RSV would be applied to gas production from qualified wells on 
your lease, as prescribed in Sec. Sec.  203.43 and 203.48; or
    (iii) A qualified deep well that is a sidetrack with a 
perforated interval the top of which is 19,000 feet TVD SS, that has 
a sidetrack measured depth of 7,000 feet, your lease earns an RSV of 
8.2 BCF under paragraph (c)(3) of this section. This RSV would be 
applied to gas production from qualified wells on your lease, as 
prescribed in Sec. Sec.  203.43 and 203.48.
    Example 5: If you have a qualified deep well that is an original 
well with a perforated interval the top of which is 16,000 feet TVD 
SS, and later drill a second qualified well that is an original well 
with a perforated

[[Page 69512]]

interval the top of which is 19,000 feet TVD SS, we increase the 
total RSV for your lease from 15 BCF to 25 BCF under paragraph 
(c)(2) of this section. We will apply that RSV to gas production 
from all qualified wells on your lease, as prescribed in Sec. Sec.  
203.43 and 203.48. If the second well has a perforated interval the 
top of which is 22,000 feet TVD SS (instead of 19,000 feet), the 
total RSV for your lease would increase to 25 BCF only in 2 
situations: (1) If the second well was a phase 1 ultra-deep well, 
i.e., if drilling began before May 18, 2007, or (2) the exception in 
Sec.  203.31(b) applies. In both situations, your lease must be 
partly or entirely in less than 200 meters of water and production 
must begin on this well before May 3, 2009. If drilling of the 
second well began on or after May 18, 2007, the second well would be 
qualified as a phase 2 or phase 3 ultra-deep well and, unless the 
exception in Sec.  203.31(b) applies, would not earn any additional 
RSV (as prescribed in Sec.  203.30), so the total RSV for your lease 
would remain at 15 BCF.
    Example 6: If you have a qualified deep well that is a 
sidetrack, with a perforated interval the top of which is 16,000 
feet TVD SS and a sidetrack measured depth of 4,000 feet, and later 
drill a second qualified well that is a sidetrack, with a perforated 
interval the top of which is 19,000 feet TVD SS and a sidetrack 
measured depth of 8,000 feet, we increase the total RSV for your 
lease from 6.4 BCF [4 + (600 * 4,000)/1,000,000] to 15.2 BCF {6.4 + 
[4 + (600 * 8,000)/1,000,000)]{time}  under paragraphs (b)(2) and 
(c)(3) of this section. We would apply that RSV to gas production 
from all qualified wells on your lease, as prescribed in Sec. Sec.  
203.43 and 203.48. The difference of 8.8 BCF represents the RSV 
earned by the second sidetrack that has a perforated interval the 
top of which is deeper than 18,000 feet TVD SS.


0
7. Sections 203.42 through 203.48 are redesignated as Sec. Sec.  203.42 
through 203.49.

0
8. Add new Sec.  203.42 to read as follows:


Sec.  203.42  What conditions and limitations apply to royalty relief 
for deep wells and phase 1 ultra-deep wells?

    The conditions and limitations in the following table apply to 
royalty relief under Sec.  203.41.

------------------------------------------------------------------------
               If . . .                            Then . . .
------------------------------------------------------------------------
(a) Your lease has produced gas or     your lease cannot earn an RSV
 oil from a well with a perforated      under Sec.   203.41 as a result
 interval the top of which is 18,000    of drilling any subsequent deep
 feet TVD SS or deeper,                 wells or phase 1 ultra-deep
                                        wells.
(b) You determine RSV under Sec.       that determination establishes
 203.41 for the first qualified deep    the total RSV available for that
 well or qualified phase 1 ultra-deep   drilling depth interval on your
 well on your lease (whether an         lease (i.e., either 15,000-
 original well or a sidetrack)          18,000 feet TVD SS, or 18,000
 because you drilled and produced it    feet TVD SS and deeper),
 within the time intervals set forth    regardless of the number of
 in the definitions for qualified       subsequent qualified wells you
 wells,                                 drill to that depth interval.
(c) A qualified deep well or           the RSV earned by that well under
 qualified phase 1 ultra-deep well on   Sec.   203.41 applies only to
 your lease is within a unitized        production from qualified wells
 portion of your lease,                 on or allocated to your lease
                                        and not to other leases within
                                        the unit.
(d) Your qualified deep well or        the lease with the perforated
 qualified phase 1 ultra-deep well is   interval that initially produces
 a directional well (either an          earns the RSV. However, if the
 original well or a sidetrack)          perforated interval crosses a
 drilled across a lease line,           lease line, the lease where the
                                        surface of the well is located
                                        earns the RSV.
(e) You earn an RSV under Sec.         that RSV is in addition to any
 203.41,                                RSS for your lease under Sec.
                                        203.45 that results from a
                                        different wellbore.
(f) Your lease earns an RSV under      the RSV is not forfeited or
 Sec.   203.41 and later produces       terminated, but you may not
 from a well that is not a qualified    apply the RSV under Sec.
 well,                                  203.41 to production from the
                                        non-qualified well.
(g) You qualify for an RSV under       you still owe minimum royalties
 paragraphs (b) or (c) of Sec.          or rentals in accordance with
 203.41,                                your lease terms.
(h) You transfer your lease,           unused RSVs transfer to a
                                        successor lessee and expire with
                                        the lease.
------------------------------------------------------------------------

    Example to paragraph (b): If your first qualified deep well is a 
sidetrack with a perforated interval whose top is 16,000 feet TVD SS 
and earns an RSV of 12.5 BCF, and you later drill a qualified 
original deep well to 17,000 feet TVD SS, the RSV for your lease 
remains at 12.5 BCF and does not increase to 15 BCF. However, under 
paragraph (c) of Sec.  203.41, if you subsequently drill a qualified 
deep well to a depth of 18,000 feet or greater TVD SS, you may earn 
an additional RSV.

0
9. Revise newly redesignated Sec.  203.43 to read as follows:


Sec.  203.43  To which production do I apply the RSV earned from 
qualified deep wells or qualified phase 1 ultra-deep wells on my lease?

    (a) You must apply the RSV prescribed in Sec.  203.41(b) and (c) to 
gas volumes produced from qualified wells on or after May 3, 2004, 
reported on the OGOR-A for your lease under Sec.  216.53, as and to the 
extent prescribed in Sec. Sec.  203.43 and 203.48.
    (1) Except as provided in paragraph (a)(2) of this section, all gas 
production from qualified wells reported on the OGOR-A, including 
production that is not subject to royalty, counts toward the lease RSV.
    (2) Production to which an RSS applies under Sec. Sec.  203.45 and 
203.46 does not count toward the lease RSV.
    (b) This paragraph applies to any lease with a qualified deep well 
or qualified phase 1 ultra-deep well when no part of the lease is 
within an MMS-approved unit. Subject to the price conditions in Sec.  
203.48, you must apply the RSV prescribed in Sec.  203.41 as required 
under the following paragraphs (b)(1) and (b)(2) of this section.
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of:
    (i) May 3, 2004, for an RSV earned by a qualified deep well or 
qualified phase 1 ultra-deep well on a lease that is located entirely 
or partly in water less than 200 meters deep;
    (ii) May 18, 2007, for an RSV earned by a qualified deep well on a 
lease that is located entirely in water more than 200 meters deep; or
    (iii) The date that the first qualified well that earns your lease 
the RSV begins production (other than test production).
    (2) You must apply the RSV to only gas production from qualified 
wells on your lease, regardless of their depth, for which you have met 
the requirements in Sec.  203.35 or Sec.  203.44.

    Example 1: On a lease in water less than 200 meters deep, you 
began drilling an original deep well with a perforated interval the 
top of which is 18,200 feet TVD SS in September 2003, that became a 
qualified deep well in July 2004, when it began producing and using 
the RSV that it earned. You subsequently drill another original deep 
well with a perforated interval the top of which is 16,600 feet TVD 
SS, which becomes a qualified deep well when production begins in 
August 2008. The first well earned an RSV of 25 BCF (see Sec.  
203.41(a)(1) and (b)(3)). You must apply any remaining RSV each 
month beginning in August 2008 to production from both wells until 
the 25 BCF RSV is fully utilized according to paragraph

[[Page 69513]]

(b)(2) of this section. If the second well had begun production in 
August 2009, it would not be a qualified deep well because it 
started production after expiration in May 2009 of the ability to 
qualify for royalty relief in this water depth, and could not share 
any of the remaining RSV (see definition of a qualified deep well in 
Sec.  203.0).
    Example 2: On a lease in water between 200 and 400 meters deep, 
you begin drilling an original deep well with a perforated interval 
the top of which is 17,100 feet TVD SS in November 2010 that becomes 
a qualified deep well in June 2011 when it begins producing and 
using the RSV. You subsequently drill another original deep well 
with a perforated interval the top of which is 15,300 feet TVD SS 
which becomes a qualified deep well by beginning production in 
October 2011 (see definition of a qualified deep well in Sec.  
203.0). Only the first well earns an RSV equal to 15 BCF (see Sec.  
203.41(a) and (b)). You must apply any remaining RSV each month 
beginning in October 2011 to production from both qualified deep 
wells until the 15 BCF RSV is fully utilized according to paragraph 
(b)(2) of this section.

    (c) This paragraph applies to any lease with a qualified deep well 
or qualified phase 1 ultra-deep well when all or part of the lease is 
within an MMS-approved unit. Under the unit agreement, a share of the 
production from all the qualified wells in the unit participating area 
would be allocated to your lease each month according to the 
participating area percentages. Subject to the price conditions in 
Sec.  203.48, you must apply the RSV prescribed under Sec.  203.41 as 
required under the following paragraphs (c)(1) through (c)(3) of this 
section.
    (1) You must apply the RSV to the earliest gas production occurring 
on and after the later of:
    (i) May 3, 2004, for an RSV earned by a qualified well or qualified 
phase 1 ultra-deep well on a lease that is located entirely or partly 
in water less than 200 meters deep;
    (ii) May 18, 2007, for an RSV earned by a qualified deep well on a 
lease that is located entirely in water more than 200 meters deep; or
    (iii) The date that the first qualified well that earns your lease 
the RSV begins production (other than test production).
    (2) You must apply the RSV to only gas production:
    (i) From all qualified wells on the non-unitized area of your 
lease, regardless of their depth, for which you have met the 
requirements in Sec.  203.35 or Sec.  203.44; and,
    (ii) Allocated to your lease under an MMS-approved unit agreement 
from qualified wells on unitized areas of your lease and on unitized 
areas of other leases in the unit, regardless of their depth, for which 
the requirements in Sec.  203.35 or Sec.  203.44 have been met.
    (3) The allocated share under paragraph (c)(2)(ii) of this section 
does not increase the RSV for your lease. None of the volumes produced 
from a well that is not within a unit participating area may be 
allocated to other leases in the unit.

    Example: The east half of your lease A is unitized with all of 
lease B. There is one qualified 19,000-foot TVD SS deep well on the 
non-unitized portion of lease A, one qualified 18,500-foot TVD SS 
deep well on the unitized portion of lease A, and a qualified 
19,400-foot TVD SS deep well on lease B. The participating area 
percentages allocate 32 percent of production from both of the unit 
qualified deep wells to lease A and 68 percent to lease B. If the 
non-unitized qualified deep well on lease A produces 12 BCF and the 
unitized qualified deep well on lease A produces 15 BCF, and the 
qualified deep well on lease B produces 10 BCF, then the production 
volume from and allocated to lease A to which the lease an RSV 
applies is 20 BCF [12 + (15 + 10) * (0.32)]. The production volume 
allocated to lease B to which the lease B RSV applies is 17 BCF [(15 
+ 10) * (0.68)].

    (d) You must begin paying royalties when the cumulative production 
of gas from all qualified wells on your lease, or allocated to your 
lease under paragraph (c) of this section, reaches the applicable RSV 
allowed under Sec.  203.31 or Sec.  203.41. For the month in which 
cumulative production reaches this RSV, you owe royalties on the 
portion of gas production that exceeds the RSV remaining at the 
beginning of that month.
    (e) You may not apply the RSV allowed under Sec.  203.41 to:
    (1) Production from completions less than 15,000 feet TVD SS, 
except in cases where the qualified deep well is re-perforated in the 
same reservoir previously perforated deeper than 15,000 feet TVD SS;
    (2) Production from a deep well or phase 1 ultra-deep well on any 
other lease, except as provided in paragraph (c) of this section;
    (3) Any liquid hydrocarbon (oil and condensate) volumes; or
    (4) Production from a deep well or phase 1 ultra-deep well that 
commenced drilling before:
    (i) March 26, 2003, on a lease that is located entirely or partly 
in water less than 200 meters deep, or
    (ii) May 18, 2007, on a lease that is located entirely in water 
more than 200 meters deep.

0
10. In redesignated Sec.  203.44, paragraphs (a), (d), and (e) are 
revised to read as follows:


Sec.  203.44  What administrative steps must I take to use the RSV 
earned by a qualified deep well or qualified phase 1 ultra-deep well?

    (a) You must notify the MMS Regional Supervisor for Production and 
Development in writing of your intent to begin drilling operations on 
all deep wells and phase 1 ultra-deep wells; and
* * * * *
    (d) You must provide the information in paragraph (b) of this 
section by January 20, 2009 if you produced before December 18, 2008 
from a qualified deep well or qualified phase 1 ultra-deep well on a 
lease that is located entirely in water more than 200 meters and less 
than 400 meters deep.
    (e) The MMS Regional Supervisor for Production and Development may 
extend the deadline for beginning production for up to one year for a 
well that cannot begin production before the applicable date prescribed 
in the definition of ``qualified deep well'' in Sec.  203.0 if it meets 
all of the following criteria.
    (1) The well otherwise meets the criteria in the definition of a 
qualified deep well in Sec.  203.0.
    (2) The delay in production occurred after reaching total depth in 
the well.
    (3) Production (other than test production) was expected to begin 
from the well before the applicable deadline in the definition of a 
qualified deep well in Sec.  203.0. You must provide a credible 
activity schedule with supporting documentation.
    (4) The delay in beginning production is for reasons beyond your 
control, such as adverse weather and accidents which MMS deems were 
unavoidable.

0
11. In redesignated Sec.  203.45, paragraphs (a), (b) and (e) are 
revised to read as follows:


Sec.  203.45  If I drill a certified unsuccessful well, what royalty 
relief will my lease earn?

* * * * *
    (a) If you drill a certified unsuccessful well and you satisfy the 
administrative requirements of Sec.  203.47, subject to the price 
conditions in Sec.  203.48, your lease earns an RSS shown in the 
following table. The RSS is shown in billions of cubic feet of gas 
equivalent (BCFE) or in thousands of cubic feet of gas equivalent 
(MCFE) and is applicable to oil and gas production as prescribed in 
Sec.  204.46.

[[Page 69514]]



----------------------------------------------------------------------------------------------------------------
If you have a certified unsuccessful well that is:   Then your lease earns an RSS on this volume of oil and gas
                                                     production as prescribed in this section and Sec.   203.46:
----------------------------------------------------------------------------------------------------------------
(1) An original well and your lease has not         5 BCFE.
 produced gas or oil from a deep well or an ultra-
 deep well,
(2) A sidetrack (with a sidetrack measured depth    0.8 BCFE plus 120 MCFE times sidetrack measured depth
 of at least 10,000 feet) and your lease has not     (rounded to the nearest 100 feet) but no more than 5 BCFE.
 produced gas or oil from a deep well or an ultra-
 deep well,
(3) An original well or a sidetrack (with a         2 BCFE.
 sidetrack measured depth of at least 10,000 feet)
 and your lease has produced gas or oil from a
 deep well with a perforated interval the top of
 which is from 15,000 to less than 18,000 feet TVD
 SS,
----------------------------------------------------------------------------------------------------------------

    (b) This paragraph applies to oil and gas volumes you report on the 
OGOR-A for your lease under Sec.  216.53.
    (1) You must apply the RSS prescribed in paragraph (a) of this 
section, in accordance with the requirements in Sec.  203.46, to all 
oil and gas produced from the lease:
    (i) On or after December 18, 2008, if your lease is located in 
water more than 200 meters but less than 400 meters deep; or
    (ii) On or after May 3, 2004, if your lease is located in water 
partly or entirely less than 200 meters deep.
    (2) Production to which an RSV applies under Sec. Sec.  203.31 
through 203.33 and Sec. Sec.  203.41 through 203.43 does not count 
toward the lease RSS. All other production, including production that 
is not subject to royalty, counts toward the lease RSS.

    Example 1: If you drill a certified unsuccessful well that is an 
original well to a target 19,000 feet TVD SS, your lease earns an 
RSS of 5 BCFE that would be applied to gas and oil production if 
your lease has not previously produced from a deep well or an ultra-
deep well, or you earn an RSS of 2 BCFE of gas and oil production if 
your lease has previously produced from a deep well with a 
perforated interval from 15,000 to less than 18,000 feet TVD SS, as 
prescribed in Sec.  203.46.
    Example 2: If you drill a certified unsuccessful well that is a 
sidetrack that reaches a target 19,000 feet TVD SS, that has a 
sidetrack measured depth of 12,545 feet, and your lease has not 
produced gas or oil from any deep well or ultra-deep well, MMS 
rounds the sidetrack measured depth to 12,500 feet and your lease 
earns an RSS of 2.3 BCFE of gas and oil production as prescribed in 
Sec.  203.45.
* * * * *
    (e) If the same wellbore that earns an RSS as a certified 
unsuccessful well later produces from a perforated interval the top of 
which is 15,000 feet TVD or deeper and becomes a qualified well, it 
will be subject to the following conditions:
* * * * *

0
12. In redesignated Sec.  203.46, paragraphs (a) introductory text, 
(a)(1), (c), and (e) are revised to read as follows:


Sec.  203.46  To which production do I apply the RSS from drilling one 
or two certified unsuccessful wells on my lease?

    (a) Subject to the requirements of Sec. Sec.  203.40, 203.43, 
203.45, 203.47, and 203.48, you must apply an RSS in Sec.  203.45 to 
the earliest oil and gas production:
    (1) Occurring on and after the day you file the information under 
Sec.  204.47(b),
* * * * *
    (c) If you have no current production on which to apply the RSS 
allowed under Sec.  203.45, your RSS applies to the earliest subsequent 
production of gas and oil from, or allocated under an MMS-approved unit 
agreement to, your lease.
* * * * *
    (e) You may not apply the RSS allowed under Sec.  203.45 to 
production from any other lease, except for production allocated to 
your lease from an MMS-approved unit agreement. If your certified 
unsuccessful well is on a lease subject to an MMS-approved unit 
agreement, the lessees of other leases in the unit may not apply any 
portion of the RSS for your lease to production from the other leases 
in the unit.
* * * * *

0
13. In redesignated Sec.  203.47, paragraph (c) is revised to read as 
follows:


Sec.  203.47  What administrative steps do I take to obtain and use the 
royalty suspension supplement?

* * * * *
    (c) If you commenced drilling a well that otherwise meets the 
criteria for a certified unsuccessful well on a lease located entirely 
in more than 200 meters and entirely less than 400 meters of water on 
or after May 18, 2007, and finished it before December 18, 2008, you 
must provide the information in paragraph (b) of this section no later 
than February 17, 2009.

0
14. Redesignated Sec.  203.48 is revised to read as follows:


Sec.  203.48  Do I keep royalty relief if prices rise significantly?

    (a) You must pay royalties on all gas and oil production for which 
an RSV or an RSS otherwise would be allowed under Sec. Sec.  203.40 
through 203.47 for any calendar year when the average daily closing 
NYMEX natural gas price exceeds the applicable threshold price shown in 
the following table.

----------------------------------------------------------------------------------------------------------------
 For a lease located in water .
              . .                          And issued . . .             the applicable threshold price is . . .
----------------------------------------------------------------------------------------------------------------
(1) Partly or entirely less      before December 18, 2008,..........  $10.15 per MMBtu, adjusted annually after
 than 200 meters deep,                                                 calendar year 2007 for inflation.
(2) Partly or entirely less      after December 18, 2008,             $4.55 per MMBtu, adjusted annually after
 than 200 meters deep,                                                 calendar year 2007 for inflation unless
                                                                       the lease terms prescribe a different
                                                                       price threshold.
(3) Entirely more than 200       on any date,                         $4.55 per MMBtu, adjusted annually after
 meters and entirely less than                                         calendar year 2007 for inflation unless
 400 meters deep,                                                      the lease terms prescribe a different
                                                                       price threshold.
----------------------------------------------------------------------------------------------------------------

    (b) Determine the threshold price for any calendar year after 2007 
by adjusting the threshold price in the previous year by the percentage 
that the implicit price deflator for the gross domestic product, as 
published by the Department of Commerce, changed during the calendar 
year.

[[Page 69515]]

    (c) You must pay any royalty due under this section no later than 
March 31 of the year following the calendar year for which you owe 
royalty. If you do not pay by that date, you must pay late payment 
interest under Sec.  218.54 from April 1 until the date of payment.
    (d) Production volumes on which you must pay royalty under this 
section count as part of your RSV and RSS.

0
15. In redesignated Sec.  203.49, the introductory text in paragraph 
(a) and paragraph (c) are revised to read as follows:


Sec.  203.49  May I substitute the deep gas drilling provisions in this 
part for the deep gas royalty relief provided in my lease terms?

    (a) You may exercise an option to replace the applicable lease 
terms for royalty relief related to deep-well drilling with those in 
Sec.  203.0 and Sec. Sec.  203.40 through 203.48 if you have a lease 
issued with royalty relief provisions for deep-well drilling. Such 
leases:
* * * * *
    (c) Once you exercise the option under paragraph (a) of this 
section, you are subject to all the activity, timing, and 
administrative requirements pertaining to deep gas royalty relief as 
specified in Sec. Sec.  203.40 through 203.48.
* * * * *

0
16. The undesignated center heading between Sec.  203.56 and Sec.  
203.60 is revised to read as follows:

Royalty Relief for Pre-Act Deep Water Leases and for Development and 
Expansion Projects

0
17. Revise Sec.  203.60 to read as follows:


Sec.  203.60  Who may apply for royalty relief on a case-by-case basis 
in deep water in the Gulf of Mexico or offshore of Alaska?

    You may apply for royalty relief under Sec. Sec.  203.61(b) and 
203.62 for an individual lease, unit or project if you:
    (a) Hold a pre-Act lease (as defined in Sec.  203.0) that we have 
assigned to an authorized field (as defined in Sec.  203.0);
    (b) Propose an expansion project (as defined in Sec.  203.0); or
    (c) Propose a development project (as defined in Sec.  203.0).

0
18. Revise Sec.  203.62 to read as follows:


Sec.  203.62  How do I apply for relief?

    (a) You must send a complete application and the required fee to 
the MMS Regional Director for your region.
    (b) Your application for royalty relief offshore Alaska or in deep 
water in the GOM must include an original and two copies (one set of 
digital information) of:
    (1) Administrative information report;
    (2) Economic Viability and relief justification report;
    (3) G&G report;
    (4) Engineering report;
    (5) Production report; and
    (6) Cost report.
    (c) Section 203.82 explains why we are authorized to require these 
reports.
    (d) Sections 203.81, 203.83, and 203.85 through 203.89 describe 
what these reports must include. The MMS regional office for your 
region will guide you on the format for the required reports, and we 
encourage you to contact this office before preparing your application 
for this guidance.

0
19. In Sec.  203.69, paragraph (b) is revised, paragraphs (c) through 
(f) are redesignated as paragraphs (f) through (i), and new paragraphs 
(c) through (e) are added to read as follows:


Sec.  203.69  If my application is approved, what royalty relief will I 
receive?

* * * * *
    (b) For development projects, any relief we grant applies only to 
project wells and replaces the royalty relief, if any, with which we 
issued your lease.
    (c) If your project is economic given the royalty relief with which 
we issued your lease, we will reject the application.
    (d) If the lease has earned or may earn deep gas royalty relief 
under Sec. Sec.  203.40 through 203.49 or ultra-deep gas royalty relief 
under Sec. Sec.  203.30 through 203.36, we will take the deep gas 
royalty relief or ultra-deep gas royalty relief into account in 
determining whether further royalty relief for a development project is 
necessary for production to be economic.
    (e) If neither paragraph (c) nor (d) of this section apply, the 
minimum royalty suspension volumes are as shown in the following table:

----------------------------------------------------------------------------------------------------------------
                                   The minimum royalty suspension volume is .
            For . . .                                 . .                                  Plus . . .
----------------------------------------------------------------------------------------------------------------
(1) RS leases in the GOM or       A volume equal to the combined royalty       10 percent of the median of the
 leases offshore Alaska,           suspension volumes (or the volume            distribution of known
                                   equivalent based on the data in your         recoverable resources upon which
                                   approved application for other forms of      MMS based approval of your
                                   royalty suspension) with which MMS issued    application from all reservoirs
                                   the leases participating in the              included in the project.
                                   application that have or plan a well into
                                   a reservoir identified in the application,
(2) Leases offshore Alaska or     A volume equal to 10 percent of the median
 other deep water GOM leases       of the distribution of known recoverable
 issued in sales after November    resources upon which MMS based approval of
 28, 2000,                         your application from all reservoirs
                                   included in the project.
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------

* * * * *

0
20. In Sec.  203.70, revise the introductory text and paragraph (b) to 
read as follows:


Sec.  203.70  What information must I provide after MMS approves 
relief?

    You must submit reports to us as indicated in the following table. 
Sections 203.81, 203.90, and 203.91 describe what these reports must 
include. The MMS Regional Office for your region will prescribe the 
formats.

----------------------------------------------------------------------------------------------------------------
             Required report                        When due to MMS                   Due date extensions
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
(b) Post-production report..............  Within 120 days after the start of  With acceptable justification from
                                           production that is subject to the   you, the MMS Regional Director
                                           approved royalty suspension         for your region may extend the
                                           volume.                             due date up to 30 days.
----------------------------------------------------------------------------------------------------------------


[[Page 69516]]


0
21. Revise Sec.  203.77 to read as follows:


Sec.  203.77  May I voluntarily give up relief if conditions change?

    Yes, you may voluntarily give up relief by sending a letter to that 
effect to the MMS Regional office for your region.

0
22. Revise Sec.  203.78 to read as follows:


Sec.  203.78  Do I keep relief approved by MMS under Sec. Sec.  203.60-
203.77 for my lease, unit or project if prices rise significantly?

    If prices rise above a base price threshold for light sweet crude 
oil or natural gas, you must pay full royalties on production otherwise 
subject to royalty relief approved by MMS under Sec. Sec.  203.60-
203.77 for your lease, unit or project as prescribed in this section.
    (a) The following table shows the base price threshold for various 
types of leases, subject to paragraph (b) of this section. Note that, 
for post-November 2000 deepwater leases in the GOM, price thresholds 
apply on a lease basis, so different leases on the same development 
project or expansion project approved for royalty relief may have 
different price thresholds.

----------------------------------------------------------------------------------------------------------------
                 For . . .                                    The base price threshold is . . .
----------------------------------------------------------------------------------------------------------------
(1) Pre-Act leases in the GOM,              set by statute.
(2) Post-November 2000 deep water leases    indicated in your original lease agreement or, if none, those in the
 in the GOM or leases offshore of Alaska     Notice of Sale under which your lease was issued.
 for which the lease or Notice of Sale set
 a base price threshold,
(3) Post-November 2000 deep water leases    the threshold set by statute for pre-Act leases.
 in the GOM or leases offshore of Alaska
 for which the lease or Notice of Sale did
 not set a base price threshold,
----------------------------------------------------------------------------------------------------------------

    (b) An exception may occur if we determine that the price 
thresholds in paragraphs (a)(2) or (a)(3) mean the royalty suspension 
volume set under Sec.  203.69 and in lease terms would provide 
inadequate encouragement to increase production or development, in 
which circumstance we could specify a different set of price thresholds 
on a case-by-case basis.
    (c) Suppose your base oil price threshold set under paragraph (a) 
is $28.00 per barrel, and the daily closing NYMEX light sweet crude oil 
prices for the previous calendar year exceeds $28.00 per barrel, as 
adjusted in paragraph (h) of this section. In this case, we retract the 
royalty relief authorized in this subpart and you must:
    (1) Pay royalties on all oil production for the previous year at 
the lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 
and Sec.  218.54 of this chapter) by March 31 of the current calendar 
year, and
    (2) Pay royalties on all your oil production in the current year.
    (d) Suppose your base gas price threshold set under paragraph (a) 
is $3.50 per million British thermal units (Btu), and the daily closing 
NYMEX light sweet crude oil prices for the previous calendar year 
exceeds $3.50 per million Btu, as adjusted in paragraph (h) of this 
section. In this case, we retract the royalty relief authorized in this 
subpart and you must:
    (1) Pay royalties on all gas production for the previous year at 
the lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 
and Sec.  218.54 of this chapter) by March 31 of the current calendar 
year, and
    (2) Pay royalties on all your gas production in the current year.
    (e) Production under both paragraphs (c) and (d) of this section 
counts as part of the royalty-suspension volume.
    (f) You are entitled to a refund or credit, with interest, of 
royalties paid on any production (that counts as part of the royalty-
suspension volume):
    (1) Of oil if the arithmetic average of the closing prices for the 
current calendar year is $28.00 per barrel or less, as adjusted in 
paragraph (h) of this section, and
    (2) Of gas if the arithmetic average of the closing natural gas 
prices for the current calendar year is $3.50 per million Btu or less, 
as adjusted in paragraph (h) of this section.
    (g) You must follow our regulations in part 230 of this chapter for 
receiving refunds or credits.
    (h) We change the prices referred to in paragraphs (c), (d), and 
(f) of this section periodically. For pre-Act leases, these prices 
change during each calendar year after 1994 by the percentage that the 
implicit price deflator for the gross domestic product changed during 
the preceding calendar year. For post-November 2000 deepwater leases, 
these prices change as indicated in the lease instrument or in the 
Notice of Sale under which we issued the lease.

0
23. In Sec.  203.79, revise the section heading to read as follows:


Sec.  203.79  How do I appeal MMS's decisions related to royalty relief 
for a deepwater lease or a development or expansion project?

* * * * *

0
24. In Sec.  203.80, revise the section heading and introductory text 
to read as follows:


Sec.  203.80  When can I get royalty relief if I am not eligible for 
royalty relief under other sections in the subpart?

    We may grant royalty relief when it serves the statutory purposes 
summarized in Sec.  203.1 and our formal relief programs, including but 
not limited to the applicable levels of the royalty suspension volumes 
and price thresholds, provide inadequate encouragement to promote 
development or increase production. Unless your lease lies offshore of 
Alaska or wholly west of 87 degrees, 30 minutes West longitude in the 
GOM, your lease must be producing to qualify for relief. Before you may 
apply for royalty relief apart from our programs for end-of-life leases 
or for pre-Act deep water leases and development and expansion 
projects, we must agree that your lease or project has two or more of 
the following characteristics:
* * * * *

0
25. In Sec.  203.81, revise paragraph (b) to read as follows:


Sec.  203.81  What supplemental reports do royalty relief applications 
require?

* * * * *
    (b) You must certify that all information in your application, 
fabricator's confirmation and post-production development reports is 
accurate, complete, and conforms to the most recent content and 
presentation guidelines available from the MMS Regional office for your 
region.
* * * * *

0
26. In Sec.  203.89, revise the section heading to read as follows:


Sec.  203.89  What is in a cost report?

* * * * *

0
27. In Sec.  203.90, revise paragraph (b) to read as follows:

[[Page 69517]]

Sec.  203.90  What is in a fabricator's confirmation report?

* * * * *
    (b) A letter from the contractor building the system to the MMS 
Regional Director for your region certifying when construction started 
on your system; and
* * * * *

PART 260--OUTER CONTINENTAL SHELF OIL AND GAS LEASING

0
28. The authority citation for part 260 continues to read as follows:

    Authority: 43 U.S.C. 1331 et seq..


0
29. In Sec.  260.121, revise paragraph (b) to read as follows:


Sec.  260.121  When does a lease issued in a sale held after November 
2000 get a royalty suspension?

* * * * *
    (b) You may apply for a supplemental royalty suspension for a 
project under part 203 of this title, if your lease is located:
    (1) In the Gulf of Mexico, in water 200 meters or deeper, and 
wholly west of 87 degrees, 30 minutes West longitude; or
    (2) Offshore of Alaska.
* * * * *

0
30. In Sec.  260.122, remove paragraph (d) and revise paragraph (b)(1) 
to read as follows:


Sec.  260.122  How long will a royalty suspension volume be effective 
for a lease issued in a sale held after November 2000?

* * * * *
    (b)(1) Notwithstanding any royalty suspension volume under this 
subpart, you must pay royalty at the lease stipulated rate on:
    (i) Any oil produced for any period stipulated in the lease during 
which the arithmetic average of the daily closing price on the New York 
Mercantile Exchange (NYMEX) for light sweet crude oil exceeds the 
applicable threshold price of $36.39 per barrel, adjusted annually 
after calendar year 2007 for inflation unless the lease terms prescribe 
a different price threshold.
    (ii) Any natural gas produced for any period stipulated in the 
lease during which the arithmetic average of the daily closing price on 
the NYMEX for natural gas exceeds the applicable threshold price of 
$4.55 per MMBtu, adjusted annually after calendar year 2007 for 
inflation unless the lease terms prescribe a different price threshold.
    (iii) Determine the threshold price for any calendar year after 
2007 by adjusting the threshold price in the previous year by the 
percentage that the implicit price deflator for the gross domestic 
product, as published by the Department of Commerce, changed during the 
calendar year.
* * * * *

 [FR Doc. E8-26410 Filed 11-17-08; 8:45 am]
BILLING CODE 4310-MR-P