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, 69490-69517 [E8-26410]

Agencies

• DEPARTMENT OF THE INTERIOR
• Minerals Management Service

[Federal Register Volume 73, Number 223 (Tuesday, November 18, 2008)]
[Rules and Regulations]
[Pages 69490-69517]
From the Federal Register Online via the Government Printing 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: https://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

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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

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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: https://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 
collec