28396 Federal Register / Vol. 72, No. 96 / Friday, May 18, 2007 / Proposed Rules 

DEPARTMENT OF THE INTERIOR 

Minerals Management Service 

30 CFR Parts 203 and 260 

RIN 1010–AD33 

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 

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. 

FOR FURTHER INFORMATION CONTACT: 

Marshall Rose, Chief, Economics 

Division, at (703) 787–1536 or 

marshall.rose@mms.gov. 

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. 

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 ultradeep 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 


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Federal Register / Vol. 72, No. 96 / Friday, May 18, 2007 / Proposed Rules 28397 

previous 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 ultradeep 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 ultradeep 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 


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28398 Federal Register / Vol. 72, No. 96 / Friday, May 18, 2007 / Proposed Rules 

to 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 ultradeep 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 ‘‘nonconverted 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 ultradeep 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 nonconverted 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 ultradeep 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. 


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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 ultradeep 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 postNovember 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 ultradeep 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 


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proposed 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 ultradeep 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 


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situation 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 ultradeep 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 ultradeep 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 ultradeep 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 ultradeep 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 ultradeep 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 ultradeep 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 MMSapproved unit, has a structure similar to 


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the 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 ultradeep 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, redesignated § 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 ultradeep 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 ultradeep 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 


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(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 royaltyfree 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 


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on 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 ultradeep 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 renumbered 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 


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$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: 

BCF .............................................................................. Billion cubic feet. 

K ................................................................................... Thousand. 

MD ............................................................................... Measured depth (length in thousands of feet). 

MMBtu ......................................................................... Million British thermal units. 

NA ................................................................................ Not applicable. 

PT ................................................................................. Price Threshold (2006$ per MMBtu). 

PR ................................................................................. Proposed rule implementing Section 344 of the Energy Policy Act of 2005. 

RSS .............................................................................. Royalty Suspension Supplement (in BCF). 

RSV .............................................................................. Royalty Suspension Volume (in BCF). 

ST ................................................................................. Sidetrack. 

TVD SS ........................................................................ True 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 type Spud date 1st date produced Royalty relief under existing 

regulations 

Additional relief under proposed 

section 344 rulemaking 

Depth (feet): RSV [RSS], PT 

A Well #1: Original 

well or ST. 

Before 3/26/2003. Not Relevant. • None. • NA 

B Well #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 

C Well #1: ST. • If ≥ 15K TVD SS: 4 BCF+ (0.6 * 

MD) BCF up to 15 or 25 BCF, 

$9.88. 

• NA 

D Well #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. 

E Well #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. 

F Well #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. 

G Well #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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28406 Federal Register / Vol. 72, No. 96 / Friday, May 18, 2007 / Proposed Rules 

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—Continued 

Well type Spud date 1st date produced Royalty relief under existing 

regulations 

Additional relief under proposed 

section 344 rulemaking 

Depth (feet): RSV [RSS], PT 

H Well #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. 

I Well #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. 

aFor 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 type Spud date 1st date produced Royalty relief under existing regulations 

Additional relief under proposed section 344 rulemaking 

Depth (feet): RSV [RSS], PT 

A Well #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. 

B Well #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. 

C Well #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. 

D Well #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. 

E Well #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. 

F Well #2: Original 

well or ST. 

After 5/3/2009. • None. • None. 

G Well #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 

aFor 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. 


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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 type Spud date 1st date produced Royalty relief under existing regulations 

Additional relief under proposed Section 344 rulemaking 

Depth (feet): RSV [RSS], PT 

A Well #1: Original 

well or ST. 

Before PR. Not Relevant. • None. • None. 

B Well #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. 

C Well #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. 

D Well #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. 

E Well #1: Original 

well. 

After 5/3/2013. • If 15K–20K TVD SS: None, or 

• If ≥ 20K TVD SS: 35 BCF, $4.47 a. 

F Well #1: ST with 

MD ≥ 20K ft. 

• If 15K–20K TVD SS: None, or 

• If ≥ 20K TVD SS: 35 BCF, $4.47 a. 

G Well #1: ST with 

MD < 20K ft. 

• None 

H Well #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. 

I Well #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 type Spud date 1st date produced Royalty relief under existing regulations 

Additional relief under proposed section 344 rulemaking 

Depth (feet): RSV [RSS], PT 

A Well #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. 


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28408 Federal Register / Vol. 72, No. 96 / Friday, May 18, 2007 / Proposed Rules 

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—Continued 

Well type Spud date 1st date produced Royalty relief under existing regulations 

Additional relief under proposed section 344 rulemaking 

Depth (feet): RSV [RSS], PT 

B Well #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. 

C Well #2: Original 

well or ST. 

After 5/3/2013. • None. 

D Well #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 type Spud date 1st date produced Existing royalty relief in original lease 

terms 

Additional relief under proposed section 344 rulemaking 

Depth (feet): RSV [RSS], PT 

A Well #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. 

B After 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. 

C More 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 


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development 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 openended 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 


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substantial 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 foreignbased 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 


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of 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 ultradeep 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 B Reporting & recordkeeping requirement Hour burden 

Average 

number of 

annual 

responses 

Annual 

burden 

hours 

31(d) ...................... Request a refund of or recoup royalties from qualified ultra-deep wells ............ 1 1 1 

41(e) ...................... Request a refund of or recoup royalties from qualified wells >200 meters but 

<400 meters.

1 1 1 

35(d); 44(e) ........... Request to extend the deadline for beginning production ................................... 1 1 1 

Total Burden .. ............................................................................................................................... .................... 3 3 

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 


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environmental impact statement is not 

required. Pursuant to Department 

Manual 516 DM 2.3A (2), Section 1.10 

of 516 DM 2, Appendix 1 excludes from 

documentation in an environmental 

assessment or impact statement 

‘‘policies, directives, regulations and 

guidelines of an administrative, 

financial, legal, technical or procedural 

nature; or the environmental effects of 

which are too broad, speculative or 

conjectural to lend themselves to 

meaningful analysis and will be subject 

later to the NEPA process, either 

collectively or case-by-case.’’ Section 

1.3 of the same appendix clarifies that 

royalties and audits are considered 

routine financial transactions that are 

subject to categorical exclusion from the 

NEPA process. 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. 

List of Subjects in 30 CFR Parts 203 and 

260 

Continental shelf, Government 

contracts, Indians—lands, Mineral 

royalties, Oil and gas exploration, 

Public lands—mineral resources, 

Reporting and recordkeeping 

requirements, Sulphur. 

Dated: December 19, 2006. 

Julie A. Jacobson, 

Acting Assistant Secretary, Land and 

Minerals Management. 

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: 

PART 203 RELIEF OR REDUCTION IN 

ROYALTY RATES 

1. The authority citation for part 203 

is revised to read as follows: 

Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 

396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C. 

181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C. 

1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 

9701 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. 

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: 

§ 203.0 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 


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production does not constitute a 

significant increase); and 

(ii) Must involve a substantial capital 

investment (e.g., fixed-leg platform, 

subsea template and manifold, tensionleg 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 nonconverted 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 ultradeep 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 reperforated less than 20,000 feet TVD SS 

in the same reservoir is still an ultradeep 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: 

§ 203.1 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: 

§ 203.2 How can I obtain royalty relief? 

* * * * * 


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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, 2000.

Propose an expansion project and can demonstrate your project is uneconomic without 

royalty relief.

A 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, 2000.

Propose a development project and can demonstrate that the suspension volume, if any, 

for your lease is not enough to make development economic.

A 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 terms.

Drill 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 well.

A 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 area.

Drill 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 well.

A 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 Alaska Propose 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 economic.

A 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 

Sec. 

203.30 Which leases are eligible for royalty 

relief as a result of drilling a phase 2 or 

phase 3 ultra-deep well? 

203.31 If I have a qualified phase 2 or 

qualified phase 3 ultra-deep well, what 

royalty relief would my lease earn? 

203.32 What other requirements or 

restrictions apply to royalty relief for a 

qualified phase 2 or phase 3 ultra-deep 

well? 

203.33 To which production do I apply the 

RSB earned by qualified phase 2 and 

phase 3 ultra-deep wells on my lease? 

203.34 To which production may an RSB 

earned by qualified phase 2 and phase 3 

ultra-deep wells on my lease not be 

applied? 

203.35 What administrative steps must I 

take to use the RSB earned by a qualified 

phase 2 or phase 3 ultra-deep well? 

203.36 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 

§ 203.30 Which leases are eligible for 

royalty relief as a result of drilling a phase 

2 or phase 3 ultra-deep well? 

Your lease may receive a royalty 

suspension volume (RSV) under 

§§ 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. 

§ 203.31 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; 


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(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 ultradeep 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 ultradeep 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. 

§ 203.32 What other requirements or 

restrictions apply to royalty relief for a 

qualified phase 2 or phase 3 ultra-deep 

well? 

(a) If a qualified ultra-deep well on 

your lease is within a unitized portion 

of your lease, the RSV earned by that 

well under this section applies only to 

your lease and not to other leases within 

the unit. 

(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 nonqualified well. 

(e) You owe minimum royalties or 

rentals in accordance with your lease 

terms notwithstanding any RSVs 


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allowed under paragraphs (a) and (b) of 

§ 203.31. 

(f) Unused RSVs transfer to a 

successor lessee and expire with the 

lease. 

§ 203.33 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 nonunitized 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. 

§ 203.34 To which production may an RSV 

earned by qualified phase 2 and phase 3 

ultra-deep wells on my lease not be 

applied? 

You may not apply an RSV earned 

under § 203.31: 

(a) To production from completions 

less than 15,000 feet TVD SS, except in 

cases where the qualified well is reperforated 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. 

§ 203.35 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 ultradeep 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. 

§ 203.36 Do I keep royalty relief if prices 

rise significantly? 

(a) You must pay royalties on all gas 

production to which an RSV otherwise 


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would 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 ultradeep 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 ultradeep 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. 

§§ 203.42 through 203.48 [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: 

§ 203.40 Which leases are eligible for 

royalty relief as a result of drilling a deep 

well or a phase 1 ultra-deep well? 

Your lease may receive an RSV under 

§§ 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: 


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(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. 

§ 203.41 If I have a qualified deep well or 

a qualified phase 1 ultra-deep well, what 

royalty relief would my lease earn? 

(a) To qualify for a suspension volume 

under paragraphs (b) or (c) of this 

section, your lease must meet the 

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 well.

has a qualified deep well or qualified phase 1 

ultra-deep well.

earns 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 deeper.

has 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 

well.

earns 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. 


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(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: 

§ 203.42 What conditions and limitations 

apply to royalty relief for deep wells and 

phase 1 ultra-deep wells? 

The conditions and limitations in the 

following table apply to royalty relief 

under § 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: 

§ 203.43 To which production do I apply 

the RSV earned from qualified deep wells or 

qualified phase 1 ultra-deep wells on my 

lease? 

(a) 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 


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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. 

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 reperforated 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: 

§ 203.44 What administrative steps must I 

take to use the RSV earned by a qualified 

deep well or qualified phase 1 ultra-deep 

well? 

(a) You must notify the MMS Regional 

Supervisor for Production and 

Development in writing of your intent to 

begin drilling operations on all deep 

wells and phase 1 ultra-deep wells. 

* * * * * 

(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: 

§ 203.45 If I drill a certified unsuccessful 

well, what royalty relief will my lease earn? 

* * * * * 

(a) If you drill a certified unsuccessful 

well and you satisfy the administrative 


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requirements 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: 

§ 203.46 To which production do I apply 

the RSS from drilling one or two certified 

unsuccessful wells on my lease? 

(a) Subject to the requirements of 

§§ 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: 

§ 203.47 What administrative steps do I 

take to obtain and use the royalty 

suspension supplement? 

* * * * * 

(c) If you commenced drilling a well 

that otherwise meets the criteria for a 

certified unsuccessful well on a lease 

located entirely in more than 200 meters 

and entirely less than 400 meters of 

water on or after May 18, 2007, and 

finished it before [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: 

§ 203.48 Do I keep royalty relief if prices 

rise significantly? 

(a) You must pay royalties on all gas 

and oil production for which an RSV or 

an RSS otherwise would be allowed 

under §§ 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. 


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28422 Federal Register / Vol. 72, No. 96 / Friday, May 18, 2007 / Proposed Rules 

For a lease located in water . . . And issued . . . the applicable threshold price is . . . 

(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: 

§ 203.49 May I substitute the deep gas 

drilling provisions in this part for the deep 

gas royalty relief provided in my lease 

terms? 

(a) You may exercise an option to 

replace the applicable lease terms for 

royalty relief related to deep-well 

drilling with those in § 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: 

§ 203.60 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: 

§ 203.62 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: 

§ 203.69 If my application is approved, 

what royalty relief will I receive? 

* * * * * 

(b) For development projects, any 

relief we grant applies only to project 

wells and replaces the royalty relief, if 

any, with which we issued your lease. 

(c) If your project is economic given 

the royalty relief with which we issued 

your lease, we will reject the 

application. 

(d) If the lease has earned or may earn 

deep gas royalty relief under §§ 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 

Alaska.

A 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 application.

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. 

(2) Leases offshore Alaska or other deep water 

GOM leases issued in sales after November 

28, 2000.

A 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.


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Federal Register / Vol. 72, No. 96 / Friday, May 18, 2007 / Proposed Rules 28423 

20. In § 203.70, the introductory 

paragraph is revised to read as follows: 

§ 203.70 What information must I provide 

after MMS approves relief? 

You must submit reports to us as 

indicated in the following table. 

Sections 203.81, 203.90, and 203.91 

describe what these reports must 

include. The MMS Regional Office for 

your region will prescribe the formats. 

* * * * * 

21. Section 203.77 is revised to read 

as follows: 

§ 203.77 May I voluntarily give up relief if 

conditions change? 

Yes, you may voluntarily give up 

relief by sending a letter to that effect to 

the MMS Regional office for your 

region. 

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: 

§ 203.78 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 leases ..................................................................................... set by statute. 

(2) Post-November 2000 deep water leases in the GOM or leases offshore Alaska.indicated 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 threshold.the threshold set by statute for pre-Act leases. 

* * * * * 

23. In § 203.79, the section heading is 

revised to read as follows: 

§ 203.79 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: 

§ 203.81 What supplemental reports do 

royalty relief applications require? 

* * * * * 

(b) You must certify that all 

information in your application, 

fabricator’s confirmation and postproduction 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: 

§ 203.89 What is in a cost report? 

* * * * * 

26. In § 203.90, paragraph (b) is 

revised to read as follows: 

§ 203.90 What is in a fabricator’s 

confirmation report? 

* * * * * 

(b) A letter from the contractor 

building the system to the MMS 

Regional Director for your region 

certifying when construction started on 

your system; and 

* * * * * 

PART 260 OUTER CONTINENTAL 

SHELF OIL AND GAS LEASING 

27. The authority citation for part 260 

continues to read as follows: 

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

28. In § 260.121, paragraph (b) is 

revised to read as follows: 

§ 260.121 When does a lease issued in a 

sale held after November 2000 get a royalty 

suspension? 

* * * * * 

(b) You may apply for a supplemental 

royalty suspension for a project under 

part 203 of this title, if your lease is 

located: 

(1) In the Gulf of Mexico, in water 200 

meters or deeper, and wholly west of 87 

degrees, 30 minutes West longitude; or 

(2) Offshore of Alaska. 

* * * * * 

29. In § 260.122, paragraph (b)(1) is 

revised to read as follows: 

§ 260.122 How long will a royalty 

suspension volume be effective for a lease 

issued in a sale held after November 2000? 

* * * * * 

(b)(1) Notwithstanding any royalty 

suspension volume under this subpart, 

you must pay royalty at the lease 

stipulated rate on: 

(i) Any oil produced for any period 

stipulated in the lease during which the 

arithmetic average of the daily closing 

price on the New York Mercantile 

Exchange (NYMEX) for light sweet 

crude oil exceeds the applicable 

threshold price of $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. 

* * * * * 

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

BILLING CODE 4310–MR–P 


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