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Proposed Rule

Oil and Gas and Sulphur Operations in the Outer Continental Shelf (OCS)-Royalty Relief-Ultra-Deep Gas Wells and Deep Gas Wells on OCS Oil and Gas Leases; Extension of Royalty Relief Provisions to OCS Leases Offshore of Alaska

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Start Preamble Start Printed Page 28396

AGENCY:

Minerals Management Service (MMS), Interior

ACTION:

Proposed rule.

SUMMARY:

MMS is proposing to amend its deep gas royalty relief regulations to incorporate statutory changes enacted in the Energy Policy Act of 2005. This proposed rule would provide additional royalty relief for certain wells on the Outer Continental Shelf (OCS) leases in the Gulf of Mexico (GOM). It would also extend the applicability of existing deep gas royalty relief regulatory provisions to more OCS leases. MMS is also proposing amendments to discretionary royalty relief provisions and associated definitions to extend the applicability of certain royalty relief to leases offshore of Alaska.

DATES:

Submit comments by July 17, 2007. MMS may not consider comments received after this date. Submit comments to the Office of Management and Budget on the information collection burden in this rule by June 18, 2007.

Start Further Info

FOR FURTHER INFORMATION CONTACT:

Marshall Rose, Chief, Economics Division, at (703) 787-1536 or marshall.rose@mms.gov.

End Further Info

ADDRESSES:

You may submit comments on the proposed rulemaking by any of the following methods. Please use the Regulation Identifier Number (RIN) 1010-AD33 as an identifier in your message. See also Public Availability of Comments under Procedural Matters.

  • Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions on the Web site for submitting comments.
  • E-mail MMS at rules.comments@mms.gov. Use the RIN 1010-AD33 in the subject line.
  • Fax: 703-787-1546. Identify with the RIN, 1010-AD33.
  • Mail or hand-carry comments to the Department of the Interior; Minerals Management Service; Attention: Regulations and Standards Branch (RSB); 381 Elden Street, MS-4024; Herndon, Virginia 20170-4817. Please reference “Royalty Relief—Ultra-Deep Gas Wells on OCS Oil and Gas Leases; Extension of Royalty Relief Provisions to OCS Leases Offshore of Alaska, 1010-AD33” in your comments and include your name and return address.
  • Send comments on the information collection in this rule to: Interior Desk Officer 1010-AD33, Office of Management and Budget; 202-395-6566 (fax); e-mail: oira_docket@omb.eop.gov. Please also send a copy to MMS.
End Preamble Start Supplemental Information

SUPPLEMENTARY INFORMATION:

A. Background and Summary of the Proposed Rule

Section 344 of the Energy Policy Act of 2005, Pub. L. 109-58, 119 Stat. 594, 702 (codified at 42 U.S.C. 15904) (referred to hereinafter as “section 344”), enacted on August 8, 2005, provides incentives to producers in the form of royalty relief for production of certain deep gas from offshore federal oil and gas leases in the shallow waters of the GOM wholly west of 87 degrees, 30 minutes West longitude. This statutorily-mandated relief supplements royalty relief MMS previously provided by regulation.

On January 26, 2004 (69 FR 3510), MMS adopted regulations at 30 CFR §§ 203.40-203.48 to provide royalty relief incentives 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 (the rule was effective for wells spudded on or after the date of the proposed rule, March 26, 2003). These rules, subject to certain limitations, provide a royalty suspension volume (RSV) for two basic categories of deep gas production: 15 billion cubic feet (BCF) of RSV is provided for qualifying wells with a perforated interval the top of which is between 15,000 and 18,000 feet true vertical depth subsea (TVD SS); and 25 BCF of RSV is provided for qualifying wells completed at least 18,000 feet TVD SS. The rules also provide lesser amounts of royalty relief for deep sidetracks and for drilling certain unsuccessful deep wells.

Section 344 requires MMS to adopt regulations providing for additional categories of deep gas royalty relief for GOM leases wholly west of 87 degrees, 30 minutes West longitude. First, section 344(a) provides that for certain ultra-deep wells in less than 400 meters of water (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 agency shall issue regulations granting an RSV of not less than 35 BCF. This requires adding a new well depth category and new RSV amount to the existing deep gas royalty relief rule.

Second, section 344(b) requires MMS to promulgate regulations granting royalty relief suspension volumes for gas produced from deep wells on leases in waters more than 200 meters but less than 400 meters deep. In calculating the suspension volumes, section 344(b) requires MMS to use the same methodology used to calculate suspension volumes for deep wells in shallower waters. This requires adding a new water depth category to the existing deep gas royalty relief rule. These proposed regulations implement these two statutory directives.

In addition, section 346 of the Energy Policy Act, 119 Stat. 704, amended section 8(a)(3)(B) of the OCS Lands Act (OCSLA), 43 U.S.C. 1337(a)(3)(B), to extend the Secretary's discretionary authority to grant royalty relief to leases offshore of Alaska. This proposed rule also implements this provision. However, neither the existing deep gas royalty relief rule nor the additional deep gas royalty relief granted in section 344 applies to leases offshore of Alaska.

Both subsections (a) and (b) of section 344 provide that any final rule that the Secretary adopts will be retroactive to the date of this proposed rule. Therefore, production from any wells that earn royalty relief under section 344 drilled on or after the publication date of the proposed rule would qualify for the relief provided for in the final rule, if the well meets the requirements of the final rule. Of course, MMS may modify the rule between this proposed rule and the final rule, so lessees should not assume that the proposed rules would apply.

With respect to ultra-deep wells on leases located wholly west of 87 degrees, 30 minutes West longitude in the GOM in shallow waters less than 400 meters deep, section 344(a)(1) provides:

[T]he Secretary shall issue regulations granting royalty relief suspension volumes of not less than 35 BCF with respect to the production of natural gas from ultra deep wells on leases issued in shallow waters less than 400 meters deep located in the Gulf of Mexico wholly west of 87 degrees, 30 minutes west longitude.

While this statutory language does not specify how the rulemaking should allocate or grant the 35 or greater BCF “with respect to the production of natural gas from ultra deep wells on leases,” Congress certainly intended an incentive to drill and produce ultra-deep wells beyond what MMS rules currently provide. Section 344(a)(2) further grants the Secretary considerable discretion when an ultra-deep well is not an original well or if there has been Start Printed Page 28397previous deep gas production on the lease. Section 344(a)(2) provides:

(2) Suspension Volumes.—The Secretary may grant suspension volumes of not less than 35 billion cubic feet in any case in which—

(A) The ultra deep well is a sidetrack; or

(B) The lease has previously produced from wells with a perforated interval the top of which is at least 15,000 feet true vertical depth below the datum at mean sea level. (Emphasis added.)

Therefore, section 344 requires that an ultra-deep well drilled on a lease receive an RSV of at least 35 BCF except for (1) an ultra-deep well that is a sidetrack, or (2) an ultra-deep well on a lease that has previously produced from a well with a perforated interval the top of which is at least 15,000 feet TVD SS. The combined effect of these provisions is that only the first ultra-deep original well on a lease with no prior production from a deep well is entitled to the 35 BCF RSV. Thus, while Congress directed generally that the first ultra-deep well on a lease drilled after the date of the proposed rule receive 35 BCF or more of RSV, Congress' use of the term “may” in section 344(a)(2) gives the Secretary discretion to decide whether any sidetracks completed to depths below 20,000 feet TVD SS or the first ultra-deep well completed after production from any deep well (including a second ultra-deep well on a lease) should be granted an additional 35 BCF or more of royalty relief. One objective of this proposed rulemaking is to determine whether MMS should grant RSVs of not less than 35 BCF for ultra-deep sidetracks and subsequent ultra-deep wells. Because of the statutory language, MMS cannot use section 344's authority to grant an RSV of between 0 and 35 BCF.

Since the royalty relief is available only upon the “production of natural gas from ultra-deep wells on leases,” Congress intended to supplement the existing rules that were promulgated with the objective of reducing the cost of producing domestic natural gas from deep formations in the shallow waters of the GOM. MMS intends to adopt an approach that is consistent with the statute. In general, with only limited exceptions, MMS is proposing to give no more relief than section 344 compels. Therefore, MMS seeks comments on its proposal to grant royalty relief only for the first ultra-deep well.

Subject to the receipt and analysis of requested comments regarding those discretionary provisions, for any lease that has never produced from any deep well, MMS is proposing to grant 35 BCF of RSV for the first producing ultra-deep original well or sidetrack with a sidetrack measured depth (i.e., length) of at least 20,000 feet drilled after the date of this proposed rule. (One exception is discussed below.) MMS is not proposing to grant an RSV for subsequent ultra-deep wells or shorter sidetracks on a lease.

Because section 344 is not retroactive, it does not provide for additional royalty relief for ultra-deep wells drilled before the publication date of this proposed rule. However, an ultra-deep well drilled before the publication date of this proposed rule would, if it met the other requirements of the existing rule, earn the same royalty relief as a deep well with a perforated interval the top of which is 18,000 feet TVD SS or deeper. Thus, MMS is proposing to treat ultra-deep wells drilled before the publication date of this proposed rule in the same manner as any other deep well in the 18,000-feet-or-deeper depth range.

MMS is not proposing to grant an RSV of 35 BCF under section 344 for an ultra-deep well that is a sidetrack that has a measured depth of less than 20,000 feet. Treatment of such a well for purposes of royalty relief under this proposed rule, as explained further below, depends on when the well begins producing.

For purposes of clarity, MMS proposes to revise the definitions in the existing rule to segregate a “deep well” (a well with a perforated interval the top of which is at least 15,000 feet and less than 20,000 feet TVD SS) from an “ultra-deep well” (a well with a perforated interval the top of which is at or below 20,000 feet TVD SS) for all purposes. This is also consistent with section 344(a)(3)(A)'s definition of “ultra-deep well.” Trying to use the term “deep well” to include an ultra-deep well in some contexts but not in others carries a high potential for confusion. The changes in definitions necessitate revisions to several provisions of the existing rule to accommodate the change in terminology. These changes do not change the substance of the existing rule with regard to deep wells or ultra-deep wells drilled before the publication date of this proposed rule.

Section 344(a) provides no time limit on the relief it grants for ultra-deep wells (a “sunset” provision). MMS therefore is not proposing one in this rulemaking.

The sunset provision in the existing deep gas rule is contained in the definition of “qualifying well” in the current § 203.0, which limits qualifying deep wells to those that produce gas before May 3, 2009. That date is 5 years after the effective date of the final rule currently in force and 6 years (plus a few weeks) after the publication date of the original proposed deep gas rule (March 26, 2003). Because section 344(b) requires that MMS use the same methodology in calculating RSVs for deep wells in 200-400 meters of water that is used to calculate RSVs for deep wells in shallower water, MMS is proposing a sunset provision for deep wells in 200-400 meters of water of May 3, 2013, which is exactly 4 years after the sunset date for relief for gas produced from deep wells in 200 meters of water or less, and about 6 years from the publication date of this proposed rule.

Section 344(c) provides that “[t]he Secretary may place limitations on the royalty relief granted under this section based on market price.” Therefore, as explained more fully below, MMS is proposing price thresholds that, if exceeded, would require the lessee to pay royalty on production that otherwise would be royalty-free. The concept underlying the price threshold terms proposed here is that to the extent ultra-deep gas and deep gas royalty relief granted under the proposed provisions would have been granted under the existing rule for existing leases, the existing rule's price threshold ($9.88 per MMBtu, adjusted annually for inflation after 2006) would apply. For all deep gas and ultra-deep gas royalty relief that results from section 344's new provisions, and for deep gas royalty relief for leases issued after the effective date of the final rule that are located partly or entirely in less than 200 meters of water, a different price threshold of $4.47 per MMBtu, adjusted annually for inflation after 2006, would apply. MMS is requesting comment, data, information, and other input on this proposed threshold or why a threshold other than $4.47 per MMBtu might be more appropriate for section 344 royalty relief.

Section 344(c) also provides that “The royalty relief granted under this section shall not apply to a lease for which deep water royalty relief is available.” The proposed rule reflects this limitation.

The existing regulations at § 203.44 provide royalty relief in the form of a royalty suspension supplement (RSS) of up to 5 BCF for certain unsuccessful wells drilled to a depth below 18,000 feet TVD SS. MMS is not proposing any additional relief for unsuccessful wells simply because an unsuccessful well or sidetrack was drilled to a depth below 20,000 feet TVD SS. Unsuccessful wells drilled to a depth below 20,000 feet TVD SS would continue to be treated the same as unsuccessful wells drilled Start Printed Page 28398to a depth between 18,000-20,000 feet TVD SS.

The fact that section 344 is not retroactive also means that the extension of deep gas royalty relief to leases in the 200-400 meter water depth range does not apply to deep or ultra-deep wells drilled on such leases before the publication date of this proposed rule.

B. Section-by-Section Analysis

The discussion in part A of this preamble summarized the principal concepts of this proposed rule. This section-by-section analysis will describe the more significant proposed changes in additional detail.

What definitions apply to this part? (§ 203.0)

MMS proposes changes to some definitions in the existing rule and some new definitions to implement section 344's requirements.

MMS proposes to revise the definition of “deep well” to mean a well with a perforated interval the top of which is at least 15,000 feet and less than 20,000 feet TVD SS, and to add a definition of “ultra-deep well” to mean a well with a perforated interval the top of which is 20,000 feet TVD SS or deeper. Under the existing rule, the term “deep well” includes all wells deeper than 15,000 feet TVD SS.

Because section 344 adds a new water depth category (leases located in more than 200 meters and less than 400 meters of water) to deep gas royalty relief, the coverage of these definitions extends beyond the existing rule, which applies only to leases in 200 meters of water or less.

Further, the existing rule does not cover all leases located in water entirely or partly less than 200 meters deep. At the end of October 2006, about 70 leases in that water depth range are subject to deep gas RSV's, conditions, and requirements specified in the lease instruments because their lessees did not opt to convert to the deep gas royalty relief terms in the existing regulations. To accommodate section 344 requirements for these leases, MMS proposes to add a definition of “non-converted lease” in § 203.0. This category of leases must be separated from leases in the 0-200 meter water depth category that are covered by the existing rule because their deep gas wells have different timing and reservoir conditions for qualification, earn different RSV's, and are subject to different price thresholds.

In addition to distinguishing between deep wells and ultra-deep wells, MMS further proposes to add definitions for the terms “phase 1 ultra-deep well,” “phase 2 ultra-deep well,” and “phase 3 ultra-deep well.” The proposed royalty relief treatment of ultra-deep wells depends first on whether an ultra-deep well was drilled before or after the date of publication of this proposed rule. Wells drilled before the date of publication of the proposed rule are phase 1 ultra-deep wells.

A phase 1 ultra-deep well would be an ultra-deep well on a lease that is located in water entirely or partly less than 200 meters deep for which drilling began before the date of publication of this proposed rule. In other words, these are wells that would continue to be treated the same as they are under the provisions of the existing rule for deep wells of more than 18,000 feet TVD SS. Phase 1 ultra-deep wells would not be eligible for the higher RSVs prescribed in section 344.

A phase 2 ultra-deep well would be an ultra-deep well for which drilling began on or after the publication date of this proposed rule and that falls into one of the three following categories: (1) The ultra-deep well begins gas production before May 3, 2009, on a lease that is located in water partly or entirely less than 200 meters deep that is not a non-converted lease; (2) the ultra-deep well begins gas production within the primary term of a non-converted lease; or (3) the ultra-deep well begins production before May 3, 2013, on a lease that is located in water entirely more than 200 meters and entirely less than 400 meters deep.

A phase 3 ultra-deep well would be an ultra-deep well for which drilling began on or after the publication date of this proposed rule and that begins gas production on or after the dates prescribed for production from a phase 2 ultra-deep well. Only phase 2 ultra-deep wells and phase 3 ultra-deep wells would be eligible to earn the higher 35 BCF RSV prescribed in section 344.

Because MMS also proposes to differentiate the treatment of ultra-deep wells that are sidetracks with a sidetrack measured depth of 20,000 feet or more from sidetracks with a sidetrack measured depth of less than 20,000 feet, MMS also proposes to add a definition of “ultra-deep short sidetrack” to mean ultra-deep wells that are sidetracks with a sidetrack measured depth of less than 20,000 feet.

The reasons for distinguishing between phase 2 and phase 3 ultra-deep wells relate to both the proposed royalty relief treatment of ultra-deep short sidetracks and the proposed price threshold provisions. Both of these matters are addressed in detail below.

Under the existing rule, the term “qualified well” means a deep well for which drilling begins on or after March 26, 2003, the date the original deep gas proposed rule was published, and which meets other applicable requirements. Qualified wells are wells to whose gas production an RSV may be applied. The fact that a well is a qualified well does not mean that it earns an RSV. A well must be a qualified well to earn an RSV, but it also must meet other requirements. Wells that earn an RSV are a subset of qualified wells. But RSVs also are applied to gas production from qualified wells that do not themselves earn an RSV. MMS proposes to amend the definition of “qualified well” and add definitions for “qualified deep well” and “qualified ultra-deep well,” to address all four categories of deep gas royalty relief that exist after enactment of section 344—namely, deep gas wells on leases located in less than 200 meters of water that are covered by the existing rule, deep gas wells on non-converted leases (all of which are in less than 200 meters of water), deep gas wells on leases located in 200-400 meters of water, and ultra-deep gas wells on leases in all water depths less than 400 meters.

MMS also proposes to revise the definition of “certified unsuccessful well” in § 203.0, used in the royalty suspension supplement provisions in re-designated §§ 203.45 and 203.46 (§§ 203.44 and 203.45 in the existing rule), to add the new 200-400 meter water depth category.

In the definition of “expansion project,” MMS proposes to specify that reservoirs to whose production an RSV would be applied under §§ 203.30 through 203.36 and 203.40 through 203.48 cannot be included as part of an expansion project.

MMS also proposes amendments to certain of the part 203 provisions to include leases offshore of Alaska under section 346 of the Energy Policy Act. These amendments would involve modifying the definitions of “development project” and “expansion project” and the royalty relief provisions for development projects and expansion projects in § 203.2. In addition, references to a lease location or water depth in §§ 203.60, 203.69, and 203.78, mention of a specific MMS Regional office in §§ 203.62, 203.70, 203.77, 203.81, and 203.90, and the associated price threshold provisions in § 203.78 would be revised to accommodate leases offshore of Alaska. Start Printed Page 28399

Royalty Relief for Drilling Ultra-Deep Gas Wells on Leases Not Subject to Deep Water Royalty Relief (§§ 203.30 through 203.36)

For the most part, the new proposed ultra-deep gas provisions in §§ 203.30 through 203.36 follow the structure of the existing deep gas rule at §§ 203.40 through 203.48, and many of the provisions are similar. MMS is also proposing changes in §§ 203.40 through 203.48 to accommodate the new ultra-deep gas provisions in §§ 203.30 through 203.36.

Which leases are eligible for royalty relief as a result of drilling an ultra-deep well? (§ 203.30)

Proposed § 203.30 prescribes the basic criteria for a lease to be eligible for deep gas royalty relief. Paragraph (a) of this proposed section follows the statutory requirement in section 344(a) and (b) that the lease must be located in the GOM wholly west of 87 degrees, 30 minutes West longitude.

Paragraph (c) of this proposed section implements the requirement of section 344(c) that deep gas royalty relief shall not apply to a lease for which deep water royalty relief is available. (In this context, “available” means either provided for in the lease terms or granted in response to an application.) This issue arises because section 344(b) requires the Secretary to extend deep gas royalty relief to leases located in more than 200 but less than 400 meters of water. Deep water royalty relief applied to leases in that water depth range under the Outer Continental Shelf Deep Water Royalty Relief Act of 1995, Pub. L. No. 104-58, Title III, 109 Stat. 563 (DWRRA). Thus, to be eligible for deep gas royalty relief, a lease located in more than 200 but less than 400 meters of water had to have been issued either before November 28, 1995 (the date of enactment of the DWRRA), or after November 28, 2000. Leases issued between those dates (i.e., in the first 5 years after the DWRRA's enactment) were issued under the mandatory deep water royalty relief provisions of DWRRA section 304. All the leases issued under section 304 provide for deep water royalty relief and therefore are not eligible for deep gas royalty relief.

A lease issued before November 28, 1995, would not be eligible for deep gas royalty relief if MMS had granted deep water royalty relief under section 302 of the DWRRA (adding 43 U.S.C. 1337(a)(3)(C)).

A lease issued after November 28, 2000, would not be eligible for deep gas royalty relief if MMS had granted deep water royalty relief under 30 CFR 203.60 through 203.79. The royalty suspension (RS) provisions in 30 CFR 260.120 through 260.124 that apply to post-November 2000 leases do not themselves grant deep water royalty relief and refer back to the specific lease terms. There are no RS leases in the 200-400 meter water depth interval—in other words, there is no lease issued in a lease sale held after November 28, 2000, in the 200-400 meter water depth interval that provides for any royalty relief in the lease terms. Therefore, the only leases issued in lease sales held after November 28, 2000, that are excluded from deep gas royalty relief are those that have applied for and been granted deep water relief under §§ 203.60 through 203.79.

Paragraph (b) of this proposed section reflects MMS' general proposal, under section 344(a)(2)(B), not to grant deep gas royalty relief if the lease has previously produced gas or oil from a deep well or an ultra-deep well. Proposed section 203.31(b) contains an exception.

If I have a qualified phase 2 or phase 3 ultra-deep well, what royalty relief would my lease earn? (§ 203.31)

In proposed § 230.31(a), the text preceding the table and the table reflect the interpretation of the statute described above that the first qualifying original phase 2 or phase 3 ultra-deep well on a lease that meets the requirements of proposed § 203.30 would earn an RSV of 35 BCF.

The table in § 230.31(a) shows that if a sidetrack drilled after the publication date of this proposed rule is completed to a depth below 20,000 feet TVD SS and has a length (measured depth) of at least 20,000 feet, i.e., a length equivalent to that of an original ultra-deep well, the sidetrack would earn an RSV of 35 BCF if there has been no gas production from a deep well or an ultra-deep well on the lease. As a practical matter, MMS believes that the only sidetracks that are likely to have a sidetrack measured depth of 20,000 feet or more are sidetracks drilled from a platform slot reclaimed from a previously drilled well. (See the inclusion in the definition of “sidetrack” in section 344(a)(3)(B)(ii)(I).) These wells are new wells and are the functional equivalent of original wells. (MMS does not believe that a 20,000-foot-long sidetrack drilled to a new objective bottom-hole location by leaving a previously drilled well—see section 344(a)(3)(B)(i)—is a practical likelihood.)

As stated above, in light of the fact that section 344 requires MMS to grant either a 35 BCF RSV or 0 BCF RSV, MMS does not believe it is appropriate or consistent with statutory objectives or congressional intent to grant a 35 BCF RSV for a relatively short sidetrack simply because it was completed at a depth below 20,000 feet TVD SS. (An example would be a 6,000-foot-long sidetrack that left the main wellbore at 14,700 feet and was completed at 20,100 feet TVD SS.) It would appear that under such a circumstance, granting a 35 BCF RSV would be disproportionate to the costs and risks of drilling the sidetrack and to the degree of relief that would encourage ultra-deep production.

At the same time, in view of the general congressional policy underlying section 344, it is difficult to believe that Congress intended to compel MMS to grant either a disproportionate RSV or no RSV at all for a sidetrack drilled to an ultra-deep depth from an existing wellbore (if there has been no production from any deep or ultra-deep well) simply because the sidetrack was completed to a depth below 20,000 feet TVD SS, even though the statutory phraseology could be read to permit no other result. Therefore, MMS proposes to treat sidetracks of lengths less than an original ultra-deep well but completed to ultra-deep depths (i.e., ultra-deep short sidetracks) in the same manner as they are treated under the existing rule, to more fully effectuate what appears to be the overall intent of Congress. Under the proposed § 203.31(a), such a sidetrack would earn an RSV of 4 BCF plus 600 MCF times the sidetrack measured depth. Likewise, the same sunset dates would apply to these sidetracks that apply to sidetracks under the existing rule (and as the existing rule is proposed to be amended to add leases in the 200-400 meter water depth range under section 344(b)). In other words, the ultra-deep short sidetrack would have to be a phase 2 ultra-deep well. If an ultra-deep short sidetrack would not have earned an RSV under the existing rule (as it is proposed to be amended to add leases in the 200-400 meter water depth range), MMS proposes to grant no RSV to it here.

MMS specifically requests comments regarding the adequacy of its authority to prescribe this RSV. If MMS concludes that the proposed provision is not supported by adequate statutory authority, MMS' alternative proposal would be to grant no RSV to an ultra-deep short sidetrack, and not to grant an RSV of 35 BCF.

Proposed § 203.31(b) contains an exception from the requirement that the lease not have produced previously from any deep well or ultra-deep well. Some background explanation is necessary to explain the reasons for the Start Printed Page 28400proposed exception. Under the existing rule, in cases where a deep well completed at a depth between 15,000 feet and 18,000 feet TVD SS has produced and earned an RSV of 15 BCF, a subsequent well completed at a depth greater than 18,000 feet TVD SS may earn an additional RSV of 10 BCF. But under the proposed rule, if the subsequent well is an ultra-deep well (completed at a depth greater than 20,000 feet TVD SS), it would earn no additional RSV. Thus, if a lessee has produced from a deep well that earned an RSV of 15 BCF and then drills an ultra-deep well, the lease would get less royalty relief than under the existing rule and less royalty relief than if the lessee had drilled a deep well to a depth between 18,000 and 20,000 feet TVD SS. Section 344, however, allows that result. (MMS anticipates that the number of cases in which this scenario might occur before deep gas royalty relief under the existing rule expires in May 2009 would be very small.)

Similarly, consistent with the proposed policy explained above, MMS proposes to grant no RSV for a sidetrack completed at a depth of 20,000 feet or more if there has been production from any deep well, regardless of the length of the sidetrack. This proposal would result in the possibility of a similar scenario arising in which a lessee drills a sidetrack to an ultra-deep depth after the lease has earned an RSV of 15 BCF from a well completed at a depth between 15,000 feet and 18,000 feet TVD SS. Under the proposed rule, the sidetrack would earn no additional RSV, while under the existing rule it would earn an RSV of 4 BCF plus 600 MCF times the sidetrack measured depth, up to a maximum of an additional 10 BCF. Under such a scenario, the lease would receive less royalty relief than under the existing rule and less than if the lessee had completed the sidetrack at a depth between 18,000 feet and 20,000 feet TVD SS.

The exception proposed in § 203.31(b) arises because all leases issued in water depths of 200 meters or less during 2004 and 2005, that is in lease sales 190, 192, 194, and 196, specifically cite the existing deep gas rule in the lease terms—unlike leases issued before 2004 or after 2005. Although deep gas royalty relief under the existing rule was effective for wells drilled after publication of the proposed rule (March 26, 2003), that relief did not become effective until the final rule. The final rule initially had an effective date of March 1, 2004, but an administrative oversight led to the effective date of the final rule being delayed until May 3, 2004. The lease sales held in 2004 were all after the initial effective date, and the terms of the leases issued in those sales referred to royalty relief terms in the existing rule. While MMS does not believe that a reference to the citation of the existing rule makes the terms of the rule as they existed on that date a fixed property right, MMS also doubts that Congress would have intended to reduce potential royalty relief that existing leases already had under the rules on the date of enactment of the Energy Policy Act if the lease instrument itself referred to the rule.

Leases issued before 2004, which preceded the effective date of the existing rule, do not refer to the rule in their terms. For these leases, the existing rule, including the opportunity for a deep well to earn relief after the lease already has production from a deep well, was a benefit that MMS granted on its own initiative after the lease was already in force. MMS may change, or even entirely eliminate, that benefit prospectively through a subsequent rulemaking should it choose to do so. In this rulemaking, MMS proposes to do just that—eliminate the additional relief these pre-2004 leases could have earned for drilling a well deeper than 20,000 feet TVS SS after producing from a well completed between 15,000 and 18,000 feet TVD SS.

However, to avoid potential future conflict regarding the terms of leases issued in the four Gulf of Mexico sales held in 2004 and 2005, i.e., Sales 190, 192, 194, and 196, MMS proposes to allow the additional relief associated with drilling an ultra-deep well after producing from a well completed between 15,000 and 18,000 feet TVD SS provided for in the existing rule for these leases. MMS specifically requests comments on this proposed exception.

MMS further notes that the issue discussed in the preceding paragraph does not arise in the context of leases issued between January 1, 2001 and January 1, 2004, that contain deep gas royalty relief in their lease terms and for which the lessee exercised the option in § 203.48, re-designated § 203.49 in this proposed rule, to convert to the rule. The lessees filed a form with an election to go under the rule. The intent was to treat these leases identically to pre-2001 leases. Nor does the issue discussed above arise in the context of leases issued after January 1, 2001, that are located partly in water less than 200 meters deep (and, therefore, partly in water more than 200 meters deep) that are covered by the existing rule because no deep water royalty relief terms in statutes or lease terms apply (see the existing § 203.40(a)(2) and (3)). These leases also are in a situation that is functionally identical to pre-2001 leases, and for which there is no question that MMS may change the rule prospectively. Therefore, MMS does not propose to include leases in these two categories within the exception proposed in § 203.31(b).

Proposed § 203.31(c) specifies that all gas production from qualified wells (i.e., qualified deep and qualified ultra-deep wells) on the lease, including gas production that is not subject to royalty, counts toward the RSV earned by a qualified deep well or qualified ultra-deep well on the lease, in the manner required under proposed §§ 203.32 and 203.36. For example, assume that the lessee drills and produces from a qualified 22,000-foot phase 2 ultra-deep well that earns an RSV of 35 BCF. Further assume that the lessee then drills and produces from two qualified deep wells (completed at 16,500 feet TVD SS and 17,200 feet TVD SS, respectively), neither of which earns an RSV. In this circumstance, the 35 BCF RSV earned by the first well applies to the earliest production from all 3 wells until the 35 BCF of RSV is used.

Proposed § 203.31(d) would provide that lessees may recoup any royalties paid on production from a qualified phase 2 or phase 3 ultra-deep well that occurs before 30 days after the date of publication of the final rule. This provision is necessary because of the provisions in subsections (a) and (b) of section 344 that “[r]egulations issued under this subsection shall be retroactive to the date that the notice of proposed rulemaking is published in the Federal Register.” Those provisions make royalty relief applicable to gas produced after the date of the proposed rule and before the final rule. A lessee may begin producing gas from a qualified phase 2 or phase 3 ultra-deep well after the date of this proposed rule, but would not be able to claim royalty relief under this proposed rule for any of that production unless and until a final rule is promulgated and becomes effective. (However, royalty relief may be available under existing regulations.) The lessee therefore might have to pay royalty on production occurring before a final rule becomes effective. Because the royalty relief provided for under section 344 would then be retroactive to the proposed rule's publication date, the lessee would have to recoup or seek a refund of the royalties paid in the meantime. Proposed paragraph (d) would clarify that the lessee could do so.

Proposed § 203.31(e) includes several examples of how the proposed provisions would work in various circumstances. Example 1 illustrates a Start Printed Page 28401situation in which a lessee drills and produces from a qualified ultra-deep well after the date of this proposed rule (in this example, a phase 2 ultra-deep well), and earns a 35 BCF RSV. The lessee then drills a second qualified ultra-deep well on the lease. Under the proposed rule, the second ultra-deep well would not earn any additional RSV. (The 35 BCF RSV would be applied to gas production from both wells.)

MMS bases this proposal on section 344(a)(2), which expressly grants the Secretary discretion whether to provide royalty relief for ultra-deep wells if the lease has previously produced from a well with a perforated interval the top of which is at least 15,000 feet TVD SS (i.e., any deep well under the existing rule). As discussed previously, section 344 does not command the Secretary to grant 35 BCF of royalty relief for each and every ultra-deep well drilled and produced on a lease simply because a well is an ultra-deep well. To accomplish the statutory objective of encouraging exploration for and production from ultra-deep wells, and at the same time to avoid excessive reductions in royalty payments that would not further that objective, MMS proposes to limit the 35 BCF in royalty relief to the first producing ultra-deep well on the lease that was drilled after the publication date of the proposed rule, with the condition that there has been no production from any other deep wells or ultra-deep wells on the lease.

The same rationale would apply to situations where more than one ultra-deep well is drilled after the date of this proposed rule. MMS proposes that the first ultra-deep well drilled after the publication date of this proposed rule that produces from a lease that has not previously produced from a deep well or an ultra-deep well would earn a 35 BCF RSV, but subsequent ultra-deep wells on the same lease would not earn additional RSVs. MMS believes that this is clearly within the discretion granted to the Secretary in section 344(a)(2), which permits the Secretary to disallow royalty relief if there has been prior production from any deep well.

Example 2 illustrates a situation in which a lessee has produced gas from an ultra-deep well drilled on the lease before the effective date of the ultra-deep provisions as specified in section 344(a), i.e., the date of publication of this proposed rule. Under the proposed definitions, this would be a phase 1 ultra-deep well. In Example 2, the ultra-deep well was drilled before the publication date of this proposed rule but after March 26, 2003. In this circumstance, any ultra-deep well drilled after the publication date of this proposed rule (the second ultra-deep well on the lease) would not earn an RSV. However, in Example 2 the ultra-deep well drilled after March 26, 2003, is also a qualified deep well under the existing rule and may qualify for an RSV of 25 BCF under its provisions. If the first ultra-deep well had earned 25 BCF under the current rule, the lease would keep that relief. However, drilling an additional ultra-deep well after the publication of this proposed rule would not earn the lease any additional royalty relief.

Example 3 illustrates a situation in which a deep well was drilled and produced before the existing deep gas rule became effective. The deep well therefore did not earn an RSV for the lease. The lessee then drilled a phase 2 ultra-deep well after the publication date of the proposed rule. Under the proposed rule, the ultra-deep well would not earn an RSV.

In Example 4, a lessee drills and produces gas from a qualified phase 2 ultra-deep well and earns an RSV of 35 BCF on a lease located in water 300 meters deep. Subsequently, the lessee drills a deep well that is not an ultra-deep well. Under the existing regulations at § 203.41(e), the later well would not earn any RSV because the lease has already produced from a deep well with a perforated interval the top of which is 18,000 feet TVD SS or deeper. However, any remaining RSV earned by the ultra-deep well would be applied to production from the new deep well, as well as production from the ultra-deep well that earned the RSV, because the new deep well is also a qualified well under the hypothetical facts stated. In contrast, if the new deep well hypothesized in this example (for which drilling begins in 2010) begins production on or after May 3, 2013 (or if the new deep well were on a lease located in water less than 200 meters deep), the new deep well would not be a qualified well. In that event, the lessee would have to pay royalty on all production from that well notwithstanding the RSV earned by the phase 2 ultra-deep well.

In Example 5, a lessee drills and produces from a qualified deep well completed at a depth between 15,000 and 18,000 feet TVD SS that earns an RSV of 15 BCF for the lease under the existing § 203.41. The lessee then later drills and produces from a qualified phase 2 or phase 3 ultra-deep well (depending on the water depth of the lease) on the same lease. The ultra-deep well would earn no additional RSV under the proposed rule, but the 15 BCF RSV earned by the deep well would be applied to production from both the deep well and the ultra-deep well. Example 7 illustrates an exception to this case.

Example 6 illustrates the proposed difference in consequences between drilling sidetracks of different lengths to ultra-deep depths. Section 344(a)(2) provides discretion whether to grant royalty relief if the ultra-deep well is a sidetrack. To be consistent with the statutory objectives, and to avoid granting excessive amounts of royalty relief for sidetracks that are shorter than the length necessary for an original well from the surface to earn royalty relief as an ultra-deep well, MMS proposes to grant a 35 BCF RSV if the sidetrack measured depth (i.e., the length of the sidetrack) is at least 20,000 feet and the sidetrack has a perforated interval the top of which is at least 20,000 feet TVD SS (and otherwise is a qualified phase 2 or phase 3 ultra-deep well). However, MMS would not grant additional royalty relief under the section 344 ultra-deep provisions if the sidetrack measured depth is less than 20,000 feet. A sidetrack of less than 20,000 feet measured depth may qualify for a lesser RSV that is equivalent to the relief granted under the deep well provisions if it is a phase 2 ultra-deep well, i.e, one that begins production before the applicable sunset date for royalty relief for deep wells.

Example 7 illustrates the exception proposed in § 203.31(b). In this example, the lease was issued after the initial effective date of the existing rule and before the enactment of the Energy Policy Act, and its terms specifically referred to the existing rule. In this example, the lessee completed a deep well in the 15,000-18,000 feet TVD SS water depth range that earned a 15 BCF RSV before enactment of the Energy Policy Act. The lessee then drilled and completed a phase 2 ultra-deep well. Under the proposed § 203.31(b) exception, the ultra-deep well would earn an additional 10 BCF RSV.

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

This section addresses various further requirements and some restrictions that would apply to RSVs earned by ultra-deep wells. These are self-explanatory.

To which production do I apply the RSV earned by qualified phase 2 and phase 3 ultra-deep wells on my lease? (§ 203.33)

Proposed § 203.33(a), which applies to leases that are not within an MMS-approved unit, has a structure similar to Start Printed Page 28402the existing deep well provision at § 203.42(a), re-designated § 203.43(a) in this proposed rule. This paragraph specifies that an RSV earned by a qualified phase 2 or phase 3 ultra-deep well applies to all gas produced from all qualified wells (i.e., all qualified deep and qualified ultra-deep wells) on the lease. Proposed § 203.32(f) also reflects this principle.

Proposed § 203.33(b), which applies to leases within a unit, follows the same structure for ultra-deep wells that the existing § 203.42(b), re-designated § 203.43(b) in this proposed rule, has for deep wells. An RSV earned by a qualified phase 2 or phase 3 ultra-deep well would be applied to production from all qualified wells on non-unitized areas of the lease on which the ultra-deep well is located and to production allocated to the lease, under the approved unit agreement, from qualified wells on unitized areas of the lease and on other leases in the unit. The allocation of production from qualified wells on other leases in the unit would not increase the RSV for your lease.

Proposed paragraph (c) of this section is similar to § 203.42(e) of the existing rule, re-designated § 203.43(c) in this proposed rule and specifies that the lessee would have to pay royalties on all production when the cumulative production from all qualified wells on the lease reaches the applicable RSV.

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

This proposed provision is analogous to the existing § 203.42(d) for deep wells, re-designated § 203.43(d) in this proposed rule, with changes to reflect section 344's addition of leases in the 200-400 meter water depth range.

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

This proposed section is analogous, with one exception, to the existing § 203.43 that applies to deep wells, re-designated § 203.44 in this proposed rule. That exception deals with the temporary extension of the deadline by which production must start to qualify a well for relief. There is no deadline by which production must start for most ultra-deep wells to qualify for relief, so no such extension is needed. The analogous temporary extension is provided for ultra-deep short sidetracks which do face a deadline.

Do I keep royalty relief if prices rise significantly? (§ 203.36)

As explained above, the concept underlying the proposed price threshold terms is that to the extent ultra-deep gas and deep gas royalty relief granted under the proposed provisions would have been granted under the existing rule for existing leases (as of the date the final rule becomes effective), the existing rule's price threshold ($9.88 per MMBtu, adjusted annually for inflation after calendar year 2006) would apply. The value $9.88 per MMBtu in 2006 dollars is equivalent to the value $9.34 per MMBtu in 2004 dollars as stated in the existing rule. The inflation adjustment is described in the existing § 203.47 (redesignated § 203.48 in this proposed rule). The MMS webpage at http://www.mms.gov/​econ/​DWRRAPrice1.htm shows results from applying that adjustment. Excepted where noted, all price threshold values discussed in this proposed rule are stated in 2006 dollars. Hence, those values are adjusted for inflation after 2006.

For all deep gas and ultra-deep gas royalty relief that results from section 344's new provisions, and for deep gas and ultra-deep gas royalty relief for leases issued after the effective date of the final rule, a different price threshold of $4.47 per MMBtu, adjusted annually for inflation after calendar year 2006, would apply. Lessees would have to pay royalty on all gas production to which an RSV otherwise would be applied under the proposed ultra-deep well provisions for any calendar year in which the average daily closing New York Mercantile Exchange (NYMEX) natural gas price exceeds $4.47 per MMBtu (adjusted for inflation after 2006).

The RSVs specified for ultra-deep wells in proposed § 203.31 for existing leases (and any future leases issued before the effective date of the final rule) are a consequence of section 344, with three exceptions. The first exception is the first 25 BCF of RSV earned under proposed § 203.31(a) by a phase 2 ultra-deep well on a lease located in water partly or entirely less than 200 meters deep (i.e., a well drilled after the publication of this proposed rule that begins production before May 3, 2009). Such a well would also earn a 25 BCF RSV under the existing rule, so this RSV would be subject to the same price threshold as in the existing rule—$9.88 per MMBtu, adjusted annually after calendar year 2006 for inflation.

The second exception is an RSV of up to 10 BCF earned by a phase 2 ultra-deep well under proposed § 203.31(b)'s exception for leases issued after the initial effective date of the existing rule and before enactment of the Energy Policy Act that specifically refer to the existing rule in the lease terms. Such a well would earn the RSV specified in proposed § 203.31(b) under the existing rule. Therefore, paragraph (a) of this proposed provision would apply the same price threshold as in the existing rule to this RSV of 10 BCF, i.e., $9.88 per MMBtu, adjusted annually after calendar year 2006 for inflation.

The third exception is the first 20 BCF of the 35 BCF RSV earned by a phase 2 ultra-deep well on a non-converted lease that begins production before 5 years after the date the lease was issued. Parallel to the situation with the RSV under proposed § 203.31(a), paragraph (b) of proposed § 203.36 would apply the price threshold specified in the lease terms to this RSV. For non-converted leases issued in the central GOM lease sale in 2001 (Sale 178), that price threshold originally was $3.50 per MMBtu, adjusted annually after calendar year 2000 for inflation. For non-converted leases issued in the western GOM sale in 2001 and the central and western GOM sales in 2002 and 2003 (Sales 180, 182, 182, 185, and 187), that price threshold originally was $5.00 per MMBtu, adjusted annually after calendar year 2000 for inflation. Inflation between 2000 and 2006 raised these price thresholds to $4.00 and $5.72 per MMBtu, respectively, as of 2006. The proposed § 203.36(a)(3) and (4) therefore express the price thresholds at those levels, and they would be adjusted annually after calendar year 2006 for inflation in the same manner as all the other price thresholds.

Paragraph (a)(2) of this proposed section addresses the RSVs earned by ultra deep wells that result from section 344 or that are earned by wells on leases issued after the effective date of the final rule that are located party or entirely in less than 200 meters of water. These RSVs include (1) the last 10 BCF (in the case of a non-converted lease, the last 15 BCF) of the 35 BCF of RSV earned under § 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 the effective date of the final rule; (2) any RSV earned under § 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 after the effective date of the final rule; (3) any RSV earned under § 203.31(a) by a phase 2 ultra-deep well on a lease that is located in water entirely more than 200 meters and entirely less than 400 meters deep; and Start Printed Page 28403(4) any RSV earned under § 203.31(a) by a phase 3 ultra-deep well.

MMS proposes to apply a lower price threshold to the RSV that results from section 344 than the $9.88 per MMBtu (adjusted for inflation after 2006) level in the existing rule. Three factors drive this decision. First, the absence of a sunset date for ultra-deep well relief risks generating in perpetuity a fiscally expensive program that may prove unnecessary or ineffective. A lower price threshold will mitigate the likelihood of such an outcome when the program is least necessary, that is, when prices are higher than expected. Second, results to date show a weaker than expected lessee reaction to the deep drilling incentive in the existing rule. This experience demonstrates the prudence of imposing tighter fiscal controls on the statutorily mandated expansion of that program. Third, this price threshold would apply when the deep drilling incentive would likely be less important, e.g., when other sources of natural gas have become more available and when current long range forecasts indicate natural gas prices will have retreated significantly from current levels.

MMS analyzed several different price thresholds taking into consideration predicted gas prices, volatility of gas prices, and expected economics for deep and ultra-deep wells covered by the Energy Policy Act. The economic analysis that accompanies this rulemaking provides estimates of the effects of each option on measures of social welfare such as consumer and producer surplus, production and royalty revenues.

MMS has chosen to propose $4.47 per MMBtu, adjusted annually for inflation after calendar year 2006, for incentives covered by the Energy Policy Act for several reasons. First, it simplifies the gas price threshold structure across royalty relief programs, because $4.47 per MMBtu (adjusted for inflation after 2006) is the same gas price threshold that applies to all leases covered by the DWRRA. That means both congressionally mandated royalty relief programs provide the same balance between the incentive to explore and produce in a frontier area and the fiscal risk of offering that categorical incentive. Second, this choice recognizes that gas produced from deepwater leases and gas produced from deep wells on leases in shallower waters sells in the same market. The RSV in each program is the policy variable tailored to the costs and risks specific to the different frontier areas that produce that product. Third, though recent gas market conditions led MMS to use price thresholds above $4.47 per MMBtu (adjusted for inflation after 2006), those higher price thresholds are used where bonus bids or sunset provisions provide added controls against incurring unnecessary fiscal costs. Finally, given the typical time frame between the decision to drill and the potential emergence of deep gas production, the ever-present risk exists that future events will prove the assumptions and forecasts used to justify the proposed additional RSV incentives inaccurate. This observation suggests the need for a conservative policy for selecting the appropriate deep gas price threshold level.

Also, § 203.36(a) includes a default price threshold of $4.47 per MMBtu (adjusted for inflation after 2006) for ultra-deep wells on future leases should their lease terms fail to provide for a different price threshold.

Proposed § 203.36(c) sets out several examples that clarify how the price thresholds would work. Example 1 assumes 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. The ultra-deep well earns the lease an RSV of 35 BCF. The well produces a total of 18 BCF by the end of 2009. In both 2008 and 2009, the average daily NYMEX closing natural gas price is less than $9.88 per MMBtu (adjusted for inflation after 2006). In 2010, the well produces another 13 BCF. In that year, the average daily closing NYMEX natural gas price is greater than $4.47 per MMBtu (adjusted for inflation after 2006), but less than $9.88 per MMBtu (adjusted for inflation after 2006). Under these circumstances, the first 7 BCF produced in 2010 will exhaust the first 25 BCF of the 35 BCF RSV that the well earned that is subject to the $9.88 per MMBtu (adjusted for inflation after 2006) threshold. The lessee must pay royalty on the remaining 6 BCF produced in 2010, which is subject to the $4.47 per MMBtu threshold (adjusted for inflation after 2006) that was exceeded.

Example 2 addresses a situation in which a lessee in 2008 drills and produces from Well No.1, a qualified deep well, to a depth of 15,500 feet TVD SS that earns a 15 BCF RSV for the lease under § 203.41, which would be subject to a price threshold of $9.88 per MMBtu (adjusted for inflation after 2006). Later in 2008, the lessee 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. Then in 2013, the lessee drills and produces from Well No. 3, a qualified phase 3 ultra-deep well that earns no additional RSV. Further assume that in 2013, the average daily closing NYMEX natural gas price exceeds the $4.47 per MMBtu (adjusted for inflation after 2006) but does not exceed $9.88 per MMBtu (adjusted for inflation after 2006). In 2013, 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 assumes the same initial facts regarding the 3 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, because the $9.88 per MMBtu (adjusted for inflation after 2006) price threshold is not exceeded.

In 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, and would earn the lease an RSV of 35 BCF. Further assume that during 2010, the average daily closing NYMEX natural gas price exceeds $4.47 per MMBtu (adjusted for inflation after 2006) but does not exceed $9.88 per MMBtu (adjusted for inflation after 2006). Because the lease is located in more than 200 but less than 400 meters of water, the price threshold of $4.47 per MMBtu (adjusted for inflation after 2006) applies to all of the RSV, and the lessee will owe royalty on all gas produced from the ultra-deep well in 2010. The volume of gas produced from the ultra-deep well in 2010 counts against the RSV, as provided in proposed paragraph (e).

The same principles would apply when a lessee applies RSVs to production allocated to a lease from qualified wells on other leases under an MMS-approved unit agreement. The price threshold associated with the RSV determines whether royalty is suspended on the production volume allocated to the lease.

Proposed § 203.36(d) provides that in the event the price threshold is exceeded in any calendar year, royalties Start Printed Page 28404on production would be due by March 31 of the following year. The purpose of this proposed provision would be to allow the lessee a reasonable time to compute and pay royalties for the year for which they were due. If royalties were not paid by that date, late payment interest would accrue beginning April 1 until paid. MMS is also proposing a corresponding change to the late payment interest provision in the existing deep gas rule at § 203.47 (proposed to be redesignated as § 203.48).

Finally, paragraph (e) of this proposed section specifies that production volumes on which a lessee must pay royalty as a result of the applicable price threshold being exceeded would count against the RSV.

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

MMS is proposing to expand the existing deep well eligibility provision at § 203.40(b) to require that the lease be located in the GOM wholly west of 87 degrees, 30 minutes West longitude in water depths entirely less than 400 meters deep to implement section 344(b). MMS also proposes other amendments to reflect the addition of leases in the 200-400 meter water depth range, and proposes to change the wording of the section heading to reflect the change in the definition of “deep well” and the addition of the definition of “phase 1 ultra-deep well.”

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

MMS proposes to modify the tables at existing § 203.41(a) and (c), other parts of the text of the section, and the wording of the section heading to reflect the new ultra-deep well category of royalty relief and the changes in the definition of terms. The proposed revision adds a new paragraph (a) to emphasize the pivotal role that prior deep production plays in the incentive. Also, the proposal changes the existing paragraph (a) to paragraph (b), and combines the content of the existing paragraphs (b) and (d) into a new paragraph (d), and divides that content into numbered subparagraphs.

The expanded coverage of this section and the proposed new paragraph (e) result from section 344's extension of royalty relief for deep wells to leases located in the 200-400 meter water depth interval. The extent of and requirements for deep gas royalty relief would not change, except that (1) there is a later proposed sunset date for deep gas royalty relief for leases in the 200-400 meter water depth range, and (2) lessees may recoup royalties paid before the effective date of the final rule on volumes that are subject to an RSV for leases in that water depth range, as explained immediately below.

Proposed new paragraph (e) of this section is analogous to proposed § 203.31(d) for ultra-deep wells to allow lessees to recoup any royalties paid on production from a qualified deep well on a lease located in the 200-400 meter water depth range that occurs before 30 days after the date of publication of the final rule which is subject to an RSV earned by either a deep well or an ultra-deep well. As explained previously, this provision is part of implementing section 344's retroactivity provisions.

MMS proposes to move the examples in paragraphs (b) and (d) of the existing rule to a new paragraph (f). Example 5 in this new paragraph (Example 2 in the existing paragraph (d)) also would be revised to reflect the effect of the new proposed ultra-deep gas provisions.

What conditions and limitations apply to royalty relief for deep wells and phase 1 ultra-deep wells? (§ 203.42)

This new proposed section corresponds to paragraphs (e) through (k) of the existing § 203.41. Paragraph (c) of the existing § 203.42 is transferred to paragraph (h) of this proposed section. The proposed revisions to § 203.42, as well as proposed revisions to other sections of the existing rule, also include minor wording changes for precision and consistency with usage throughout the proposed rule. MMS proposes to redesignate the existing §§ 203.42 through 203.48 as §§ 203.43 through 203.49.

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

MMS proposes changes to this re-numbered section to implement section 344's extension of royalty relief for deep wells to leases in the 200-400 meter water depth interval and to reflect the proposed changes in defined terms. MMS also proposes to revise the examples to improve the illustration of how this section operates. Paragraph (e) of the existing § 203.42 is moved to paragraph (c) of this proposed section. Paragraph (f) of the existing section is made part of paragraph (d) of the proposed section.

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

The proposed changes in wording to this section reflect the addition of leases in the 200-400 meter water depth range and the changes in definitions of terms.

If I drill a certified unsuccessful well, what royalty relief will my lease earn? (§ 203.45)

MMS proposes minor changes in wording to reflect the proposed changes in definitions and for consistency of usage throughout the proposed rule. The substantive change in coverage of existing § 203.44 (redesignated § 203.45) for certified unsuccessful wells to extend these provisions to leases in the 200—400 meter water depth interval are a consequence of the proposed change to the defined term “certified unsuccessful well” in § 203.0.

To which production do I apply the RSV from drilling one or two certified unsuccessful wells on my lease? (§ 203.46)

The proposed changes to this section, as well as in the redesignated § 203.49, reflect the revised section references necessary for consistency with changes proposed elsewhere in this part.

What administrative steps do I take to obtain and use the royalty suspension supplement? (§ 203.47)

The proposed changes in wording to this section reflect the addition of leases in the 200-400 meter water depth range and the changes in definitions of terms. The provisions of the current § 203.46(c) requiring submission of necessary information no later than August 3, 2004, for certified unsuccessful wells drilled after the date of publication of the proposed rule that resulted in the current rule (March 26, 2003) and before the effective date of the current rule (May 3, 2004) are obsolete and no longer necessary. This proposed rule therefore would delete them.

Do I keep royalty relief if prices rise significantly? (§ 203.48)

MMS proposes to revise existing § 203.47, as well as re-designate it § 203.48, to reflect the overall proposed price threshold approach discussed above. The price threshold under the existing rule ($9.88 per MMBtu, adjusted annually after calendar year 2006 for inflation) would continue to apply to deep gas royalty relief for leases located in water partly or entirely less than 200 meters deep that are in existence before the effective date of the final rule. The new price threshold of Start Printed Page 28405$4.47 per MMBtu (adjusted for inflation after 2006) would apply to deep gas royalty relief for leases in that water depth range issued after the effective date of the final rule and for all leases in the 200-400 meter water depth range. Also, § 203.48 includes a default price threshold of $4.47 per MMBtu (adjusted for inflation after 2006) for deep wells on future leases should their lease terms fail to provide for a different price threshold.

MMS proposes to revise the language of the royalty payment deadline that applies in the event the price threshold is exceeded to read consistently with the corresponding provision of proposed § 203.36(d), but the substantive meaning would remain unchanged.

MMS also requests comments on whether any other provisions in §§ 203.40 through 203.48, applicable to deep wells, need to be changed to conform with section 344 so that the provisions governing the different categories of deep gas wells function together harmoniously, or whether any other of these provisions should be applied to ultra-deep wells.

Summary of the Proposed Deep Gas Royalty Relief Program

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

BCFBillion cubic feet.
KThousand.
MDMeasured depth (length in thousands of feet).
MMBtuMillion British thermal units.
NANot applicable.
PTPrice Threshold (2006$ per MMBtu).
PRProposed rule implementing Section 344 of the Energy Policy Act of 2005.
RSSRoyalty Suspension Supplement (in BCF).
RSVRoyalty Suspension Volume (in BCF).
STSidetrack.
TVD SSTrue Vertical Depth Sub-Sea.

The last two columns of each table outline the royalty relief that exists in the current regulations and the additional relief proposed 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 $2006/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

Well typeSpud date1st date producedRoyalty relief under existing regulationsAdditional relief under proposed section 344 rulemaking
Depth (feet): RSV [RSS], PT
AWell #1: Original well or ST.Before 3/26/2003.Not Relevant.• None.• NA
BWell #1: Original well.Between 3/26/2003 and PR.Before 5/3/2009.• If 15K-18K TVD SS: 15 BCF, $9.88, or • If ≥ 18K TVD SS: 25 BCF, $9.88.• NA
CWell #1: ST.• If ≥ 15K TVD SS: 4 BCF+ (0.6 * MD) BCF up to 15 or 25 BCF, $9.88.• NA
DWell #1: Original well.After PR.• If 15K-18K TVD SS: 15 BCF, $9.88 a, or • If 18K-20K TVD SS: 25 BCF, $9.88 a, or • If ≥ 20K TVD SS: 1st 25 BCF, $9.88 a.• NA.   • NA.   • If ≥ 20K TVD SS: Add 10 BCF, $4.47 a.
EWell #1: ST with MD ≥ 20K ft.• If ≥ 20K TVD SS: 1st 25 BCF, $9.88 a.• If ≥ 20K TVD SS: Add 10 BCF, $4.47 a.
FWell #1: ST with MD < 20K ft.• If ≥ 15K TVD SS: 4 BCF + (0.6 * MD) BCF up to 15 or 25 BCF, $9.88 a.• None.
GWell #1: Original well or ST with MD ≥ 20K ft.After 5/3/2009.• None.• If ≥ 20K TVD SS: 35 BCF, $4.47 a.
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HWell #1: Original well.Between 3/26/2003 and 5/3/2009.Never.• If 15K-18K TVD SS: [None], or • If ≥ 18K TVD SS: [5 BCF], $9.88 a.  • NA.
IWell #1: ST with MD ≥ 10K ft.• If 15K-18K TVD SS: [None], or • If ≥ 18K TVD SS: [0.8 BCF + (0.12 * MD) BCF up to 5 BCF], $9.88 a.  • NA.
a For wells on leases issued after [DATE THAT IS 30 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register], the price threshold will be $4.47/MMBtu (adjusted for inflation after 2006) unless the lease terms prescribe a different price threshold.

For example, suppose an original well (one that does not use an existing wellbore) is drilled to a depth of 23,000 feet TVD SS between September and December 2007 (after this proposed rule has been 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 $9.88 per MMBtu (adjusted for inflation after 2006) while the remaining RSV of 10 BCF is subject to a price threshold of $4.47 per MMBtu (adjusted for inflation after 2006). Alternatively, if delays prevent production 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 $4.47 per MMBtu (adjusted for inflation after 2006). 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 $9.88 per MMBtu (adjusted for inflation after 2006).

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 That Converted to the Royalty Relief Terms in the Existing Rule

Well typeSpud date1st date producedRoyalty relief under existing regulationsAdditional relief under proposed section 344 rulemaking
Depth (feet): RSV [RSS], PT
AWell #2: Original well.Between 3/26/2003 and PR.Before 5/3/2009.• If 15K-18K TVD SS: None, or • If ≥ 18K TVD SS: 10 BCF, $9.88.• NA.
BWell #2: ST.• If 15K-18K TVD SS: None, or • If ≥ 18K TVD SS: 4 BCF + (0.6 * MD) BCF up to 10 BCF, $9.88.• NA.
CWell #2: Original well.After PR.• If 15K-18K TVD SS: None, or • If 18K-20K TVD SS: 10 BCF, $9.88 a.• If ≥ 20K TVD SS: + 10 BCF if lease issued in lease sale held between 1/1/2004 and 12/31/2005 otherwise none, $9.88.
DWell #2: ST with MD ≥ 20K ft.• If 15K-18K TVD SS: None, or • If 18K-20K TVD SS: 4 BCF + (0.6 * MD) BCF up to 10 BCF, $9.88 a.• If ≥ 20K TVD SS: + 10 BCF if lease issued in lease sale held between 1/1/2004 and 12/31/2005 otherwise none, $9.88.
EWell #2: ST with MD < 20K ft.• If ≥ 20K TVD SS: + 4BCF + (0.6 * MD) BCF if lease issued in lease sale held between 1/1/2004 and 12/31/2005 otherwise none, $9.88.
FWell #2: Original well or ST.After 5/3/2009.• None.• None.
GWell #2: Original well or ST with MD ≥ 10K ft.Between 3/26/2003 and 5/3/2009.Never.• If 15K-18K TVD SS: [None], or • If ≥ 18K TVD SS: [2 BCF], $9.88 a.• NA
a For wells on leases issued after [DATE THAT IS 30 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register], the price threshold will be $4.47/MMBtu (adjusted for inflation after 2006) unless the lease terms prescribe a different price threshold.
Start Printed Page 28407

For example, suppose a sidetrack with a length of 7,000 feet is drilled to a depth of 23,000 feet TVD SS beginning in September 2007 (after this proposed rule has been 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 shows that the 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 does qualify to share the RSV, if any, earned by the deep well that remains.

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

Well typeSpud date1st date producedRoyalty relief under existing regulationsAdditional relief under proposed Section 344 rulemaking
Depth (feet): RSV [RSS], PT
AWell #1: Original well or ST.Before PR.Not Relevant.• None.• None.
BWell #1: Original well.After PR.Before 5/3/2013.• If 15K-18K TVD SS: 15 BCF, $4.47 a, or • If 18K-20K TVD SS: 25 BCF, $4.47 a, or • If ≥ 20K TVD SS: 35 BCF, $4.47 a.
CWell #1: ST with MD ≥ 20K ft.• If 15K-20K TVD SS: 4 BCF + (0.6 * MD) BCF up to 15 or 25 BCF, $4.47 a, or • If ≥ 20K TVD SS: 35 BCF, $4.47 a.
DWell #1: ST with MD < 20K ft.• If ≥ 15K TVD SS: 4 BCF + (0.6 * MD) BCF up to 15 or 25 BCF, $4.47 a.
EWell #1: Original well.After 5/3/2013.• If 15K-20K TVD SS: None, or • If ≥ 20K TVD SS: 35 BCF, $4.47 a.
FWell #1: ST with MD ≥ 20K ft.• If 15K-20K TVD SS: None, or • If ≥ 20K TVD SS: 35 BCF, $4.47 a.
GWell #1: ST with MD < 20K ft.• None
HWell #1: Original well.Between PR and 5/3/2013.Never.• If 15K-18K TVD SS: [None], or • If ≥ 18K TVD SS: [5 BCF], $4.47 a.
IWell #1: ST with MD ≥ 10K ft.• If 15K-18K TVD SS: [None], or • If ≥ 18K TVD SS: [0.8 BCF + (0.12 * MD) BCF up to 5 BCF], $4.47 a.
a Unless the lease terms of a lease issued after [DATE THAT IS 30 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register], prescribe a different price threshold.

For example, suppose a sidetrack with a length of 9,000 feet is drilled to a depth of 18,000 feet TVD SS between February and October 2010 (after this proposed rule has been issued) on a lease that has had no production from a well completed deeper than 15,000 feet 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 $4.47 per MMBtu (adjusted for inflation after 2006). Alternatively, if delays prevent production starting until July of 2013, Table 3, row F indicates this well earns no RSV. If this well were unsuccessful, Table 3, row H 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

Well typeSpud date1st date producedRoyalty relief under existing regulationsAdditional relief under proposed section 344 rulemaking
Depth (feet): RSV [RSS], PT
AWell #2: Original well.Between PR and 5/3/2013.Before 5/3/2013.• None.• If 15K-18K TVD SS: None, or • If 18K-20K TVD SS: 10 BCF, $4.47 a, or • If ≥ 20K TVD SS: None.
Start Printed Page 28408
BWell #2: ST.• If 15K-18K TVD SS: None, or • If 18K-20K TVD SS: 4 BCF + (0.6 * MD) BCF up to 10 BCF, $4.47 a, or • If ≥ 20K TVD SS: None.
CWell #2: Original well or ST.After 5/3/2013.• None.
DWell #2: Original well or ST with MD ≥ 10K ft.Between PR and 5/3/2013.Never.• If 15K-18K TVD SS: [None], or • If ≥ 18K TVD SS:      [2 BCF], $4.47 a.
a Unless the lease terms of a lease issued after [DATE THAT IS 30 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register] 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 this proposed rule has been 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

Well typeSpud date1st date producedExisting royalty relief in original lease termsAdditional relief under proposed section 344 rulemaking
Depth (feet): RSV [RSS], PT
AWell #1: Original well or ST.Before PR.Within 5 years of lease effective date.• If ≥ 15K in new reservoir: 20BCF, $4.00 (Sale 178), or • If ≥ 15K in new reservoir: 20BCF, $5.72 (Sales 180, 182, 184, 185, or 187).• None.
BAfter PR.• If 15K-20K in new reservoir: 20BCF, $4.00 (Sale 178), or • If 15K-20K in new reservoir: 20BCF, $5.72 (Sales 180, 182, 184, 185, or 187), or • If ≥ 20K in new reservoir: 1st 20 BCF, $4.00 or $5.72.• If 15K-20K TVD SS: None, or • If ≥ 20K TVD SS: Add 15 BCF, $4.47.
CMore than 5 years after lease effective date.• None.• If 15K-20K TVD SS: None, or • If ≥ 20K in new reservoir: 35BCF, $4.47.

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 this proposed rule has been 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 $5.72 per MMBtu (adjusted for inflation after 2006) while the remaining RSV of 15 BCF is subject to a price threshold of $4.47 per MMBtu (adjusted for inflation after 2006).

Additional information on the structure of the deep gas royalty relief incentives both in existing regulations and in this proposed rule can be found on the Minerals Management Service Web site at http://www.mms.gov/​econ/​.

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

The proposed changes to §§ 203.60, 203.62, 230.69, 203.70, 203.77, 203.78, 203.79, 203.81, 203.89, 203.90, and 260.121 reflect adding leases offshore of Alaska to the coverage of these provisions as section 346 of the Energy Policy Act requires. The proposed change to § 260.122 would add the default price threshold proposed for future leases issued with deep gas and ultra-deep gas royalty relief to future deepwater leases issued with royalty relief.

In § 203.69, MMS proposes to specify that if a lease issued after November 28, 2000 (the class of leases on which Start Printed Page 28409development projects are undertaken), has earned or may earn deep gas royalty relief, and if the lessee then applies for deep water royalty relief for a development project, MMS would take the value of the deep gas relief into account as part of the determination of whether the lease needs additional royalty relief for the development project.

If the lessee applies for deep water royalty relief for an expansion project, none of the reservoirs covered by the application could be reservoirs for which the lease could earn deep gas royalty relief, as reflected in the proposed amendment to the definition of “expansion project” in § 203.0.

The definition of “RS lease” in § 260.102 (a lease issued after November 28, 2000 with an RSV) does not exclude leases offshore Alaska issued with an RSV. The change proposed in § 260.121 would authorize lessees of RS leases issued offshore Alaska with an inadequate RSV to apply for additional relief before they produce.

The change proposed to § 260.122 would adopt a default price threshold for future leases in deep water equal to the level specified in the Deep Water Royalty Relief Act of 1995. This is the same price threshold that applies to all existing deepwater leases issued before 2001 in the Gulf of Mexico. Since all lease sale notices from 2000 forward have included price thresholds, this edit is not retroactively applying price thresholds where they did not already exist. It does serve to preclude the accidental omission of a price threshold for RS leases issued in future lease sales.

Procedural Matters

Public Availability of Comments

Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.

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

According to the criteria in E.O. 12866, this proposed rule is a significant regulatory action for which a Regulatory Analysis has been prepared. The Office of Management and Budget (OMB) has made that determination under E.O. 12866.

(1) The actions left to agency discretion in section 344 of the Energy Policy Act and incorporated into this proposed rule would not have an economic effect of $100 million or more in any year.

The added eligibility of leases in water depths from 200-400 meters for the deep gas royalty incentive would represent a 12 percent increase in the estimated gas resources that would be eligible for the deep gas incentive, and only a fraction of those resources would 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 proposed rule would prescribe (25 BCF increasing to 35 BCF for successful ultra-deep wells). However, because this incentive would 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. MMS proposes to prescribe 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 the final rule. 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 proposed formulation would apply a price threshold for ultra-deep gas royalty relief at the same level as used for deepwater royalty relief for leases issued before 2001 ($4.47 per MMBtu, adjusted for inflation after 2006). 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 $4.47 per MMBtu (adjusted for inflation after 2006) 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 $539 million) relative to using the same price threshold as in the existing regulations. Over the next 15 years, we estimate that the proposed price threshold of $4.47 per MMBtu would result in an annualized forgone royalties of about $11 million, generate an annualized social welfare measure of consumer plus producer surplus of about $460, 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.

This proposed rule would also add 66 currently active Alaska leases to the roughly 2,200 deepwater leases in the GOM that could apply for an RSV (for both oil and gas) before production. Again, section 346 of the Energy Policy Act mandates this expansion of existing discretionary royalty relief, so the implementation provisions in this proposed rule would add no economic effect to the effect that necessarily results from 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 avoided an average of $30 million annually in royalties since 1999, an amount that was restrained by price thresholds. The value of the relief offered 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 would only approve relief in the appropriate amount if MMS deemed the project uneconomic absent relief. Thus, there would be no negative effect on federal revenue from this rulemaking proposal.

(2) This proposed rule would not create any inconsistencies with actions by other agencies because royalty relief is confined to leasing in federal offshore waters that lie outside the coastal jurisdiction of state and other local agencies. Careful review of the lease sale notices, along with stringent leasing policies now in force, ensures that the federal OCS leasing program, of which royalty relief is only a component, would not conflict with the work of other federal agencies.

(3) This proposed rule would have no effect on entitlements, grants, user fees, loan programs, or their recipients.

(4) This proposed rule raises novel legal or policy issues. The proposed rule would expand previously established royalty relief programs for deep gas in the GOM and expand existing statutory discretionary royalty relief authority to offshore Alaska leases.

Regulatory Flexibility Act (RFA)

The Department certifies that this proposed rule would not have a significant economic effect on a Start Printed Page 28410substantial number of small entities under the RFA (5 U.S.C. 601 et seq.). The provisions of this proposed rule would not have a significant adverse economic effect on offshore lessees and operators, including those that are classified as small businesses.

This proposed rule would expand 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 would not materially alter the findings of that analysis because it would expand by less than five percent the set of leases affected.

The proposed rule would also extend the benefit of discretionary royalty relief to 66 OCS leases located offshore Alaska, some of which may qualify as marginally uneconomic. Two of the four 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 the proposed rule may affect. In the past, we have received less than one application a year from a candidate set of 2,200 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.

Your comments are important. The Small Business and Agriculture Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were established to receive comments from small businesses about Federal agency enforcement actions. The Ombudsman will annually evaluate the enforcement activities and rate each agency's responsiveness to small business. If you wish to comment on the actions of MMS, call 1-888-734-3247. You may comment to the Small Business Administration without fear of retaliation. Disciplinary action for retaliation by an MMS employee may include suspension or termination from employment with the DOI.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

This proposed rule is not a major rule under SBREFA (5 U.S.C. 804(2)). This proposed rule:

a. Would expand coverage of existing royalty relief programs by about 3 percent, adding about 160 leases to the set of about 5,000 leases eligible either for the deep gas incentive or to apply for royalty relief before production begins on the lease. These leases represent only a small fraction of the leases already eligible for these incentives as a result of earlier rules. The provisions in this proposed rule that would result from exercise of the Secretary's discretion do not change their effects substantially from those estimated for the earlier rules.

b. Would 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 would 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. Would 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 (UMRA)

This proposed rule would not impose an unfunded mandate on state, local, or tribal governments or the private sector of more than $100 million per year. The proposed rule would not have any federal mandates for non-federal entities. Nor would the proposed rule have a significant or unique effect on state, local, or tribal governments or the private sector. A statement containing the information required by the UMRA (2 U.S.C. 1531 et seq.) is not necessary.

Takings Implication Assessment (Executive Order 12630)

According to E.O. 12630, the proposed rule would not have significant takings implications; therefore a Takings Implication Assessment is not required. The proposed reduction in the price threshold would be purposely delayed until after the existing deep gas incentives expire to avoid risking a takings situation.

Federalism (Executive Order 13132)

According to E.O. 13132, this proposed rule would not have meaningful Federalism implications. As noted above, the deep gas provisions in this proposed rule should have a small effect relative to the original 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. However, any relief awarded to offshore Alaska leases could significantly affect that State's share of OCS revenue. In view of the fact that section 346 mandated extending existing discretionary royalty relief rules to leases offshore of Alaska, and that Alaska congressional representatives supported it, the State presumably believes that this provision would operate to its advantage.

Civil Justice Reform (Executive Order 12988)

With respect to E.O. 12988, The Office of the Solicitor has determined that the proposed rule does not unduly burden the judicial system and does meet the requirements of sections 3(a) and 3(b)(2) of the Executive Order.

Paperwork Reduction Act (PRA) of 1995

This proposed rule contains a collection of information that has been submitted to OMB for review and approval under § 3507(d) of the PRA. This proposed rule also refers to, but does not change, information collection burdens already covered and approved under OMB Control Number 1010-0071.

As part of our continuing effort to reduce paperwork and respondent burdens, MMS invites the public and other federal agencies to comment on any aspect of the reporting and recordkeeping burden. You may submit your comments on the information collection aspects of this rule directly to the Office of Management and Budget (OMB), Office of Information and Regulatory Affairs, OMB Attention: Desk Officer for the Department of the Interior via OMB e-mail: (OIRA_DOCKET@omb.eop.gov); or by fax (202) 395-6566; identify with 1010-AD33. Send a copy of your comments to the Rules Processing Team (RPT), Attn: Comments; 381 Elden Street, MS-4024; Herndon, Virginia 20170-4817. Please reference “Royalty Relief—Ultra-Deep Gas Wells and Deep Gas Wells on Outer Continental Shelf (OCS) Oil and Gas Leases; Extension of Royalty Relief Provisions to OCS Leases Offshore of Alaska—AD33” in your comments. You may obtain a copy of the supporting statement for the new collection of information by contacting the Bureau's Information Collection Clearance Officer at (202) 208-7744.

The PRA provides that an agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. OMB is required to make a decision concerning the collection of information contained in these proposed regulations between 30 to 60 days after publication Start Printed Page 28411of this document in the Federal Register. Therefore, a comment to OMB is best assured of having its full effect if OMB received it by June 18, 2007. This does not affect the deadline for the public to comment to MMS on the proposed regulations.

The title of the collection of information for the rule is “30 CFR 203, Royalty Relief—Ultra-Deep Gas Wells and Deep Gas Wells on Outer Continental Shelf (OCS) Oil and Gas Leases; Extension of Royalty Relief Provisions to OCS 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 (IC) does not include questions of a sensitive nature. MMS will protect proprietary information according to the Freedom of Information Act (5 U.S.C. 522) and its implementing regulations (43 CFR part 2), 30 CFR part 203, “Does my application have to include all leases in the field?” and 30 CFR 250.196, “Data and information to be made available to the public.”

The collection of information required by the current 30 CFR part 203 regulations was approved under OMB Control Number 1010-0071 (expiration 12/31/06), currently under renewal with OMB. The currently approved burden already covers the requirements for respondents to notify MMS of their intent to drill (89 annual burden hours) and when production actually begins for all wells (50 annual burden hours). Due to statutory changes enacted in section 344 of the Energy Policy Act of 2005, these proposed regulations differentiate these notifications into “deep” and “ultra-deep” well drilling categories. This change, however, does not affect the approved burdens for these requirements.

The currently approved burden also covers the requirements (3,130 total annual burden hours) for respondents to apply for royalty relief in the Gulf of Mexico Region (GOMR). Due to statutory changes enacted in section 344 of the Energy Policy Act of 2005, the scope for royalty relief will include the Alaska Region (AKOCSR) as well, but will not change the currently approved burdens. The hour burdens for the required applications relating to royalty relief for either the GOMR or the AKOCSR are still estimated to be 3,130 total annual hours. In the 11 years that MMS had had this regulatory requirement, only 9 lessees have submitted applications. This approved estimate is adequate for both regions for information collection requirements in both proposed requirements and current regulations.

The proposed rule does impose minor changes to the information collection burden hours. In the proposed rule, respondents may request a refund of or recoup royalties from qualified ultra-deep and deep wells, and they may request to extend the deadline for beginning production for up to one year. The burden estimates include the time for submitting requests to MMS for review. The following table provides a breakdown of the new paperwork burden estimates for this proposed rulemaking. We estimate a total of 3 annual burden hours. Based on $50 an hour, the estimated annual hour burden is $150 ($50 × 3 hours = $150). The information collection does not include questions of a sensitive nature.

Citation 30 CFR 203 subpart BReporting & recordkeeping requirementHour burdenAverage number of annual responsesAnnual burden hours
31(d)Request a refund of or recoup royalties from qualified ultra-deep wells111
41(e)Request a refund of or recoup royalties from qualified wells >200 meters but <400 meters111
35(d); 44(e)Request to extend the deadline for beginning production111
Total Burden33

MMS specifically solicits comments on the following questions:

(a) Is the proposed collection of information necessary for MMS to properly perform its functions, and will it be useful?

(b) Are the estimates of the burden hours of the proposed collection reasonable?

(c) Do you have any suggestions that would enhance the quality, clarity, or usefulness of the information to be collected?

(d) Is there a way to minimize the information collection burden on those who are to respond, including the use of appropriate automated electronic, mechanical, or other forms of information technology?

In addition, the PRA requires agencies to estimate the total annual reporting and recordkeeping “non-hour cost” burden resulting from the collection of information. We have not identified any, and we solicit your comments on this item. For reporting and recordkeeping only, your response should split the cost estimate into two components:

(a) Total capital and start-up cost component and (b) annual operation, maintenance, and purchase of services component. Your estimates should consider the costs to generate, maintain, and disclose or provide the information. You should describe the methods you use to estimate major cost factors, including system and technology acquisition, expected useful life of capital equipment, discount rate(s), and the period over which you incur costs. Capital and start-up costs include, among other items, computers and software you purchase to prepare for collecting information; monitoring, sampling, drilling, and testing equipment; and record storage facilities. Generally, your estimates should not include equipment or services purchased:

(1) Before October 1, 1995;

(2) To comply with requirements not associated with the information collection;

(3) For reasons other than to provide information or keep records for the Government; or

(4) As part of customary and usual business or private practices.

National Environmental Policy Act (NEPA) of 1969

We have analyzed this proposed rule in accordance with the criteria of the National Environmental Policy Act and the Department Manual at 516 DM. We determined this proposed rule does not constitute a major Federal action significantly affecting the quality of the human environment. This proposed rule deals with financial matters and has no direct effect on MMS decisions on environmental activities; hence, an Start Printed Page 28412environmental 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. No exception to the categorical exclusion applies.

Energy Supply, Distribution, or Use (Executive Order 13211)

This proposed rule would not have a significant adverse effect on energy supply, distribution, or use. This proposed rule may slightly increase and accelerate the production of oil and gas from offshore Alaska and gas from deep wells in shallow waters of the GOM, so it would have a positive effect on energy supplies.

Consultation with Indian Tribes (Executive Order 13175)

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

Clarity of This Regulation

Executive Order 12866 requires each agency to write regulations that are easy to understand. MMS invites your comments on how to make this proposed rule easier to understand, including answers to questions such as the following:

(1) Are the requirements in the proposed rule clearly stated?

(2) Does the rule contain technical language or jargon that interferes with its clarity?

(3) Does the format of the proposed rule (grouping and order of sections, use of headings, paragraphing, etc.) aid or reduce its clarity?

(4) Is the description of the proposed rule in the “Supplementary Information” section of this preamble helpful in understanding the rule? What else can MMS do to make the rule easier to understand?

Send a copy of any comments that concern how MMS could make this proposed rule easier to understand to: Office of Regulatory Affairs, Department of the Interior, Room 7229, 1849 C Street, NW., Washington, DC 20240. You may also e-mail the comments to this address: Exsec@ios.doi.gov.

Start List of Subjects

List of Subjects in 30 CFR Parts 203 and 260

End List of Subjects Start Signature

Dated: December 19, 2006.

Julie A. Jacobson,

Acting Assistant Secretary, Land and Minerals Management.

End Signature

Editorial Note:

This document was received at the Office of the Federal Register on May 10, 2007.

For the reasons stated in the preamble, the Minerals Management Service (MMS) proposes to amend 30 CFR parts 203 and 260 as follows:

Start Part

PART 203 RELIEF OR REDUCTION IN ROYALTY RATES

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

Start Authority

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 et seq.; 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.

End Authority

2. Section 203.0 is amended by revising the definitions for “certified unsuccessful well,” “deep well,” “development project,” “expansion project,” “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:

What definitions apply to this part?
* * * * *

Certified unsuccessful well means an original well, or a sidetrack with a sidetrack measured depth 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 MMS agrees is not commercially producible; and

(5) For which you have provided the notices and information required under § 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 planning areas 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 requirements in this definition.

(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 planning areas 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 Start Printed Page 28413production 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 planning areas 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) If an RSV under §§ 203.30 through 203.36 or 203.40 through 203.48 would be applied to production from a reservoir that has not previously produced and that otherwise would constitute part of an expansion project under this definition, that reservoir may not be included as part of an expansion project.

* * * * *

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 § 203.49 to replace the lease terms for royalty relief with those in §§ 203.0 and 203.40 through 203.48.

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 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

(2) Before the date which is 5 years after the lease issuance date on a non-converted lease; 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 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

(2) On or after the date which is 5 years after the lease issuance date on a non-converted lease; 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 § 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 § 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 § 203.35 or § 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 § 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 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 of less than 20,000 feet.

* * * * *

3. In § 203.1, paragraph (b) is revised to read as follows:

What is MMS's authority to grant royalty relief?
* * * * *

(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.

* * * * *

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

How can I obtain royalty relief?
* * * * *
Start Printed Page 28414
If you have a lease . . .And if you . . .Then we may grant you . . .
*         *         *         *         *         *         *
(b) Located in a designated GOM deep water area and acquired in a lease sale held before November 28, 1995, or after November 28, 2000Propose an expansion project and can demonstrate your project is uneconomic without royalty reliefA royalty suspension for a minimum production volume plus any additional production large enough to make the project economic. (See §§ 203.60 through 203.79.)
*         *         *         *         *         *         *
(d) Located in a designated GOM deep water area and acquired in a lease sale held after November 28, 2000Propose a development project and can demonstrate that the suspension volume, if any, for your lease is not enough to make development economicA royalty suspension for a minimum production volume plus any additional volume needed to make your project economic. (See §§ 203.60 through 203.79.)
*         *         *         *         *         *         *
(f) Located in a designated GOM shallow water area and acquired in a lease sale held before January 1, 2001, or after January 1, 2004, or have exercised an option to substitute for royalty relief in your lease termsDrill a deep well on a lease that is not eligible for deep water royalty relief and you have not previously produced oil or gas from a deep well or an ultra-deep wellA royalty suspension for a volume of gas produced from successful deep and ultra-deep wells, or, for certain unsuccessful deep and ultra-deep wells, a smaller royalty suspension for a volume of gas or oil produced by all wells on your lease. (See §§ 203.40 through 203.49).
(g) Located in a designated GOM shallow water areaDrill and produce gas from an ultra-deep well on a lease that is not eligible for deep water royalty relief and you have not previously produced oil or gas from an ultra-deep wellA royalty suspension for a volume of gas produced from successful ultra-deep and deep wells on your lease. (See §§ 203.30 through 203.36.)
(h) Located in planning areas offshore AlaskaPropose an expansion project or propose a development project and can demonstrate that the project is uneconomic without relief or that the suspension volume, if any, for your lease is not enough to make development economicA royalty suspension for a minimum production volume plus any additional volume needed to make your project economic. (See §§ 203.60, 203.62, 203.67 through 203.70, 203.73 and 203.76 through 203.79.)

5. A new undesignated center heading and new §§ 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

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

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

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 §§ 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. See § 203.31(b) for an exception.

(c) 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 30 CFR 203.60 through 203.79.

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

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

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

(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; Start Printed Page 28415

(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 § 203.41-203.47 as they existed at the time the lease was issued.

(2) Subject to the administrative requirements of § 203.35 and the price conditions in § 203.36, your lease earns an RSV shown in the following table in BCF or MCF as prescribed in § 203.33:

If you have a qualified phase 2 ultra-deep well that is . . .Then your lease earns an RSV on this volume of gas production:
(i) An original well or a sidetrack with a sidetrack measured depth of at least 20,000 feet TVD SS,10 BCF.
(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)(1) You must apply the RSV prescribed in paragraphs (a) and (b) of this section 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 § 216.53, and to the extent prescribed in § 203.33.

(2) 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 and ultra-deep wells on the lease, in the manner prescribed in §§ 203.33 and 203.36.

(d) 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 [DATE THAT IS 30 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register] and

(2) Is subject to application of an RSV under either § 203.31 or § 203.41.

(e) The following examples illustrate how this section applies. These examples assume that the price thresholds prescribed in § 203.36 have not been exceeded.

Example 1:

In 2007, 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. Your lease earns an RSV of 35 BCF under this section when this well begins producing. Then in 2013, 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, but any remaining RSV earned by the first ultra-deep well would be applied to production from both the first and the second ultra-deep well as prescribed in § 203.33.

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 because you spudded the well before the publication date of the proposed rule. However, this ultra-deep well may earn an RSV of 25 BCF for your lease under § 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.

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 an 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 § 203.41.

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 production from a deep or ultra-deep well. Your lease earns an RSV of 35 BCF under this section when this well begins producing. 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 (see § 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 §§ 203.33 and 203.43. However, if the 16,000-foot deep well does not begin production until 2014 (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, and the RSV earned by the ultra-deep well would not be applied to production from the 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 § 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 when it begins producing but your lease earns no additional RSV under this section or § 203.41. 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 §§ 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. 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 of gas production from qualified deep and qualified ultra-deep wells on your lease, as prescribed in § 203.33. 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. However, if it does not begin production until 2010, it earns no RSV.

Example 7:

Your lease was issued in June 2004 and expressly incorporates the provisions of §§ 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 § 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. Well no. 2 earns your lease an additional RSV of 10 BCF under paragraph (b) of this section. If, on the other hand, well no. 2 had begun producing in June 2009, it would earn no additional RSV for the lease.

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.

(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 § 203.31 is in addition to any royalty suspension supplement (RSS) for your lease under § 203.45 that results from a different wellbore.

(d) If your lease earns an RSV under § 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 § 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 Start Printed Page 28416allowed under paragraphs (a) and (b) of § 203.31.

(f) Unused RSVs transfer to a successor lessee and expire with the lease.

To which production do I apply the RSV earned by qualified phase 2 and phase 3 ultra-deep wells on my lease?

(a) 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 § 203.36, you must apply the RSV prescribed in § 203.31 as required under the following paragraphs (a)(1) and (a)(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 gas production from all qualified wells on your lease, regardless of their depth, for which you have met the requirements in § 203.35 or § 203.44.

(b) 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 § 203.36, you must apply the RSV prescribed in § 203.31 as required under the following paragraphs (b)(1) through (b)(3) 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 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 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 § 203.35 or § 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 § 203.35 or § 203.44 have been met.

(3) The allocated share under paragraph (a)(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 phase 2 ultra-deep well on the non-unitized portion of lease A that earns lease A an RSV of 35 BCF under § 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 § 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)].

(c) 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 § 203.31 or § 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.

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 § 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 (b) of § 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.

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

(a) To use an RSV earned under § 203.31, you must:

(1) Notify the MMS Regional Supervisor for Production and Development in writing of your intent to begin drilling operations on all ultra-deep wells;

(2) Within 30 days of the beginning of production from all 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.

(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) If you produced from a qualified phase 2 or phase 3 ultra-deep well before [DATE THAT IS 30 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register], you must provide the information in paragraph (b)(1) of this section no later than [DATE THAT IS 60 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register].

(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, provided that you demonstrate that:

(1) The delay occurred after reaching 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; and

(3) The delay in beginning production is for reasons beyond your control, including but not limited to adverse weather and unavoidable accidents.

Do I keep royalty relief if prices rise significantly?

(a) You must pay royalties on all gas production to which an RSV otherwise Start Printed Page 28417would be applied under § 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 2006 dollars of . . .Applies to . . .
(1) $9.88 per MMBtu• The first 25 BCF of RSV earned under § 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 [DATE THAT IS 30 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register]; and
• Any RSV earned under § 203.31(b) by a phase 2 ultra-deep well.
(2) $4.47 per MMBtu• Any RSV earned under § 203.31(a) by a phase 3 ultra-deep well unless the lease terms prescribe a different price threshold;
• The last 10 BCF of the 35 BCF of RSV earned under § 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 [DATE THAT IS 30 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register] and that is not a non-converted lease;
• The last 15 BCF of the 35 BCF of RSV earned under § 203.31(a) by a phase 2 ultra-deep well on a non-converted lease;
• Any RSV earned under § 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 [DATE THAT IS 30 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register] unless the lease terms prescribe a different price threshold; and
• Any RSV earned under § 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.
(3) $4.00 per MMBtu• 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) $5.72 per MMBtu• 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 2006 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. The well produces a total of 18 BCF by the end of 2009. In both of those years, the average daily NYMEX closing natural gas price is less than $9.88 (adjusted for inflation after 2006). The lessee does not pay royalty on the 18 BCF. In 2010, the well produces another 13 BCF. In that year, the average daily closing NYMEX natural gas price is greater than $4.47 per MMBtu (adjusted for inflation after 2006), but less than $9.88 per MMBtu (adjusted for inflation after 2006). The first 7 BCF produced in 2010 will exhaust the first 25 BCF of the 35 BCF RSV that the well earned that is subject to the $9.88 threshold. The lessee must pay royalty on the remaining 6 BCF produced in 2010, which is subject to the $4.47 per MMBtu threshold that 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 § 203.41, which would be subject to a price threshold of $9.88 per MMBtu (adjusted for inflation after 2006);

(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; and

(3) In 2013 drills and produces from Well No. 3, a qualified phase 3 ultra-deep well that earns no additional RSV. Further assume that in 2013, the average daily closing NYMEX natural gas price exceeds $4.47 per MMBtu (adjusted for inflation after 2006) but does not exceed $9.88 per MMBtu (adjusted for inflation after 2006). In 2013, 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, because the $9.88 per MMBtu (adjusted for inflation after 2006) price threshold is not exceeded.

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, and would earn the lease an RSV of 35 BCF. Further assume that the average daily closing NYMEX natural gas price exceeds $4.47 per MMBtu (adjusted for inflation after 2006) but does not exceed $9.88 per MMBtu (adjusted for inflation after 2006) during 2010. Because the lease is located in more than 200 but less than 400 meters of water, the $4.47 per MMBtu price threshold applies, 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 § 218.54 beginning 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.

[Redesignated as §§ 203.43 through 203.49]

6. Sections 203.42 through 203.48 are redesignated as §§ 203.43 through 203.49.

7. Sections 203.40 and 203.41 are revised to read as follows:

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 §§ 203.41 through 203.44, and may receive an RSS under §§ 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: Start Printed Page 28418

(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 § 203.49; or

(3) On or after January 1, 2004, and the lease terms provide for royalty relief under §§ 203.41 through 203.47 of this part. (Note: Because the original § 203.41 has been divided into new §§ 203.41 and 203.42 and subsequent sections have been redesignated as §§ 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 §§ 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 §§ 203.60 through 203.79.

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

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

(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 well that is:Then your lease earns an RSV on this volume of gas production:
(1) An original well with a perforated interval the top of which is from 15,000 to less than 18,000 feet TVD SS,15 BCF.
(2) A sidetrack with a perforated interval the top of which is from 15,000 to less than 18,000 feet TVD SS,4 BCF plus 600 MCF times sidetrack measured depth (rounded to the nearest 100 feet) but no more than 15 BCF.
(3) An original well with a perforated interval the top of which is at least 18,000 feet TVD SS,25 BCF.
(4) A sidetrack with a perforated interval the top of which is at least 18,000 feet TVD SS,4 BCF plus 600 MCF times sidetrack measured depth (rounded to the 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 perforated interval the top of which is from 15,000 to less than 18,000 feet TVD SS,0 BCF.
(2) An original well with a perforated interval the top of which is 18,000 feet TVD SS or deeper,10 BCF.
(3) A sidetrack with a perforated interval the top of which is 18,000 feet TVD SS or deeper,4 BCF plus 600 MCF times sidetrack measured depth (rounded to the nearest 100 feet) but no more than 10 BCF.

(d) You must apply the RSV prescribed in paragraphs (b) and (c) of this section to gas volumes produced from qualified wells on or after May 3, 2004, reported on the OGOR-A for your lease under § 216.53, as and to the extent prescribed in §§ 203.43 and 203.48.

(1) Except as provided in paragraph (d)(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 §§ 203.45 and 203.46 does not count toward the lease RSV.

(e) 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 [DATE THAT IS 30 DAYS AFTER THE PUBLICATION DATE OF THE FINAL RULE IN THE Federal Register]; and

(2) Is subject to application of an RSV under either § 203.31 or § 203.41. Start Printed Page 28419

(f) The following examples illustrate how this section applies:

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 that would be applied to gas production from all qualified wells on your lease, as prescribed in § 203.43. However, if the top of the perforated interval is 18,500 feet TVD SS, the RSV is 25 BCF.

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 that would be applied to gas production from all qualified wells on your lease, as prescribed in § 203.43.

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 that would be applied to gas production from all qualified wells on your lease, as prescribed in § 203.43, even though 4 BCF plus 600 MCF per foot of sidetrack measured depth equals 15.7 BCF.

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;

(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 that would be applied to gas production from qualified wells on your lease, as prescribed in §§ 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 that would be applied to gas production from qualified wells on your lease, as prescribed in §§ 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 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. MMS would apply that RSV to gas production from qualified wells on your lease, as prescribed in §§ 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 if the second well was a phase 1 ultra-deep well, i.e., if drilling began before May 18, 2007. If drilling of the second well began after that date, the second well would not earn any additional RSV (as prescribed in § 203.30), and 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 to 15.2 BCF. MMS would apply that RSV to gas production from qualified wells on your lease, as prescribed in §§ 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.

8. A new § 203.42 is added to read as follows:

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 § 203.41.

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

9. Newly redesignated § 203.43 is revised to read as follows:

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

(a) This paragraph applies to any lease with a qualified deep well or qualified phase 1 ultra-deep well that is not within an MMS-approved unit. Subject to the price conditions in § 203.48, you must apply the RSV prescribed in § 203.41 as required under the following paragraphs (a)(1) and (a)(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 Start Printed Page 28420begins production (other than test production).

(2) You must apply the RSV to gas production from all qualified wells on your lease, regardless of their depth, for which you have met the requirements in § 203.35 or § 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. 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. 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. If the second well had begun production in August 2009, it would not be a qualified deep well because it started production after expiration of this provision in May 2009, and could not share any of the remaining RSV.

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. Only the first well earns an RSV equal to 15 BCF. 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.

(b) 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 § 203.48, you must apply the RSV prescribed under § 203.41 as required under the following paragraphs (b)(1) through (b)(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 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 § 203.35 or § 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 § 203.35 or § 203.44 have been met.

(3) The allocated share under paragraph (b)(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)].

(c) 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 § 203.31 or § 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.

(d) You may not apply the RSV allowed under § 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 (b) 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.

10. In redesignated § 203.44, the section heading and paragraphs (a), (d), and (e) are revised to read as follows:

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.

* * * * *

(d) You must provide the information in paragraph (b) of this section by [DATE THAT IS 60 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register] if you produced before [DATE THAT IS 30 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register] 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 § 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 § 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 date from the definition of a qualified deep well in § 203.0.

(4) The delay in beginning production is for reasons beyond your control, e.g., adverse weather or unavoidable accidents.

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

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 Start Printed Page 28421requirements of § 203.47, subject to the price conditions in § 203.48, your lease earns an RSS shown in the following table. The RSS are shown in billions of cubic feet of gas equivalent (BCFE) or in thousands of cubic feet of gas equivalent (MCFE) and are applicable to oil and gas production as prescribed in § 204.46.

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 § 203.46:
(1) An original well and your lease has not produced gas or oil from a deep well or an ultra-deep well,5 BCFE.
(2) A sidetrack (with a sidetrack measured depth of at least 10,000 feet) and your lease has not produced gas or oil from a deep well or an ultra-deep well,0.8 BCFE plus 120 MCFE times sidetrack measured depth (rounded to the nearest 100 feet) but no more than 5 BCFE.
(3) An original well or a sidetrack (with a 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,2 BCFE.

(b) This paragraph applies to oil and gas volumes you report on the OGOR-A for your lease under § 216.53.

(1) You must apply the RSS prescribed in paragraph (a) of this section, in accordance with the requirements in § 203.46, to all oil and gas produced from the lease:

(i) On or after [DATE THAT IS 30 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register], 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 §§ 203.31 through 203.33 and 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 § 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 earn an RSS of 2.3 BCFE of gas and oil production as prescribed in § 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:

* * * * *

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

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 §§ 203.40, 203.43, 203.45, 203.47, and 203.48, you must apply an RSS in § 203.45 to the earliest oil and gas production:

* * * * *

(c) If you have no current production on which to apply the RSS allowed under § 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 § 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.

* * * * *

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

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 [DATE THAT IS 30 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register], you must provide the information in paragraph (b) of this section no later than [DATE THAT IS 90 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register].

14. Redesignated § 203.48 is revised to read as follows:

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 §§ 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 than 200 meters deep,before [DATE THAT IS 30 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register]$9.88 per MMBtu, adjusted annually after calendar year 2006 for inflation.
(2) Partly or entirely less than 200 meters deep,after [DATE THAT IS 30 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE IN THE Federal Register]$4.47 per MMBtu, adjusted annually after calendar year 2006 for inflation unless the lease terms prescribe a different price threshold.
Start Printed Page 28422
(3) Entirely more than 200 meters and entirely less than 400 meters deep,on any date$4.47 per MMBtu, adjusted annually after calendar year 2006 for inflation unless the lease terms prescribe a different price threshold.

(b) Determine the threshold price for any calendar year after 2006 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.

(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 beginning 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.

15. In redesignated § 203.49, the section heading and paragraphs (a) introductory text and paragraph (c) are revised to read as follows:

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 § 203.0 and 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 §§ 203.40 through 203.48.

* * * * *

16. The undesignated center heading preceeding § 203.60 is revised to read as follows:

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

17. Section 203.60 is revised to read as follows:

Who may apply for royalty relief offshore Alaska or in deep water in the Gulf of Mexico?

You may apply for royalty relief under §§ 203.61(b) and 203.62 if you:

(a) Hold a pre-Act lease (as defined in § 203.0) that we have assigned to an authorized field (as defined in § 203.0);

(b) Propose an expansion project (as defined in § 203.0); or

(c) Propose a development project (as defined in § 203.0).

18. In § 203.62, paragraphs (a) through (c) are redesignated paragraphs (b) through (d), the introductory paragraph is designated paragraph (a), and redesignated paragraphs (b) and (d) are revised to read as follows:

How do I apply for relief?
* * * * *

(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.

* * * * *

(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.

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

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 §§ 203.40 through 203.49 or ultra-deep gas royalty relief under §§ 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:

For . . .The minimum royalty suspension volume is . . .Plus . . .
(1) RS leases in the GOM or leases offshore AlaskaA volume equal to the combined royalty suspension volumes (or the volume equivalent based on the data in your approved application for other forms of royalty suspension) with which MMS issued the leases participating in the application that have or plan a well into a reservoir identified in the application10 percent of the median of the distribution of known recoverable resources upon which MMS based approval of your application from all reservoirs included in the project.
(2) Leases offshore Alaska or other deep water GOM leases issued in sales after November 28, 2000A volume equal to 10 percent of the median of the distribution of known recoverable resources upon which MMS based approval of your application from all reservoirs included in the project
Start Printed Page 28423

20. In § 203.70, the introductory paragraph is revised to read as follows:

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.

* * * * *

21. Section 203.77 is revised to read as follows:

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.

22. In § 203.78, the introductory paragraph is revised, paragraphs (a) through (f) are redesignated as paragraphs (b) through (g), respectively, and a new paragraph (a) is added, to read as follows:

Do I keep relief 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 as prescribed in this section.

(a) The following table shows the base price threshold for various types of leases. Note that, for post-November 2000 deepwater leases, price thresholds apply on a lease basis, so different leases on the same development project or expansion project may have different price thresholds.

For . . .The base price threshold is . . .
(1) Pre-Act leasesset by statute.
(2) Post-November 2000 deep water leases in the GOM or leases offshore Alaskaindicated in your original lease agreement or Notice of Sale.
(3) Post-November 2000 deep water leases in the GOM or leases offshore of Alaska that did not set a base price thresholdthe threshold set by statute for pre-Act leases.
* * * * *

23. In § 203.79, the section heading is revised to read as follows:

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

24. In § 203.81, paragraph (b) is revised to read as follows:

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.

* * * * *

25. In § 203.89, the section heading is revised to read as follows:

What is in a cost report?
* * * * *

26. In § 203.90, paragraph (b) is revised to read as follows:

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

* * * * *
End Part Start Part

PART 260 OUTER CONTINENTAL SHELF OIL AND GAS LEASING

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

Start Authority

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

End Authority

28. In § 260.121, paragraph (b) is revised to read as follows:

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.

* * * * *

29. In § 260.122, paragraph (b)(1) is revised to read as follows:

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 $35.75 per barrel, adjusted annually after calendar year 2006 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 $4.47 per MMBtu, adjusted annually after calendar year 2006 for inflation unless the lease terms prescribe a different price threshold.

(iii) Determine the threshold price for any calendar year after 2006 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.

* * * * *
End Part End Supplemental Information

[FR Doc. E7-9294 Filed 5-17-07; 8:45 am]

BILLING CODE 4310-MR-P