Federal Register, Volume 73 Issue 223 (Tuesday, November 18, 2008)

[Federal Register Volume 73, Number 223 (Tuesday, November 18, 2008)]
[Rules and Regulations]
[Pages 69490-69517]
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

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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: 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