eCFR for 30 CFR Part 203 - Relief or Reduction in Royalty Rates

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Title 30 → Chapter II → Subchapter A → Part 203
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Title 30: Mineral Resources

PART 203—RELIEF OR REDUCTION IN ROYALTY RATES
Contents
Subpart A—General Provisions
§203.0   What definitions apply to this part?
§203.1   What is BSEE's authority to grant royalty relief?
§203.2   How can I obtain royalty relief?
§203.3   Do I have to pay a fee to request royalty relief?
§203.4   How do the provisions in this part apply to different types of leases and projects?
§203.5   What is BSEE's authority to collect information?
Subpart B—OCS Oil, Gas, and Sulfur General

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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?
§203.31   If I have a qualified phase 2 or qualified phase 3 ultra-deep well, what royalty relief would that well earn for my lease?
§203.32   What other requirements or restrictions apply to royalty relief for a qualified phase 2 or phase 3 ultra-deep well?
§203.33   To which production do I apply the RSV earned by qualified phase 2 and phase 3 ultra-deep wells on my lease or in
my unit?
§203.34   To which production may an RSV earned by qualified phase 2 and phase 3 ultra-deep wells on my lease not be
applied?
§203.35   What administrative steps must I take to use the RSV earned by a qualified phase 2 or phase 3 ultra-deep well?
§203.36   Do I keep royalty relief if prices rise significantly?
RoYaltY Relief for Drilling Deep Gas Wells on Leases Not SubJect to Deep Water RoYaltY Relief
§203.40   Which leases are eligible for royalty relief as a result of drilling a deep well or a phase 1 ultra-deep well?
§203.41   If I have a qualified deep well or a qualified phase 1 ultra-deep well, what royalty relief would my lease earn?
§203.42   What conditions and limitations apply to royalty relief for deep wells and phase 1 ultra-deep wells?
§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?
§203.44   What administrative steps must I take to use the royalty suspension volume?
§203.45   If I drill a certified unsuccessful well, what royalty relief will my lease earn?
§203.46   To which production do I apply the royalty suspension supplements from drilling one or two certified unsuccessful
wells on my lease?
§203.47   What administrative steps do I take to obtain and use the royalty suspension supplement?
§203.48   Do I keep royalty relief if prices rise significantly?
§203.49   May I substitute the deep gas drilling provisions in this part for the deep gas royalty relief provided in my lease terms?
RoYaltY Relief for End-of-Life Leases

[A1]

§203.50   Who may apply for end-of-life royalty relief?
§203.51   How do I apply for end-of-life royalty relief?
§203.52   What criteria must I meet to get relief?
§203.53   What relief will BSEE grant?
§203.54   How does my relief arrangement for an oil and gas lease operate if prices rise sharply?
§203.55   Under what conditions can my end-of-life royalty relief arrangement for an oil and gas lease be ended?
§203.56   Does relief transfer when a lease is assigned?

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RoYaltY Relief for Pre-Act Deep Water Leases and for Development and Expansion ProJects
§203.60   Who may apply for royalty relief on a case-by-case basis in deep water in the Gulf of Mexico or offshore of Alaska?
§203.61   How do I assess my chances for getting relief?
§203.62   How do I apply for relief?
§203.63   Does my application have to include all leases in the field?
§203.64   How many applications may I file on a field or a development project?
§203.65   How long will BSEE take to evaluate my application?
§203.66   What happens if BSEE does not act in the time allowed?
§203.67   What economic criteria must I meet to get royalty relief on an authorized field or project?
§203.68   What pre-application costs will BSEE consider in determining economic viability?
§203.69   If my application is approved, what royalty relief will I receive?
§203.70   What information must I provide after BSEE approves relief?
§203.71   How does BSEE allocate a field's suspension volume between my lease and other leases on my field?
§203.72   Can my lease receive more than one suspension volume?
§203.73   How do suspension volumes apply to natural gas?
§203.74   When will BSEE reconsider its determination?
§203.75   What risk do I run if I request a redetermination?
§203.76   When might BSEE withdraw or reduce the approved size of my relief?
§203.77   May I voluntarily give up relief if conditions change?
§203.78   Do I keep relief approved by BSEE under this part for my lease, unit or project if prices rise significantly?
§203.79   How do I appeal BSEE's decisions related to royalty relief for a deepwater lease or a development or expansion
project?
§203.80   When can I get royalty relief if I am not eligible for royalty relief under other sections in the subpart?
Required Reports
§203.81   What supplemental reports do royalty-relief applications require?
§203.82   What is BSEE's authority to collect this information?
§203.83   What is in an administrative information report?
§203.84   What is in a net revenue and relief justification report?
§203.85   What is in an economic viability and relief justification report?
§203.86   What is in a G&G report?
§203.87   What is in an engineering report?
§203.88   What is in a production report?
§203.89   What is in a cost report?
§203.90   What is in a fabricator's confirmation report?
§203.91   What is in a post-production development report?
Subpart C—Federal and Indian Oil [Reserved]
Subpart D—Federal and Indian Gas [Reserved]
Subpart E—Solid Minerals, General [Reserved]
Subpart F [Reserved]
Subpart G—Other Solid Minerals [Reserved]
Subpart H—Geothermal Resources [Reserved]
Subpart I—OCS Sulfur [Reserved]

AuthoritY: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30
U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 U.S.C. 15903-15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.;
and 43 U.S.C. 1801 et seq.
Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

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Subpart A—General Provisions
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§203.0   What definitions apply to this part?
Authorized field means a field:
(1) Located in a water depth of at least 200 meters and in the Gulf of Mexico (GOM) west of 87 degrees, 30 minutes West
longitude;
(2) That includes one or more pre-Act leases; and

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(3) From which no current pre-Act lease produced, other than test production, before November 28, 1995.
Certified unsuccessful well means an original well or a sidetrack with a sidetrack measured depth (i.e., length) of at least
10,000 feet, on your lease that:
(1) You begin drilling on or after March 26, 2003, and before May 3, 2009, on a lease that is located in water partly or
entirely less than 200 meters deep and that is not a non-converted lease, or on or after May 18, 2007, and before May 3, 2013,
on a lease that is located in water entirely more than 200 meters and entirely less than 400 meters deep;
(2) You begin drilling before your lease produces gas or oil from a well with a perforated interval the top of which is at least
18,000 feet true vertical depth subsea (TVD SS), (i.e., below the datum at mean sea level);
(3) You drill to at least 18,000 feet TVD SS with a target reservoir on your lease, identified from seismic and related data,
deeper than that depth;
(4) Fails to meet the producibility requirements of 30 CFR part 550, subpart A, and does not produce gas or oil, or meets
those producibility requirements and Bureau of Ocean Energy Management (BOEM) agrees it is not commercially producible;
and
(5) For which you have provided the notices and information required under §203.47.
Complete application means an original and two copies of the six reports consisting of the data specified in §§203.81,
203.83, and 203.85 through 203.89, along with one set of digital information, which Bureau of Safety and Environmental
Enforcement (BSEE) has reviewed and found complete.
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.
Determination means the binding decision by BSEE on whether your field qualifies for relief or how large a royaltysuspension volume must be to make the field economically viable.
Development project means a project to develop one or more oil or gas reservoirs located on one or more contiguous
leases that have had no production (other than test production) before the current application for royalty relief and are either:
(1) Located in a planning area offshore Alaska; or
(2) Located in the GOM in a water depth of at least 200 meters and wholly west of 87 degrees, 30 minutes West longitude,
and were issued in a sale held after November 28, 2000.
Draft application means the preliminary set of information and assumptions you submit to seek a nonbinding assessment
on whether a field could be expected to qualify for royalty relief.
Eligible lease means a lease that:
(1) Is issued as part of an OCS lease sale held after November 28, 1995, and before November 28, 2000;
(2) Is located in the Gulf of Mexico in water depths of 200 meters or deeper;
(3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
(4) Is offered subject to a royalty suspension volume.
Expansion project means a project that meets the following requirements:
(1) You must propose the project in a (BOEM) Development and Production Plan, a BOEM Development Operations
Coordination Document (DOCD), or a BOEM Supplement to a DOCD, approved by the Secretary of the Interior after November
28, 1995.
(2) The project must be located on either:
(i) A pre-Act lease in the GOM, or a lease in the GOM issued in a sale held after November 28, 2000, located wholly west
of 87 degrees, 30 minutes West longitude; or
(ii) A lease in a planning area offshore Alaska.
(3) On a pre-Act lease in the GOM, the project:
(i) Must significantly increase the ultimate recovery of resources from one or more reservoirs that have not previously
produced (extending recovery from reservoirs already in production does not constitute a significant increase); and
(ii) Must involve a substantial capital investment (e.g., fixed-leg platform, subsea template and manifold, tension-leg
platform, multiple well project, etc.).
(4) For a lease issued in a planning area offshore Alaska, or in the GOM after November 28, 2000, the project must involve
a new well drilled into a reservoir that has not previously produced.
(5) On a lease in the GOM, the project must not include a reservoir the production from which an RSV under §§203.30
through 203.36 or §§203.40 through 203.48 would be applied.
Fabrication (or start of construction) means evidence of an irreversible commitment to a concept and scale of development.
Evidence includes copies of a binding contract between you (as applicant) and a fabrication yard, a letter from a fabricator

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certifying that continuous construction has begun, and a receipt for the customary down payment.
Field means an area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same general
geological structural feature or stratigraphic trapping condition. Two or more reservoirs may be in a field, separated vertically by
intervening impervious strata or laterally by local geologic barriers, or both.
Lease means a lease or unit.
New production means any production from a current pre-Act lease from which no royalties are due on production, other
than test production, before November 28, 1995. Also, it means any additional production resulting from new leasedevelopment activities on a lease issued in a sale after November 28, 2000, or a current pre-Act lease under a BOEM DOCD or
a BOEM Supplement approved by the Secretary of the Interior after November 28, 1995.
Nonbinding assessment means an opinion by BSEE of whether your field could qualify for royalty relief. It is based on your
draft application and does not entitle the field to relief.
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.
Original well means a well that is drilled without utilizing an existing wellbore. An original well includes all sidetracks drilled
from the original wellbore either before the drilling rig moves off the well location or after a temporary rig move that BSEE
agrees was forced by a weather or safety threat and drilling resumes within 1 year. A bypass from an original well (e.g., drilling
around material blocking the hole or to straighten crooked holes) is part of the original well.
Participating area means that part of the unit area that BSEE determines is reasonably proven by drilling and completion of
producible wells, geological and geophysical information, and engineering data to be capable of producing hydrocarbons in
paying quantities.
Performance conditions mean minimum conditions you must meet, after we have granted relief and before production
begins, to remain qualified for that relief. If you do not meet each one of these performance conditions, we consider it a change
in material fact significant enough to invalidate our original evaluation and approval.
Phase 1 ultra-deep well means an ultra-deep well on a lease that is located in water partly or entirely less than 200 meters
deep for which drilling began before May 18, 2007, and that begins production before May 3, 2009, or that meets the
requirements to be a certified unsuccessful well.
Phase 2 ultra-deep well means an ultra-deep well for which drilling began on or after May 18, 2007; and that either meets
the requirements to be a certified unsuccessful well or that begins production:
(1) Before the date which is 5 years after the lease issuance date on a non-converted lease; or
(2) Before May 3, 2009, on all other leases located in water partly or entirely less than 200 meters deep; or
(3) Before May 3, 2013, on a lease that is located in water entirely more than 200 meters and entirely less than 400 meters
deep.
Phase 3 ultra-deep well means an ultra-deep well for which drilling began on or after May 18, 2007, and that begins
production:
(1) On or after the date which is 5 years after the lease issuance date on a non-converted lease; or
(2) On or after May 3, 2009, on all other leases located in water partly or entirely less than 200 meters deep; or
(3) On or after May 3, 2013, on a lease that is located in water entirely more than 200 meters and entirely less than 400
meters deep.
Pre-Act lease means a lease that:
(1) Results from a sale held before November 28, 1995;
(2) Is located in the GOM in water depths of 200 meters or deeper; and
(3) Lies wholly west of 87 degrees, 30 minutes West longitude.
Production means all oil, gas, and other relevant products you save, remove, or sell from a tract or those quantities
allocated to your tract under a unitization formula, as measured for the purposes of determining the amount of royalty payable
to the United States.
Project means any activity that requires at least a permit to drill.
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

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(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 nonconverted lease, an ultra-deep well for which drilling began on or after May 18, 2007, that produces natural gas (other than test
production), including gas associated with oil production, and for which you have met the requirements prescribed in §203.35.
Qualified well means either a qualified deep well or a qualified ultra-deep well.
Redetermination means our reconsideration of our determination on royalty relief because you request it after:
(1) We have rejected your application;
(2) We have granted relief but you want a larger suspension volume;
(3) We withdraw approval; or
(4) You renounce royalty relief.
Renounce means action you take to give up relief after we have granted it and before you start production.
Reservoir means an underground accumulation of oil or natural gas, or both, characterized by a single pressure system
and segregated from other such accumulations.
Royalty suspension (RS) lease means a lease that:
(1) Is issued as part of an OCS lease sale held after November 28, 2000;
(2) Is in locations or planning areas specified in a particular Notice of OCS Lease Sale offering that lease; and
(3) Is offered subject to a royalty suspension specified in a Notice of OCS Lease Sale published in the Federal Register.
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 a BSEEapproved 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.
Sidetrack means, for the purpose of this subpart, a well resulting from drilling an additional hole to a new objective bottomhole location by leaving a previously drilled hole. A sidetrack also includes drilling a well from a platform slot reclaimed from a
previously drilled well or re-entering and deepening a previously drilled well. A bypass from a sidetrack (e.g., drilling around
material blocking the hole, or to straighten crooked holes) is part of the sidetrack.
Sidetrack measured depth means the actual distance or length in feet a sidetrack is drilled beginning where it exits a
previously drilled hole to the bottom hole of the sidetrack, that is, to its total depth.
Sunk costs for an authorized field means the after-tax eligible costs that you (not third parties) incur for exploration,
development, and production from the spud date of the first discovery on the field to the date we receive your complete
application for royalty relief. The discovery well must be qualified as producible under 30 CFR part 550, subpart A. Sunk costs
include the rig mobilization and material costs for the discovery well that you incurred before its spud date.
Sunk costs for an expansion or development project means the after-tax eligible costs that you (not third parties) incur for
only the first well that encounters hydrocarbons in the reservoir(s) included in the application and that meets the producibility
requirements under 30 CFR part 550, subpart A on each lease participating in the application. Sunk costs include rig
mobilization and material costs for the discovery wells that you incurred before their spud dates.
Ultra-deep well means either an original well or a sidetrack completed with a perforated interval the top of which is at least
20,000 feet TVD SS. An ultra-deep well subsequently re-perforated less than 20,000 feet TVD SS in the same reservoir is still
an ultra-deep well.
Withdraw means action we take on a field that has qualified for relief if you have not met one or more of the performance
conditions.
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§203.1   What is BSEE's authority to grant royalty relief?
The Outer Continental Shelf (OCS) Lands Act, 43 U.S.C. 1337, as amended by the OCS Deep Water Royalty Relief Act
(DWRRA), Public Law 104-58 and the Energy Policy Act of 2005, Public Law 109-058 authorizes us to grant royalty relief in four
situations.

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(a) Under 43 U.S.C. 1337(a)(3)(A), we may reduce or eliminate any royalty or a net profit share specified for an OCS lease
to promote increased production.
(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.
(c) Under 43 U.S.C. 1337(a)(3)(C), we may suspend royalties for designated volumes of new production from any lease if:
(1) Your lease is in deep water (water at least 200 meters deep);
(2) Your lease is in designated areas of the GOM (west of 87 degrees, 30 minutes West longitude);
(3) Your lease was acquired in a lease sale held before the DWRRA (before November 28, 1995);
(4) We find that your new production would not be economic without royalty relief; and
(5) Your lease is on a field that did not produce before enactment of the DWRRA, or if you propose a project to significantly
expand production under a Development Operations Coordination Document (DOCD) or a supplementary DOCD, that the
Bureau of Ocean Energy Management (BOEM) approved after November 28, 1995.
(d) Under 42 U.S.C. 15904-15905, we may suspend royalties for designated volumes of gas production from deep and
ultra-deep wells on a lease if:
(1) Your lease is in shallow water (water less than 400 meters deep) and you produce from an ultra-deep well (top of the
perforated interval is at least 20,000 feet TVD SS) or your lease is in waters entirely more than 200 meters and entirely less
than 400 meters deep and you produce from a deep well (top of the perforated interval is at least 15,000 feet TVD SS);
(2) Your lease is in the designated area of the GOM (wholly west of 87 degrees, 30 minutes west longitude); and
(3) Your lease is not eligible for deep water royalty relief.
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§203.2   How can I obtain royalty relief?
We may reduce or suspend royalties for Outer Continental Shelf (OCS) leases or projects that meet the criteria in the
following table.
If you have a lease . . .
And if you . . .
Then we may grant you . . .
(a) With earnings that cannot sustain Would abandon otherwise potentially
A reduced royalty rate on current monthly
production (i.e., End-of-life lease),
recoverable resources but seek to
production and a higher royalty rate on
increase production by operating
additional monthly production (see §§203.50
beyond the point at which the lease is through 203.56).
economic under the existing royalty
rate,
(b) Located in a designated GOM
Propose an expansion project and can A royalty suspension for a minimum production
deep water area (i.e., 200 meters or demonstrate your project is uneconomic volume plus any additional production large
greater) and acquired in a lease sale without royalty relief,
enough to make the project economic (see
held before November 28, 1995, or
§§203.60 through 203.79).
after November 28, 2000,
(c) Located in a designated GOM
Are on a field from which no current pre- A royalty suspension for a minimum production
deep water area and acquired in a
Act lease produced (other than test
volume plus any additional volume needed to
lease sale held before November 28, production) before November 28, 1995, make the field economic (see §§203.60 through
1995 (Pre-Act lease),
(Authorized field,)
203.79).
(d) Located in a designated GOM
Propose a development project and can A royalty suspension for a minimum production
deep water area and acquired in a
demonstrate that the suspension
volume plus any additional volume needed to
lease sale held after November 28, volume, if any, for your lease is not
make your project economic (see §§203.60
2000,
enough to make development
through 203.79).
economic,
(e) Where royalty relief would
Are not eligible to apply for end-of-life or A royalty modification in size, duration, or form
recover significant additional
deep water royalty relief, but show us
that makes your lease or project economic (see
resources or, offshore Alaska or in
you meet certain eligibility conditions,
§203.80).
certain areas of the GOM, would
enable development,
(f) Located in a designated GOM
Drill a deep well on a lease that is not
A royalty suspension for a volume of gas
shallow water area and acquired in a eligible for deep water royalty relief and produced from successful deep and ultra-deep
lease sale held before January 1,
you have not previously produced oil or wells, or, for certain unsuccessful deep and
2001, or after January 1, 2004, or
gas from a deep well or an ultra-deep
ultra-deep wells, a smaller royalty suspension
have exercised an option to
well,
for a volume of gas or oil produced by all wells
substitute for royalty relief in your
on your lease (see §§203.40 through 203.49).
lease terms,
(g) Located in a designated GOM
Drill and produce gas from an ultraA royalty suspension for a volume of gas
shallow water area,
deep well on a lease that is not eligible produced from successful ultra-deep and deep

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(h) Located in planning areas
offshore Alaska,

for deep water royalty relief and you
have not previously produced oil or gas
from an ultra-deep well,
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,

wells on your lease (see §§203.30 through
203.36).
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).

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§203.3   Do I have to pay a fee to request royalty relief?
When you submit an application or ask for a preview assessment, you must include a fee to reimburse us for our costs of
processing your application or assessment. Federal policy and law require us to recover the cost of services that confer special
benefits to identifiable non-Federal recipients. The Independent Offices Appropriation Act (31 U.S.C. 9701), Office of
Management and Budget Circular A-25, and the Omnibus Appropriations Bill (Pub. L. 104-134, 110 Stat. 1321, April 26, 1996)
authorize us to collect these fees.
(a) We will specify the necessary fees for each of the types of royalty relief applications and possible BSEE audits in a
Notice to Lessees. We will periodically update the fees to reflect changes in costs, as well as provide other information
necessary to administer royalty relief.
(b) You must file all payments electronically through the Fees for Services page on the BSEE Web site at
http://www.bsee.gov, and you must include a copy of the Pay.gov confirmation receipt page with your application or
assessment.
[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36148, June 6, 2016]

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§203.4   How do the provisions in this part apply to different types of leases and projects?
The tables in this section summarize the similar application and approval provisions for the discretionary end-of-life and
deep water royalty relief programs in §§203.50 to 203.91. Because royalty relief for deep gas on leases not subject to deep
water royalty relief, as provided for under §§203.40 to 203.48, does not involve an application, its provisions do not parallel the
other two royalty relief programs and are not summarized in this section.
(a) We require the information elements indicated by an X in the following table and described in §§203.51, 203.62, and
203.81 through 203.89 for applications for royalty relief.

Information elements
(1) Administrative information report
(2) Net revenue and relief justification report (prescribed format)
(3) Economic viability and relief justification report (Royalty Suspension Viability
Program (RSVP) model inputs justified with Geological and Geophysical (G&G),
Engineering, Production, & Cost reports)
(4) G&G report
(5) Engineering report
(6) Production report
(7) Deep water cost report

End- Deep water
ofPrelife Expansion act Development
lease project
lease project
X
X
X
X
X
X
X
X

X
X
X
X

X
X
X
X

X
X
X
X

(b) We require the confirmation elements indicated by an X in the following table and described in §§203.70, 203.81,
203.90 and 203.91 to retain royalty relief.
Deep water
End-ofPrelife
Expansion act Development
Confirmation elements
lease
project
lease project
(1) Fabricator's confirmation report
X
X
X
(2) Post-production development report approved by an independent certified public
X
X
X
accountant (CPA) *  *  *
(c) The following table indicates by an X, and §§203.50, 203.52, 203.60 and 203.67 describe, the prerequisites for our
approval of your royalty relief application.
Deep water

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End-of-life
Pre-act Development
Approval conditions
lease
Expansion lease project
(1) At least 12 of the last 15 months have the required level of production
X
(2) Already producing
X
(3) A producible well into a reservoir that has not produced before
X
X
X
(4) Royalties for qualifying months exceed 75 percent of net revenue (NR)
X
(5) Substantial investment on a pre-Act lease (e.g., platform, subsea template)
(6) Determined to be economic only with relief
X
X
X
(d) The following table indicates by an X, and §§203.52, 203.74, and 203.75 describe, the prerequisites for a
redetermination of our royalty relief decision.
Deep water
End-of-life Expansion Pre-act Development
Redetermination conditions
lease
project
lease project
(1) After 12 months under current rate, criteria same as for approval
X
(2) For material change in geologic data, prices, costs, or available technology
X
X
X
(e) The following table indicates by an X, and §§203.53 and 203.69 describe, the characteristics of approved royalty relief.
End- Deep water
ofPrelife Expansion act Development
Relief rate and volume, subject to certain conditions
lease project
lease project
(1) One-half pre-application effective lease rate on the qualifying amount, 1.5 times pre- X
application effective lease rate on additional production up to twice the qualifying
amount, and the pre-application effective lease rate for any larger volumes
(2) Qualifying amount is the average monthly production for 12 qualifying months
X
(3) Zero royalty rate on the suspension volume and the original lease rate on additional
X
X
X
production
(4) Suspension volume is at least 17.5, 52.5 or 87.5 million barrels of oil equivalent
X
(MMBOE)
(5) Suspension volume is at least the minimum set in the Notice of Sale, the lease, or
X
X
the regulations
(6) Amount needed to become economic
X
X
X
(f) The following table indicates by an X, and §§203.54 and 203.78 describe, circumstances under which we discontinue
your royalty relief.
Deep water
EndPreof-life Expansion act Development
Full royalty resumes when
lease project
lease project
(1) Average NYMEX price for last 12 months is at least 25 percent above the average
X
for the qualifying months.
(2) Average NYMEX price for last calendar year exceeds $28/bbl or $3.50/mcf,
X
X
escalated by the gross domestic product (GDP) deflator since 1994
(3) Average prices for designated periods exceed levels we specify in the Notice of
X
X
Sale or the lease
(g) The following table indicates by an X, and §§203.55, 203.76, and 203.77 describe, circumstances under which we end
or reduce royalty relief.
Deep water
End-ofExpansion
life
project
lease
Relief withdrawn or reduced
(1) If recipient requests
X
X
(2) Lease royalty rate is at the effective rate for 12 consecutive months
X
(3) Conditions occur that we specified in the approval letter in individual cases
X
(4) Recipient does not submit post-production report that compares expected to
X
actual costs
(5) Recipient changes development system
X
(6) Recipient excessively delays starting fabrication
X
(7) Recipient spends less than 80 percent of proposed pre-production costs
X
prior to start of production
(8) Amount of relief volume is produced
X

Preact Development
lease project
X
X

X

X

X
X
X

X
X
X

X

X

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§203.5   What is BSEE's authority to collect information?
(a) The Office of Management and Budget (OMB) has approved the information collection requirements in this part under
44 U.S.C. 3501 et seq., and assigned OMB Control Number 1014-0005. The title of this information collection is “30 CFR part
203, Relief or Reduction in Royalty Rates.”
(b) BSEE collects this information to make decisions on the economic viability of leases requesting a suspension or
elimination of royalty or net profit share. Responses are required to obtain a benefit or are mandatory according to 43 U.S.C.
1331 et seq. BSEE will protect information considered proprietary under applicable law and under regulations at §203.61, “How
do I assess my chances for getting relief?” and 30 CFR 250.197, “Data and information to be made available to the public or for
limited inspection.”
(c) 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.
(d) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing
the burden, to the Information Collection Clearance Officer, Bureau of Safety and Environmental Enforcement, 45600 Woodland
Road, Sterling, VA 20166.
[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36148, June 6, 2016]

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Subpart B—OCS Oil, Gas, and Sulfur General
Back to Top

Royalty Relief for Drilling Ultra-Deep Wells on Leases Not SubJect to Deep Water Royalty
Relief
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§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, except as provided in §203.31(b).
(c) If the lease is located entirely in more than 200 meters and entirely less than 400 meters of water, it must either:
(1) Have been issued before November 28, 1995, and not been granted deep water royalty relief under 43 U.S.C. 1337(a)
(3)(C), added by section 302 of the Deep Water Royalty Relief Act; or
(2) Have been issued after November 28, 2000, and not been granted deep water royalty relief under §§203.60 through
203.79.
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§203.31   If I have a qualified phase 2 or qualified phase 3 ultra-deep well, what royalty relief would that well earn for
my lease?
(a) Subject to the administrative requirements of §203.35 and the price conditions in §203.36, your qualified well earns your
lease an RSV shown in the following table in billions of cubic feet (BCF) or in thousands of cubic feet (MCF) as prescribed in
§203.33:
If you have a qualified phase 2 or qualified phase 3
ultra-deep well
that is:
(1) An original well,
(2) A sidetrack with a sidetrack measured depth of at
least 20,000 feet,
(3) An ultra-deep short sidetrack that is a phase 2 ultradeep well,

Then your lease earns an RSV on this volume of gas
production:
35 BCF.
35 BCF.

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- 0 BCF.

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deep well,
(b)(1) This paragraph applies if your lease:
(i) Has produced gas or oil from a deep well with a perforated interval the top of which is less than 18,000 feet TVD SS;
(ii) Was issued in a lease sale held between January 1, 2004, and December 31, 2005; and
(iii) The terms of your lease expressly incorporate the provisions of §§203.41 through 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 qualified well earns your
lease 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
.  .  .
(i) An original well or a sidetrack with a sidetrack
measured depth of at least 20,000 feet TVD SS,
(ii) An ultra-deep short sidetrack,

Then your lease earns an RSV on this volume of gas
production:
10 BCF.
4 BCF plus 600 MCF times sidetrack measured depth (rounded to
the nearest 100 feet) but no more than 10 BCF.

(c) Lessees may request a refund of or recoup royalties paid on production from qualified phase 2 or phase 3 ultra-deep
wells that:
(1) Occurs before December 18, 2008, and
(2) Is subject to application of an RSV under either §203.31 or §203.41.
(d) The following examples illustrate how this section applies. These examples assume that your lease is located in the
GOM west of 87 degrees, 30 minutes West longitude and in water less than 400 meters deep (see §203.30(a)), has no existing
deep or ultra-deep wells and that the price thresholds prescribed in §203.36 have not been exceeded.
Example 1: In 2008, you drill and begin producing from an ultra-deep well with a perforated interval the top of which is 25,000 feet
TVD SS, and your lease has had no prior production from a deep or ultra-deep well. Assuming your lease has no deepwater royalty relief
(see §203.30(c)), your lease is eligible (according to §203.30(b)) to earn an RSV under §203.31 because it has not yet produced from a
deep well. Your lease earns an RSV of 35 BCF under this section when this well begins producing. According to §203.31(a), your 25,000
foot well qualifies your lease for this RSV because the well was drilled after the relief authorized here became effective (when the
proposed version of this rule was published on May 18, 2007) and produced from an interval that meets the criteria for an ultra-deep well
(i.e., is a phase 2 ultra-deep well as defined in §203.0). Then in 2014, you drill and produce from another ultra-deep well with a perforated
interval the top of which is 29,000 feet TVD SS. Your lease earns no additional RSV under this section when this second ultra-deep well
produces, because your lease no longer meets the condition in (§203.30(b)) of no production from a deep well. However, any remaining
RSV earned by the first ultra-deep well on your lease would be applied to production from both the first and the second ultra-deep wells as
prescribed in §203.33(a)(2), or §203.33(b)(2) if your lease is part of a unit.
Example 2: In 2005, you spudded and began producing from an ultra-deep well with a perforated interval the top of which is 23,000
feet TVD SS. Your lease earns no RSV under this section from this phase 1 ultra-deep well (as defined in §203.0) because you spudded
the well before the publication date (May 18, 2007) of the proposed rule when royalty relief under §203.31(a) became effective. 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 (§203.30(b)).
Example 3: In 2000, you began producing from a deep well with a perforated interval the top of which is 16,000 feet TVD SS and your
lease is located in water 100 meters deep. Then in 2008, you drill and produce from a new ultra-deep well with a perforated interval the
top of which is 24,000 feet TVD SS. Your lease earns no RSV under either this section or §203.41 because the 16,000-foot well was
drilled before we offered any way to earn an RSV for producing from a deep well (see dates in the definition of qualified well in §203.0)
and because the existence of the 16,000-foot well means the lease is not eligible (see §203.30(b)) to earn an RSV for the 24,000-foot well.
Because the lease existed in the year 2000, it cannot be eligible for the exception to this eligibility condition provided in §203.31(b).
Example 4: In 2008, you spud and produce from an ultra-deep well with a perforated interval the top of which is 22,000 feet TVD SS,
your lease is located in water 300 meters deep, and your lease has had no previous production from a deep or ultra-deep well. Your lease
earns an RSV of 35 BCF under this section when this well begins producing because your lease meets the conditions in §203.30 and the
well fits the definition of a phase 2 ultra-deep well (in §203.0). Then in 2010, you spud and produce from a deep well with a perforated
interval the top of which is 16,000 feet TVD SS. Your 16,000-foot well earns no RSV because it is on a lease that already has a producing
well at least 18,000 feet subsea (see §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(a)(2), or §203.33(b)(2) if your lease is part of a unit and §203.43(a)(2), or
§203.43(b)(2) if your lease is part of a unit. However, if the 16,000-foot deep well does not begin production until 2016 (or if your lease
were located in water less than 200 meters deep), then the 16,000-foot well would not be a qualified deep well because this well does not
begin production within the interval specified in the definition of a qualified well in §203.0, and the RSV earned by the ultra-deep well
would not be applied to production from this (unqualified) deep well.
Example 5: In 2008, you spud a deep well with a perforated interval the top of which is 17,000 feet TVD SS that becomes a qualified
well and earns an RSV of 15 BCF under §203.41 when it begins producing. Then in 2011, you spud an ultra-deep well with a perforated
interval the top of which is 26,000 feet TVD SS. Your 26,000-foot well becomes a qualified ultra-deep well because it meets the date and
depth conditions in this definition under §203.0 when it begins producing, but your lease earns no additional RSV under this section or
§203.41 because it is on a lease that already has production from a deep well (see §203.30(b)). Both the qualified deep well and the
qualified ultra-deep well would share your lease's total RSV of 15 BCF in the manner prescribed in §§203.33 and 203.43.
Example 6: In 2008, you spud a qualified ultra-deep well that is a sidetrack with a sidetrack measured depth of 21,000 feet and a
perforated interval the top of which is 25,000 feet TVD SS. This well meets the definition of an ultra-deep well but is too long to be

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classified an ultra-deep short sidetrack in §203.0. If your lease is located in 150 meters of water and has not previously produced from a
deep well, your lease earns an RSV of 35 BCF because it was drilled after the effective date for earning this RSV. Further, this RSV
applies to gas production from this and any future qualified deep and qualified ultra-deep wells on your lease, as prescribed in §203.33.
The absence of an expiration date for earning an RSV on an ultra-deep well means this long sidetrack well becomes a qualified well
whenever it starts production. If your sidetrack has a sidetrack measured depth of 14,000 feet and begins production in March 2009, it
earns an RSV of 12.4 BCF under this section because it meets the definitions of a phase 2 ultra-deep well (production begins before the
expiration date for the pre-existing relief in its water depth category) and an ultra-deep short sidetrack in §203.0. However, if it does not
begin production until 2010, it earns no RSV because it is too short as a phase 3 ultra-deep well to be a qualified ultra-deep well.
Example 7: Your lease was issued in June 2004 and expressly incorporates the provisions of §§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, after well no.
1 has started production. Well no. 2 earns your lease an additional RSV of 10 BCF under paragraph (b) of this section because it begins
production in time to be classified as a phase 2 ultra-deep well. If, on the other hand, well no. 2 had begun producing in June 2009, it
would earn no additional RSV for the lease because it would be classified as a phase 3 ultra-deep well and thus is not entitled to the
exception under paragraph (b) of this section.

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§203.32   What other requirements or restrictions apply to royalty relief for a qualified phase 2 or phase 3 ultra-deep
well?
(a) If a qualified ultra-deep well on your lease is within a unitized portion of your lease, the RSV earned by that well under
this section applies only to your lease and not to other leases within the unit or to the unit as a whole.
(b) If your qualified ultra-deep well is a directional well (either an original well or a sidetrack) drilled across a lease line, then
either:
(1) The lease with the perforated interval that initially produces earns the RSV or
(2) If the perforated interval crosses a lease line, the lease where the surface of the well is located earns the RSV.
(c) Any RSV earned under §203.31 is in addition to any royalty suspension supplement (RSS) for your lease under §203.45
that results from a different wellbore.
(d) If your lease earns an RSV under §203.31 and later produces from a deep well that is not a qualified well, the RSV is
not forfeited or terminated, but you may not apply the RSV earned under §203.31 to production from the non-qualified well.
(e) You owe minimum royalties or rentals in accordance with your lease terms notwithstanding any RSVs allowed under
paragraphs (a) and (b) of §203.31.
(f) Unused RSVs transfer to a successor lessee and expire with the lease.
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§203.33   To which production do I apply the RSV earned by qualified phase 2 and phase 3 ultra-deep wells on my
lease or in my unit?
(a) You must apply the RSV allowed in §203.31(a) and (b) to gas volumes produced from qualified wells on or after May
18, 2007, reported on the Oil and Gas Operations Report, Part A (OGOR-A) for your lease under 30 CFR 1210.102. All gas
production from qualified wells reported on the OGOR-A, including production not subject to royalty, counts toward the total
lease RSV earned by both deep or ultra-deep wells on the lease.
(b) This paragraph applies to any lease with a qualified phase 2 or phase 3 ultra-deep well that is not within a BSEEapproved unit. 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) and (b)(2) of this section.
(1) You must apply the RSV to the earliest gas production occurring on and after the later of May 18, 2007, or the date the
first qualified phase 2 or phase 3 ultra-deep well that earns your lease the RSV begins production (other than test production).
(2) You must apply the RSV to only gas production from qualified wells on your lease, regardless of their depth, for which
you have met the requirements in §203.35 or §203.44.
(c) This paragraph applies to any lease with a qualified phase 2 or phase 3 ultra-deep well where all or part of the lease is
within a BSEE-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 follows:
(1) You must apply the RSV to the earliest gas production occurring on and after the later of May 18, 2007, or the date that
the first qualified phase 2 or phase 3 ultra-deep well that earns your lease the RSV begins production (other than test
production).
(2) You must apply the RSV to only gas production:
(i) From qualified wells on the non-unitized area of your lease, regardless of their depth, for which you have met the

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requirements in §203.35 or §203.44; and
(ii) Allocated to your lease under a BSEE-approved unit agreement from qualified wells on unitized areas of your lease and
on other leases in participating areas of the unit, regardless of their depth, for which the requirements in §203.35 or §203.44
have been met. The allocated share under paragraph (a)(2)(ii) of this section does not increase the RSV for your lease.
Example: The east half of your lease A is unitized with all of lease B. There is one qualified phase 2 ultra-deep well on the 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)]. None of the volumes produced from a well that is not within a unit participating
area may be allocated to other leases in the unit.

(d) You must begin paying royalties when the cumulative production of gas from all qualified wells on your lease, or
allocated to your lease under paragraph (b) of this section, reaches the applicable RSV allowed under §203.31 or §203.41. For
the month in which cumulative production reaches this RSV, you owe royalties on the portion of gas production from or
allocated to your lease that exceeds the RSV remaining at the beginning of that month.
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§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 re-perforated
in the same reservoir previously perforated deeper than 15,000 feet TVD SS;
(b) To production from a deep well or ultra-deep well on any other lease, except as provided in paragraph (c) of §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.
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§203.35   What administrative steps must I take to use the RSV earned by a qualified phase 2 or phase 3 ultra-deep
well?
To use an RSV earned under §203.31:
(a) You must notify the BSEE Regional Supervisor for Production and Development in writing of your intent to begin drilling
operations on all your ultra-deep wells.
(b) Before beginning production, you must meet any production measurement requirements that the BSEE Regional
Supervisor for Production and Development has determined are necessary under 30 CFR part 250, subpart L.
(c)(1) Within 30 days of the beginning of production from any wells that would become qualified phase 2 or phase 3 ultradeep wells by satisfying the requirements of this section:
(i) Provide written notification to the BSEE Regional Supervisor for Production and Development that production has
begun; and
(ii) Request confirmation of the size of the RSV earned by your lease.
(2) If you produced from a qualified phase 2 or phase 3 ultra-deep well before December 18, 2008, you must provide the
information in paragraph (c)(1) of this section no later than January 20, 2009.
(d) If you cannot produce from a well that otherwise meets the criteria for a qualified phase 2 ultra-deep well that is an ultradeep 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 BSEE
Regional Supervisor for Production and Development may extend the deadline for beginning production for up to 1 year, based
on the circumstances of the particular well involved, if it meets all the following criteria.
(1) The delay occurred after drilling reached the total depth in your well.
(2) Production (other than test production) was expected to begin from the well before May 3, 2009, on a lease that is
located entirely or partly in water less than 200 meters deep or before May 3, 2013, on a lease that is located entirely in water
more than 200 meters but less than 400 meters deep. You must provide a credible activity schedule with supporting
documentation.

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(3) The delay in beginning production is for reasons beyond your control, such as adverse weather and accidents which
BSEE deems were unavoidable.
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§203.36   Do I keep royalty relief if prices rise significantly?
(a) You must pay the Office of Natural Resources Revenue royalties on all gas production to which an RSV otherwise
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 2007
dollars of .  .  .
(1) $10.15 per
MMBtu,

(2) $4.55 per
MMBtu,

(3) $4.08 per
MMBtu,
(4) $5.83 per
MMBtu,

Applies to .  .  .
(i) 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 December 18, 2008; and
(ii) Any RSV earned under §203.31(b) by a phase 2 ultra-deep well.
(i) Any RSV earned under §203.31(a) by a phase 3 ultra-deep well unless the lease terms prescribe a
different price threshold;
(ii) The last 10 BCF of the 35 BCF of RSV earned under §203.31(a) by a phase 2 ultra-deep well on a
lease that is located in water partly or entirely less than 200 meters deep issued before December 18,
2008, and that is not a non-converted lease;
(iii) The last 15 BCF of the 35 BCF of RSV earned under §203.31(a) by a phase 2 ultra-deep well on a
non-converted lease;
(iv) 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 December 18, 2008, unless the lease terms prescribe a
different price threshold; and
(v) 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.
(i) The first 20 BCF of RSV earned by a well that is located on a non-converted lease issued in OCS
Lease Sale 178.
(i) The first 20 BCF of RSV earned by a well that is located on a non-converted lease issued in OCS
Lease Sales 180, 182, 184, 185, or 187.

(b) For purposes of paragraph (a) of this section, determine the threshold price for any calendar year after 2007 by:
(1) Determining the percentage of change during the year in the Department of Commerce's implicit price deflator for the
gross domestic product; and
(2) Adjusting the threshold price for the previous year by that percentage.
(c) The following examples illustrate how this section applies.
Example 1: Assume that a lessee drills and begins producing from a qualified phase 2 ultra-deep well in 2008 on a lease issued in
2004 in less than 200 meters of water that earns the lease an RSV of 35 BCF. Further, assume the well produces a total of 18 BCF by the
end of 2009 and in both of those years, the average daily NYMEX closing natural gas price is less than $10.15 (adjusted for inflation after
2007). The lessee does not pay royalty on the 18 BCF because the gas price threshold under paragraph (a)(1) of this section applies to
the first 25 BCF of this RSV earned by this phase 2 ultra-deep well. In 2010, the well produces another 13 BCF. In that year, the average
daily closing NYMEX natural gas price is greater than $4.55 per MMBtu (adjusted for inflation after 2007), but less than $10.15 per MMBtu
(adjusted for inflation after 2007). The first 7 BCF produced in 2010 will exhaust the first 25 BCF (that is subject to the $10.15 threshold) of
the 35 BCF RSV that the well earned. The lessee must pay royalty on the remaining 6 BCF produced in 2010, because it is subject to the
$4.55 per MMBtu threshold under paragraph (a)(2)(ii) of this section which was exceeded.
Example 2: Assume that a lessee:
(1) Drills and produces from well no.1, a qualified deep well in 2008 to a depth of 15,500 feet TVD SS that earns a 15 BCF RSV for
the lease under §203.41, which would be subject to a price threshold of $10.15 per MMBtu (adjusted for inflation after 2007), meaning the
lease is partly or entirely in less than 200 meters of water;
(2) Later in 2008, drills and produces from well no. 2, a second qualified deep well to a depth of 17,000 feet TVD SS that earns no
additional RSV (see §203.41(c)(1)); and
(3) In 2015, drills and produces from well no. 3, a qualified phase 3 ultra-deep well that earns no additional RSV since the lease
already has an RSV established by prior deep well production. Further assume that in 2015, the average daily closing NYMEX natural gas
price exceeds $4.55 per MMBtu (adjusted for inflation after 2007) but does not exceed $10.15 per MMBtu (adjusted for inflation after
2007). In 2015, any remaining RSV earned by well no. 1 (which would have been applied to production from well nos. 1 and 2 in the
intervening years), would be applied to production from all three qualified wells. Because the price threshold applicable to that RSV was
not exceeded, the production from all three qualified wells would be royalty-free until the 15 BCF RSV earned by well no. 1 is exhausted.
Example 3: Assume the same initial facts regarding the three wells as in Example 2. Further assume that well no. 1 stopped
producing in 2011 after it had produced 8 BCF, and that well no. 2 stopped producing in 2012 after it had produced 5 BCF. Two BCF of
the RSV earned by well no. 1 remain. That RSV would be applied to production from well no. 3 until it is exhausted, and the lessee
therefore would not pay royalty on those 2 BCF produced in 2015, because the $10.15 per MMBtu (adjusted for inflation after 2007) price
threshold is not exceeded. The determination of which price threshold applies to deep gas production depends on when the first qualified

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well earned the RSV for the lease, not on which wells use the RSV.
Example 4: Assume that in February 2010, a lessee completes and begins producing from an ultra-deep well (at a depth of 21,500
feet TVD SS) on a lease located in 325 meters of water with no prior production from any deep well and no deep water royalty relief. The
ultra-deep well would be a phase 2 ultra-deep well (see definition in §203.0), and would earn the lease an RSV of 35 BCF under §§203.30
and 203.31. Further assume that the average daily closing NYMEX natural gas price exceeds $4.55 per MMBtu (adjusted for inflation after
2007) but does not exceed $10.15 per MMBtu (adjusted for inflation after 2007) during 2010. Because the lease is located in more than
200 but less than 400 meters of water, the $4.55 per MMBtu price threshold applies to the whole RSV (see paragraph (a)(2)(v) of this
section), and the lessee will owe royalty on all gas produced from the ultra-deep well in 2010.

(d) You must pay any royalty due under this section no later than March 31 of the year following the calendar year for which
you owe royalty. If you do not pay by that date, you must pay late payment interest under 30 CFR 1218.54 from April 1 until the
date of payment.
(e) Production volumes on which you must pay royalty under this section count as part of your RSV.
Back to Top

Royalty Relief for Drilling Deep Gas Wells on Leases Not SubJect to Deep Water Royalty
Relief
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§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:
(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. (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.
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§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 Has a qualified deep well or qualified phase 1 ultra-deep earns an RSV specified
ultra-deep well,
well,
in paragraph (b) of this
section.
(2) produced gas or oil from a well with a
Has a qualified deep well with a perforated interval
earns an RSV specified
perforated interval whose top is 18,000 feet whose top is 18,000 feet TVD SS or deeper or a
in paragraph (c) of this

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TVD SS or deeper,

qualified phase 1 ultra-deep well,

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:
(1) An original well with a perforated interval the top of which
is from 15,000 to less than 18,000 feet TVD SS,
(2) A sidetrack with a perforated interval the top of which is
from 15,000 to less than 18,000 feet TVD SS,
(3) An original well with a perforated interval the top of which
is at least 18,000 feet TVD SS,
(4) A sidetrack with a perforated interval the top of which is at
least 18,000 feet TVD SS,

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

Then you earn an RSV on this amount of gas
production:
0 BCF.
10 BCF.
4 BCF plus 600 MCF times sidetrack measured depth
(rounded to the nearest 100 feet) but no more than 10 BCF.

(d) Lessees may request a refund of or recoup royalties paid on production from qualified wells on a lease that is located in
water entirely deeper than 200 meters but entirely less than 400 meters deep that:
(1) Occurs before December 18, 2008; and
(2) Is subject to application of an RSV under either §203.31 or §203.41.
(e) The following examples illustrate how this section applies, assuming your lease meets the location, prior production,
and lease issuance conditions in §203.40 and paragraph (a) of this section:
Example 1: If you have a qualified deep well that is an original well with a perforated interval the top of which is 16,000 feet TVD SS,
your lease earns an RSV of 15 BCF under paragraph (b)(1) of this section. This RSV must be applied to gas production from all qualified
wells on your lease, as prescribed in §§203.43 and 203.48. However, if the top of the perforated interval is 18,500 feet TVD SS, the RSV
is 25 BCF according to paragraph (b)(3) of this section.
Example 2: If you have a qualified deep well that is a sidetrack, with a perforated interval the top of which is 16,000 feet TVD SS and
a sidetrack measured depth of 6,789 feet, we round the measured depth to 6,800 feet and your lease earns an RSV of 8.08 BCF under
paragraph (b)(2) of this section. This RSV would be applied to gas production from all qualified wells on your lease, as prescribed in
§§203.43 and 203.48.
Example 3: If you have a qualified deep well that is a sidetrack, with a perforated interval the top of which is 16,000 feet TVD SS and
a sidetrack measured depth of 19,500 feet, your lease earns an RSV of 15 BCF. This RSV would be applied to gas production from all
qualified wells on your lease, as prescribed in §§203.43 and 203.48, even though 4 BCF plus 600 MCF per foot of sidetrack measured
depth equals 15.7 BCF because paragraph (b)(2) of this section limits the RSV for a sidetrack at the amount an original well to the same
depth would earn.
Example 4: If you have drilled and produced a deep well with a perforated interval the top of which is 16,000 feet TVD SS before
March 26, 2003 (and the well therefore is not a qualified well and has earned no RSV under this section), and later drill:
(i) A deep well with a perforated interval the top of which is 17,000 feet TVD SS, your lease earns no RSV (see paragraph (c)(1) of
this section);
(ii) A qualified deep well that is an original well with a perforated interval the top of which is 19,000 feet TVD SS, your lease earns an
RSV of 10 BCF under paragraph (c)(2) of this section. This RSV would be applied to gas production from qualified wells on your lease, as
prescribed in §§203.43 and 203.48; or
(iii) A qualified deep well that is a sidetrack with a perforated interval the top of which is 19,000 feet TVD SS, that has a sidetrack
measured depth of 7,000 feet, your lease earns an RSV of 8.2 BCF under paragraph (c)(3) of this section. This RSV would be applied to
gas production from qualified wells on your lease, as prescribed in §§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 under paragraph (c)(2) of this section. We will apply that RSV to gas production from
all qualified wells on your lease, as prescribed in §§203.43 and 203.48. If the second well has a perforated interval the top of which is
22,000 feet TVD SS (instead of 19,000 feet), the total RSV for your lease would increase to 25 BCF only in 2 situations: (1) If the second
well was a phase 1 ultra-deep well, i.e., if drilling began before May 18, 2007, or (2) the exception in §203.31(b) applies. In both situations,
your lease must be partly or entirely in less than 200 meters of water and production must begin on this well before May 3, 2009. If drilling
of the second well began on or after May 18, 2007, the second well would be qualified as a phase 2 or phase 3 ultra-deep well and, unless

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the exception in §203.31(b) applies, would not earn any additional RSV (as prescribed in §203.30), so the total RSV for your lease would
remain at 15 BCF.
Example 6: If you have a qualified deep well that is a sidetrack, with a perforated interval the top of which is 16,000 feet TVD SS and
a sidetrack measured depth of 4,000 feet, and later drill a second qualified well that is a sidetrack, with a perforated interval the top of
which is 19,000 feet TVD SS and a sidetrack measured depth of 8,000 feet, we increase the total RSV for your lease from 6.4 BCF [4 +
(600 * 4,000)/1,000,000] to 15.2 BCF {6.4 + [4 + (600 * 8,000)/1,000,000)]} under paragraphs (b)(2) and (c)(3) of this section. We would
apply that RSV to gas production from all qualified wells on your lease, as prescribed in §§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.

Back to Top

§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 . . .
(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,
(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) because you drilled
and produced it within the time intervals set forth in the
definitions for qualified wells,
(c) A qualified deep well or qualified phase 1 ultra-deep well on
your lease is within a unitized portion of your lease,

Then . . .
your lease cannot earn an RSV under §203.41 as a result of
drilling any subsequent deep wells or phase 1 ultra-deep
wells.
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.
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 the lease with the perforated interval that initially produces
is a directional well (either an original well or a sidetrack) drilled earns the RSV. However, if the perforated interval crosses a
across a lease line,
lease line, the lease where the surface of the well is located
earns the RSV.
(e) You earn an RSV under §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 the RSV is not forfeited or terminated, but you may not apply
from a well that is not a qualified well,
the RSV under §203.41 to production from the non-qualified
well.
(g) You qualify for an RSV under paragraphs (b) or (c) of
you still owe minimum royalties or rentals in accordance with
§203.41,
your lease terms.
(h) You transfer your lease,
unused RSVs transfer to a successor lessee and expire with
the lease.
Example to paragraph (b): If your first qualified deep well is a sidetrack with a perforated interval whose top is 16,000 feet TVD SS
and earns an RSV of 12.5 BCF, and you later drill a qualified original deep well to 17,000 feet TVD SS, the RSV for your lease remains at
12.5 BCF and does not increase to 15 BCF. However, under paragraph (c) of §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.

Back to Top

§203.43   To which production do I apply the RSV earned from qualified deep wells or qualified phase 1 ultra-deep
wells on my lease?
(a) You must apply the RSV prescribed in §203.41(b) and (c) to gas volumes produced from qualified wells on or after May
3, 2004, reported on the OGOR-A for your lease under 30 CFR 1210.102, as and to the extent prescribed in §§203.43 and
203.48.
(1) Except as provided in paragraph (a)(2) of this section, all gas production from qualified wells reported on the OGOR-A,
including production that is not subject to royalty, counts toward the lease RSV.
(2) Production to which an RSS applies under §§203.45 and 203.46 does not count toward the lease RSV.
(b) This paragraph applies to any lease with a qualified deep well or qualified phase 1 ultra-deep well when no part of the
lease is within a BSEE-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 (b)(1) and (b)(2) of this section.
(1) You must apply the RSV to the earliest gas production occurring on and after the later of:
(i) May 3, 2004, for an RSV earned by a qualified deep well or qualified phase 1 ultra-deep well on a lease that is located
entirely or partly in water less than 200 meters deep;
(ii) May 18, 2007, for an RSV earned by a qualified deep well on a lease that is located entirely in water more than 200
meters deep; or

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(iii) The date that the first qualified well that earns your lease the RSV begins production (other than test production).
(2) You must apply the RSV to only gas production from qualified wells on your lease, regardless of their depth, for which
you have met the requirements in §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 that it earned. You subsequently drill another original deep well with a perforated interval the top of which is 16,600 feet TVD SS,
which becomes a qualified deep well when production begins in August 2008. The first well earned an RSV of 25 BCF (see §203.41(a)(1)
and (b)(3)). You must apply any remaining RSV each month beginning in August 2008 to production from both wells until the 25 BCF RSV
is fully utilized according to paragraph (b)(2) of this section. If the second well had begun production in August 2009, it would not be a
qualified deep well because it started production after expiration in May 2009 of the ability to qualify for royalty relief in this water depth,
and could not share any of the remaining RSV (see definition of a qualified deep well in §203.0).
Example 2: On a lease in water between 200 and 400 meters deep, you begin drilling an original deep well with a perforated interval
the top of which is 17,100 feet TVD SS in November 2010 that becomes a qualified deep well in June 2011 when it begins producing and
using the RSV. You subsequently drill another original deep well with a perforated interval the top of which is 15,300 feet TVD SS which
becomes a qualified deep well by beginning production in October 2011 (see definition of a qualified deep well in §203.0). Only the first
well earns an RSV equal to 15 BCF (see §203.41(a) and (b)). You must apply any remaining RSV each month beginning in October 2011
to production from both qualified deep wells until the 15 BCF RSV is fully utilized according to paragraph (b)(2) of this section.

(c) This paragraph applies to any lease with a qualified deep well or qualified phase 1 ultra-deep well when all or part of the
lease is within a BSEE-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 (c)
(1) through (3) of this section.
(1) You must apply the RSV to the earliest gas production occurring on and after the later of:
(i) May 3, 2004, for an RSV earned by a qualified well or qualified phase 1 ultra-deep well on a lease that is located entirely
or partly in water less than 200 meters deep;
(ii) May 18, 2007, for an RSV earned by a qualified deep well on a lease that is located entirely in water more than 200
meters deep; or
(iii) The date that the first qualified well that earns your lease the RSV begins production (other than test production).
(2) You must apply the RSV to only gas production:
(i) From all qualified wells on the non-unitized area of your lease, regardless of their depth, for which you have met the
requirements in §203.35 or §203.44; and,
(ii) Allocated to your lease under a BSEE-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 (c)(2)(ii) of this section does not increase the RSV for your lease. None of the
volumes produced from a well that is not within a unit participating area may be allocated to other leases in the unit.
Example: The east half of your lease A is unitized with all of lease B. There is one qualified 19,000-foot TVD SS deep well on the nonunitized portion of lease A, one qualified 18,500-foot TVD SS deep well on the unitized portion of lease A, and a qualified 19,400-foot TVD
SS deep well on lease B. The participating area percentages allocate 32 percent of production from both of the unit qualified deep wells to
lease A and 68 percent to lease B. If the non-unitized qualified deep well on lease A produces 12 BCF and the unitized qualified deep well
on lease A produces 15 BCF, and the qualified deep well on lease B produces 10 BCF, then the production volume from and allocated to
lease A to which the lease an RSV applies is 20 BCF [12 + (15 + 10) * (0.32)]. The production volume allocated to lease B to which the
lease B RSV applies is 17 BCF [(15 + 10) * (0.68)].

(d) You must begin paying royalties when the cumulative production of gas from all qualified wells on your lease, or
allocated to your lease under paragraph (c) of this section, reaches the applicable RSV allowed under §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.
(e) 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 (c) of this
section;
(3) Any liquid hydrocarbon (oil and condensate) volumes; or
(4) Production from a deep well or phase 1 ultra-deep well that commenced drilling before:
(i) March 26, 2003, on a lease that is located entirely or partly in water less than 200 meters deep, or
(ii) May 18, 2007, on a lease that is located entirely in water more than 200 meters deep.
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§203.44   What administrative steps must I take to use the royalty suspension volume?
(a) You must notify the BSEE Regional Supervisor for Production and Development in writing of your intent to begin drilling
operations on all deep wells and phase 1 ultra-deep wells; and
(b) Within 30 days of the beginning of production from all wells that would become qualified wells by satisfying the
requirements of this section, you must:
(1) Provide written notification to the BSEE Regional Supervisor for Production and Development that production has
begun; and
(2) Request confirmation of the size of the royalty suspension volume earned by your lease.
(c) Before beginning production, you must meet any production measurement requirements that the BSEE Regional
Supervisor for Production and Development has determined are necessary under 30 CFR part 250, subpart L.
(d) You must provide the information in paragraph (b) of this section by January 20, 2009, if you produced before
December 18, 2008, from a qualified deep well or qualified phase 1 ultra-deep well on a lease that is located entirely in water
more than 200 meters and less than 400 meters deep.
(e) The BSEE 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 deadline in the
definition of a qualified deep well in §203.0. You must provide a credible activity schedule with supporting documentation.
(4) The delay in beginning production is for reasons beyond your control, such as adverse weather and accidents which
BSEE deems were unavoidable.
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§203.45   If I drill a certified unsuccessful well, what royalty relief will my lease earn?
Your lease may earn a royalty suspension supplement. Subject to paragraph (d) of this section, the royalty suspension
supplement is in addition to any royalty suspension volume your lease may earn under §203.41.
(a) If you drill a certified unsuccessful well and you satisfy the administrative requirements of §203.47, subject to the price
conditions in §203.48, your lease earns an RSS shown in the following table. The RSS is shown in billions of cubic feet of gas
equivalent (BCFE) or in thousands of cubic feet of gas equivalent (MCFE) and is applicable to oil and gas production as
prescribed in §203.46.
Then your lease earns an RSS on this
volume of oil and gas production as
prescribed in this section and §203.46:
If you have a certified unsuccessful well that is:—
—
(1) An original well and your lease has not produced gas or oil from a deep well or 5 BCFE.
an ultra-deep well,
(2) A sidetrack (with a sidetrack measured depth of at least 10,000 feet) and your 0.8 BCFE plus 120 MCFE times sidetrack
lease has not produced gas or oil from a deep well or an ultra-deep well,
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
2 BCFE.
10,000 feet) and your lease has produced gas or oil from a deep well with a
perforated interval the top of which is from 15,000 to less than 18,000 feet TVD
SS,
(b) This paragraph applies to oil and gas volumes you report on the OGOR-A for your lease under 30 CFR 1210.102.
(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 December 18, 2008, if your lease is located in water more than 200 meters but less than 400 meters deep; or
(ii) On or after May 3, 2004, if your lease is located in water partly or entirely less than 200 meters deep.
(2) Production to which an RSV applies under §§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.

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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, BSEE rounds the
sidetrack measured depth to 12,500 feet and your lease earns an RSS of 2.3 BCFE of gas and oil production as prescribed in §203.45.

(c) The conversion from oil to gas for using the royalty suspension supplement is specified in §203.73.
(d) Each lease is eligible for up to two royalty suspension supplements. Therefore, the total royalty suspension supplement
for a lease cannot exceed 10 BCFE.
(1) You may not earn more than one royalty suspension supplement from a single wellbore.
(2) If you begin drilling a certified unsuccessful well on one lease but the completion target is on a second lease, the entire
royalty suspension supplement belongs to the second lease. However, if the target straddles a lease line, the lease where the
surface of the well is located earns the royalty suspension supplement.
(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:
(1) Beginning on the date production starts, you must stop applying the royalty suspension supplement earned by that
wellbore to your lease production.
(2) If the completion of this qualified well is on your lease or, in the case of a directional well, is on another lease, then you
must subtract from the royalty suspension volume earned by that qualified well the royalty suspension supplement amounts
earned by that wellbore that have already been applied either on your lease or any other lease. The difference represents the
royalty suspension volume earned by the qualified well.
(f) If the same wellbore that earned a royalty suspension supplement later has a sidetrack drilled from that wellbore, you
are not required to subtract any royalty suspension supplement earned by that wellbore from the royalty suspension volume that
may be earned by the sidetrack.
(g) You owe minimum royalties or rentals in accordance with your lease terms notwithstanding any royalty suspension
supplements under this section.
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§203.46   To which production do I apply the royalty suspension supplements 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:
(1) Occurring on and after the day you file the information under §203.47(b),
(2) From, or allocated under a BSEE-approved unit agreement to, the lease on which the certified unsuccessful well was
drilled, without regard to the drilling depth of the well producing the gas or oil.
(b) If you have a royalty suspension volume for the lease under §203.41, you must use the royalty suspension volumes for
gas produced from qualified wells on the lease before using royalty suspension supplements for gas produced from qualified
wells.
Example to paragraph (b): You have two shallow oil wells on your lease. Then you drill a certified unsuccessful well and earn a royalty
suspension supplement of 5 BCFE. Thereafter, you begin production from an original well that is a qualified well that earns a royalty
suspension volume of 15 BCF. You use only 2 BCFE of the royalty suspension supplement before the oil wells deplete. You must use up
the 15 BCF of royalty suspension volume before you use the remaining 3 BCFE of the royalty suspension supplement for gas produced
from the qualified well.

(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 a BSEE-approved unit agreement to, your lease.
(d) Unused royalty suspension supplements transfer to a successor lessee and expire with the 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 a BSEE-approved unit agreement. If your certified unsuccessful well is on a lease subject to a BSEEapproved 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.
(f) You must begin or resume paying royalties when cumulative gas and oil production from, or allocated under a BSEEapproved unit agreement to, your lease (excluding any gas produced from qualified wells subject to a royalty suspension
volume allowed under §203.41) reaches the applicable royalty suspension supplement. For the month in which the cumulative
production reaches this royalty suspension supplement, you owe royalties on the portion of gas or oil production that exceeds
the amount of the royalty suspension supplement remaining at the beginning of that month.
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§203.47   What administrative steps do I take to obtain and use the royalty suspension supplement?

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(a) Before you start drilling a well on your lease targeted to a reservoir at least 18,000 feet TVD SS, you must notify, in
writing, the BSEE Regional Supervisor for Production and Development of your intent to begin drilling operations and the depth
of the target.
(b) After drilling the well, you must provide the BSEE Regional Supervisor for Production and Development within 60 days
after reaching the total depth in your well:
(1) Information that allows BSEE to confirm that you drilled a certified unsuccessful well as defined under §203.0, including:
(i) Well log data, if your original well or sidetrack does not meet the producibility requirements of 30 CFR part 550, subpart
A; or
(ii) Well log, well test, seismic, and economic data, if your well does meet the producibility requirements of 30 CFR part
550, subpart A; and
(2) Information that allows BSEE to confirm the size of the royalty suspension supplement for a sidetrack, including
sidetrack measured depth and supporting documentation.
(c) If you commenced drilling a well that otherwise meets the criteria for a certified unsuccessful well on a lease located
entirely in more than 200 meters and entirely less than 400 meters of water on or after May 18, 2007, and finished it before
December 18, 2008, you must provide the information in paragraph (b) of this section no later than February 17, 2009.
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§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.
And issued .
..
before
December 18,
2008,
(2) Partly or entirely less than 200
after
meters deep,
December 18,
2008,
(3) Entirely more than 200 meters and on any date,
entirely less than 400 meters deep,
For a lease located in water . . .
(1) Partly or entirely less than 200
meters deep,

The applicable threshold price is . . .
$10.15 per MMBtu, adjusted annually after calendar year 2007 for
inflation.
$4.55 per MMBtu, adjusted annually after calendar year 2007 for
inflation unless the lease terms prescribe a different price threshold.
$4.55 per MMBtu, adjusted annually after calendar year 2007 for
inflation unless the lease terms prescribe a different price threshold.

(b) Determine the threshold price for any calendar year after 2007 by adjusting the threshold price in the previous year by
the percentage that the implicit price deflator for the gross domestic product, as published by the Department of Commerce,
changed during the calendar year.
(c) You must pay any royalty due under this section no later than March 31 of the year following the calendar year for which
you owe royalty. If you do not pay by that date, you must pay late payment interest under 30 CFR 1218.54 from April 1 until the
date of payment.
(d) Production volumes on which you must pay royalty under this section count as part of your RSV and RSS.
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§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:
(1) Must be issued as part of an OCS lease sale held after January 1, 2001, and before April 1, 2004; and
(2) Must be located wholly west of 87 degrees, 30 minutes West longitude in the GOM entirely or partly in water less than
200 meters deep.
(b) To exercise the option under paragraph (a) of this section, you must notify, in writing, the BSEE Regional Supervisor for
Production and Development of your decision before September 1, 2004, or 180 days after your lease is issued, whichever is
later, and specify the lease and block number.
(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.
(d) Exercising the option under paragraph (a) of this section is irrevocable. If you do not exercise this option, then the terms
of your lease apply.

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Royalty Relief for End-of-Life Leases
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§203.50   Who may apply for end-of-life royalty relief?
You may apply for royalty relief in two situations.
(a) Your end-of-life lease (as defined in §203.2) is an oil and gas lease and has average daily production of at least 100
barrels of oil equivalent (BOE) per month (as calculated in §203.73) in at least 12 of the past 15 months. The most recent of
these 12 months are considered the qualifying months. These 12 months should reflect the basic operation you intend to use
until your resources are depleted. If you changed your operation significantly (e.g., begin re-injecting rather than recovering gas)
during the qualifying months, or if you do so while we are processing your application, we may defer action on your application
until you revise it to show the new circumstances.
(b) Your end-of-life lease is other than an oil and gas lease (e.g., sulphur) and has production in at least 12 of the past 15
months. The most recent of these 12 months are considered the qualifying months.
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§203.51   How do I apply for end-of-life royalty relief?
You must submit a complete application and the required fee to the appropriate BSEE Regional Director. Your BSEE
regional office will provide specific guidance on the report formats. A complete application for relief includes:
(a) An administrative information report (specified in §203.83) and
(b) A net revenue and relief justification report (specified in §203.84).
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§203.52   What criteria must I meet to get relief?
(a) To qualify for relief, you must demonstrate that the sum of royalty payments over the 12 qualifying months exceeds 75
percent of the sum of net revenues (before-royalty revenues minus allowable costs, as defined in §203.84).
(b) To re-qualify for relief, e.g., either applying for additional relief on top of relief already granted, or applying for relief
sometime after your earlier agreement terminated, you must demonstrate that:
(1) You have met the criterion listed in paragraph (a) of this section, and
(2) The 12 required qualifying months of operation have occurred under the current royalty arrangement.
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§203.53   What relief will BSEE grant?
(a) If we approve your application and you meet certain conditions, we will reduce the pre-application effective royalty rate
by one-half on production up to the relief volume amount. If you produce more than the relief volume amount:
(1) We will impose a royalty rate equal to 1.5 times the effective royalty rate on your additional production up to twice the
relief volume amount; and
(2) We will impose a royalty rate equal to the effective rate on all production greater than twice the relief volume amount.
(b) Regardless of the level of production or prices (see §203.54), royalty payments due under end-of-life relief will not
exceed the royalty obligations that would have been due at the effective royalty rate.
(1) The effective royalty rate is the average lease rate paid on production during the 12 qualifying months.
(2) The relief volume amount is the average monthly BOE production for the 12 qualifying months.
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§203.54   How does my relief arrangement for an oil and gas lease operate if prices rise sharply?
In those months when your current reference price rises by at least 25 percent above your base reference price, you must

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pay the effective royalty rate on all monthly production.
(a) Your current reference price is a weighted average of daily closing prices on the NYMEX for light sweet crude oil and
natural gas over the most recent full 12 calendar months;
(b) Your base reference price is a weighted average of daily closing prices on the NYMEX for light sweet crude oil and
natural gas during the qualifying months; and
(c) Your weighting factors are the proportions of your total production volume (in BOE) provided by oil and gas during the
qualifying months.
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§203.55   Under what conditions can my end-of-life royalty relief arrangement for an oil and gas lease be ended?
(a) If you have an end-of-life royalty relief arrangement, you may renounce it at any time. The lease rate will return to the
effective rate during the qualifying period in the first full month following our receipt of your renouncement of the relief
arrangement.
(b) If you pay the effective lease rate for 12 consecutive months, we will terminate your relief. The lease rate will return to
the effective rate in the first full month following this termination.
(c) We may stipulate in the letter of approval for individual cases certain events that would cause us to terminate relief
because they are inconsistent with an end-of-life situation.
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§203.56   Does relief transfer when a lease is assigned?
Yes. Royalty relief is based on the lease circumstances, not ownership. It transfers upon lease assignment.
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Royalty Relief for Pre-Act Deep Water Leases and for Development and EXpansion ProJects
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§203.60   Who may apply for royalty relief on a case-by-case basis in deep water in the Gulf of Mexico or offshore of
Alaska?
You may apply for royalty relief under §§203.61(b) and 203.62 for an individual lease, unit or project 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).
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§203.61   How do I assess my chances for getting relief?
You may ask for a nonbinding assessment (a formal opinion on whether a field would qualify for royalty relief) before
turning in your first complete application on an authorized field. This field must have a qualifying well under 30 CFR part 550,
subpart A, or be on a lease that has allocated production under an approved unit agreement.
(a) To request a nonbinding assessment, you must:
(1) Submit a draft application in the format and detail specified in guidance from the BSEE regional office for the GOM;
(2) Propose to drill at least one more appraisal well if you get a favorable assessment; and
(3) Pay a fee under §203.3.
(b) You must wait at least 90 days after receiving our assessment to apply for relief under §203.62.
(c) This assessment is not binding because a complete application may contain more accurate information that does not
support our original assessment. It will help you decide whether your proposed inputs for evaluating economic viability and your
supporting data and assumptions are adequate.
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§203.62   How do I apply for relief?
(a) You must send a complete application and the required fee to the BSEE Regional Director for your region.
(b) Your application for royalty relief offshore Alaska or in deep water in the GOM must include an original and two copies
(one set of digital information) of:
(1) Administrative information report;
(2) Economic viability and relief justification report;
(3) G&G report;
(4) Engineering report;
(5) Production report; and
(6) Cost report.
(c) Section 203.82 explains why we are authorized to require these reports.
(d) Sections 203.81, 203.83, and 203.85 through 203.89 describe what these reports must include. The BSEE 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.
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§203.63   Does my application have to include all leases in the field?
(a) For authorized fields, we will accept only one joint application for all leases that are part of the designated field on the
date of application, except as provided in paragraph (a)(3) of this section and §203.64. However, we will evaluate all acreage
that may eventually become part of the authorized field. Therefore, if you have any other leases that you believe may eventually
be part of the authorized field, you must submit data for these leases according to §203.81.
(1) The Regional Director maintains a Field Names Master List with updates of all leases in each designated field.
(2) To avoid sharing proprietary data with other lessees on the field, you may submit your proprietary G&G report
separately from the rest of your application. Your application is not complete until we receive all the required information for
each lease on the field. We will not disclose proprietary data when explaining our assumptions and reasons for our
determinations under §203.67.
(3) We will not require a joint application if you show good cause and honest effort to get all lessees in the field to
participate. If you must exclude a lease from your application because its lessee will not participate, that lease is ineligible for
the royalty relief for the designated field.
(b) If your application seeks only relief for a development project or an expansion project, your application does not have to
include all leases in the field.
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§203.64   How many applications may I file on a field or a development project?
You may file one complete application for royalty relief during the life of the field or for a development project or an
expansion project designed to produce a reservoir or set of reservoirs. However, you may send another application if:
(a) You are eligible to apply for a redetermination under §203.74;
(b) You apply for royalty relief for an expansion project;
(c) You withdraw the application before we make a determination; or
(d) You apply for end-of-life royalty relief.
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§203.65   How long will BSEE take to evaluate my application?
(a) We will determine within 20 working days if your application for royalty relief is complete. If your application is
incomplete, we will explain in writing what it needs. If you withdraw a complete application, you may reapply.
(b) We will evaluate your first application on a field within 180 days, evaluate your first application on a development project
or an expansion project within 150 days and evaluate a redetermination under §203.75 within 120 days after we determine that
it is complete.

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(c) We may ask to extend the review period for your application under the conditions in the following table.
If .  .  .
(1) We need more records to audit sunk costs,

Then we may .  .  .
Ask to extend the 120-day or 180-day evaluation period. The extension
we request will equal the number of days between when you receive our
request for records and the day we receive the records.
(2) We cannot evaluate your application for a valid Add another 30 days. We may add more than 30 days, but only if you
reason, such as missing vital information or
agree.
inconsistent or inconclusive supporting data,
(3) We need more data, explanations, or revision, Ask to extend the 120-day or 180-day evaluation period. The extension
we request will equal the number of days between when you receive our
request and the day we receive the information.
(d) We may change your assumptions under §203.62 if our technical evaluation reveals others that are more appropriate.
We may consult with you before a final decision and will explain any changes.
(e) We will notify all designated lease operators within a field when royalty relief is granted.
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§203.66   What happens if BSEE does not act in the time allowed?
If we do not act within the timeframes established under §203.65, you get royalty relief according to the following table.
If you apply
for royalty
relief for
(a) An
authorized
field,
(b) An
expansion
project,
(c) A
development
project,

And we do not decide within the time specified,
You get the minimum suspension volumes specified in §203.69,

You get a royalty suspension for the first year of production,

You get a royalty suspension for initial production for the number of months that a decision is
delayed beyond the stipulated timeframes set by §203.65, plus all the royalty suspension
volume for which you qualify,

As long as
you
Abide by
§§203.70 and
203.76.
Abide by
§§203.70 and
203.76.
Abide by
§§203.70 and
203.76.

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§203.67   What economic criteria must I meet to get royalty relief on an authorized field or project?
We will not approve applications if we determine that royalty relief cannot make the field, development project, or
expansion project economically viable. Your field or project must be uneconomic while you are paying royalties and must
become economic with royalty relief.
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§203.68   What pre-application costs will BSEE consider in determining economic viability?
(a) We will not consider ineligible costs as set forth in §203.89(h) in determining economic viability for purposes of royalty
relief.
(b) We will consider sunk costs according to the following table.
We will .  .  .
(1) Include sunk costs,

(2) Not include sunk costs,
(3) Not include sunk costs,
(4) Include sunk costs for the
project discovery well on each
lease,

When determining .  .  .
Whether a field that includes a pre-Act lease which has not produced, other than test
production, before the application or redetermination submission date needs relief to become
economic.
Whether an authorized field, a development project, or an expansion project can become
economic with full relief (see §203.67).
How much suspension volume is necessary to make the field, a development project, or an
expansion project economic (see §203.69(c)).
Whether a development project or an expansion project needs relief to become economic.

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§203.69   If my application is approved, what royalty relief will I receive?
If we approve your application, subject to certain conditions, we will not collect royalties on a specified suspension volume
for your field, development project, or expansion project. Suspension volumes include volumes allocated to a lease under an
approved unit agreement, but exclude any volumes of production that are not normally royalty-bearing under the lease or the
regulations of this chapter (e.g., fuel gas).
(a) For authorized fields, the minimum royalty-suspension volumes are:
(1) 17.5 million barrels of oil equivalent (MMBOE) for fields in 200 to 400 meters of water;
(2) 52.5 MMBOE for fields in 400 to 800 meters of water; and
(3) 87.5 MMBOE for fields in more than 800 meters of water.
(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 .  .  .
(1) RS leases in the
GOM or leases
offshore Alaska,

The minimum royalty suspension volume is .  .  .
Plus . . .
A volume equal to the combined royalty suspension volumes (or 10 percent of the median of the
the volume equivalent based on the data in your approved
distribution of known recoverable
application for other forms of royalty suspension) with which BSEE resources upon which BSEE based
issued the leases participating in the application that have or plan approval of your application from all
a well into a reservoir identified in the application,
reservoirs included in the project.
(2) Leases offshore A volume equal to 10 percent of the median of the distribution of
Alaska or other deep known recoverable resources upon which BSEE based approval
water GOM leases
of your application from all reservoirs included in the project.
issued in sales after
November 28, 2000,
(f) If your application includes pre-Act leases in different categories of water depth, we apply the minimum royalty
suspension volume for the deepest such lease then assigned to the field. We base the water depth and makeup of a field on the
water-depth delineations in the “Lease Terms and Economic Conditions” map and the “Fields Directory” documents and
updates in effect at the time your application is deemed complete. These publications are available from the BSEE Gulf of
Mexico Regional Office.
(g) You will get a royalty suspension volume above the minimum if we determine that you need more to make the field or
development project economic.
(h) For expansion projects, the minimum royalty suspension volume equals 10 percent of the median of the distribution of
known recoverable resources upon which we based approval of your application from all reservoirs included in your project plus
any suspension volumes required under §203.66. If we determine that your expansion project may be economic only with more
relief, we will determine and grant you the royalty suspension volume necessary to make the project economic.
(i) The royalty suspension volume applicable to specific leases will continue through the end of the month in which
cumulative production reaches that volume. You must calculate cumulative production from all the leases in the authorized field
or project that are entitled to share the royalty suspension volume.
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§203.70   What information must I provide after BSEE 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 BSEE Regional Office for your region will prescribe the formats.
Required
report
(a) Fabricator's
confirmation
report.
(b) Postproduction
report.

When due to BSEE
Within 18 months after approval of relief.

Due date extensions
BSEE Director may grant you an extension under
§203.79(c) for up to 6 months.

Within 120 days after the start of production that With acceptable justification from you, the BSEE Regional
is subject to the approved royalty suspension
Director for your region may extend the due date up to 30
volume.
days.

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§203.71   How does BSEE allocate a field's suspension volume between my lease and other leases on my field?
The allocation depends on when production occurs, when we issued the lease, when we assigned it to the field, and
whether we award the volume suspension by an approved application or establish it in the lease terms, as prescribed in this
section.
(a) If your authorized field has an approved royalty suspension volume under §§203.67 and 203.69, we will suspend
payment of royalties on production from all leases in the field that participate in the application until their cumulative production
equals the approved volume. The following conditions also apply:
If .  .  .
(1) We
assign an
eligible
lease to
your
authorized
field after
we approve
relief,
(2) We
assign a
pre-Act or
postNovember
2000 deep
water lease
to your field
after we
approve
your
application,
(3) We
assign
another
lease that
you operate
to your field
while we
are
evaluating
your
application,

Then .  .  .
And .  .  .
We will not change your authorized field's royalty Production from the assigned eligible lease(s) counts toward
suspension volume determined under §203.69, the royalty suspension volume for the authorized field, but the
eligible lease will not share any remaining royalty suspension
volume for the authorized field after the eligible lease has
produced the volume applicable under 30 CFR 560.114.

We will not change your field's royalty
suspension volume,

The assigned lease(s) may share in any remaining royalty relief
by filing the short-form application specified in §203.83 and
authorized in §203.82. An assigned RS lease also gets any
portion of its royalty suspension volume remaining even after
the field has produced the approved relief volume.

In our evaluation of your authorized field, we will
take into account the value of any royalty relief
the added lease already has under 30 CFR
560.114 or its lease document. If we find your
authorized field still needs additional royalty
suspension volume, that volume will be at least
the combined royalty suspension volume to
which all added leases on the field are entitled,
or the minimum suspension volume of the
authorized field, whichever is greater,

(i) You toll the time period for evaluation until you modify your
application to be consistent with the newly constituted field;
(ii) We have an additional 60 days to review the new
information; and
(iii) The assigned pre-Act lease or royalty suspension lease
shares the royalty suspension we grant to the newly constituted
field. An eligible lease does not share the royalty suspension we
grant to the new field. If you do not agree to toll, we will have to
reject your application due to incomplete information.
Production from an assigned eligible lease counts toward the
royalty suspension volume that we grant under §203.69 for your
authorized field, but you will not owe royalty on production from
the eligible lease until it has produced the volume applicable
under 30 CFR 560.114.
We will change your field's minimum suspension (i) You both toll the time period for evaluation until both of you
volume provided the assigned lease joins the
modify your application to be consistent with the new field;
application and is entitled to a larger minimum
(ii) We have an additional 60 days to review the new
suspension volume,
information; and
(iii) The assigned lease(s) shares the royalty suspension we
grant to the new field. If you (the original applicant) do not agree
to toll, the other operator's lease retains any suspension volume
it has or may share in any relief that we grant by filing the short
form application specified in §203.83 and authorized in §203.82.

(4) We
assign
another
operator's
lease to
your field
while we
are
evaluating
your
application,
(5) We
The past production from the well counts toward
reassign a the royalty suspension volume that we grant
well on a
under §203.69 to field B,
pre-Act,
eligible, or
royalty
suspension
lease from
field A to
field B,

For any field based relief, the past production for that well will
not count toward any royalty suspension volume that we grant
under §203.69 to field A. Moreover, past production from that
well will count toward the royalty suspension volume applicable
for the lease under 30 CFR 560.114 if the well is on an eligible
lease or under 30 CFR 560.124 if the well is on a royalty
suspension lease.

(b) When a project has more than one lease, the royalty suspension volume for each lease equals that lease's actual
production from the project (or production allocated under an approved unit agreement) until total production for all leases in the
project equals the project's approved royalty suspension volume.
(c) You may receive a royalty-suspension volume only if your entire lease is west of 87 degrees, 30 minutes West
longitude. If the field lies on both sides of this meridian, only leases located entirely west of the meridian will receive a royaltysuspension volume.

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§203.72   Can my lease receive more than one suspension volume?
Yes. You may apply for royalty relief that involves more than one suspension volume under §203.62 in two circumstances.
(a) Each field that includes your lease may receive a separate royalty-suspension volume, if it meets the evaluation criteria
of §203.67.
(b) An expansion project on your lease may receive a separate royalty-suspension volume, even if we have already
granted a royalty-suspension volume to the field that encompasses the project. But the reserves associated with the project
must not have been part of our original determination, and the project must meet the evaluation criteria of §203.67.
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§203.73   How do suspension volumes apply to natural gas?
You must measure natural gas production under the royalty-suspension volume as follows: 5.62 thousand cubic feet of
natural gas, measured in accordance with 30 CFR part 250, subpart L, equals one barrel of oil equivalent.
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§203.74   When will BSEE reconsider its determination?
You may request a redetermination after we withdraw approval or after you renounce royalty relief, unless we withdraw
approval due to your providing false or intentionally inaccurate information. Under certain conditions you may also request a
redetermination if we deny your application or if you want your approved royalty suspension volume to change. In these
instances, to be eligible for a redetermination, at least one of the following four conditions must occur.
(a) You have significant new G&G data and you previously have not either requested a redetermination or reapplied for
relief after we withdrew approval or you relinquished royalty relief. “Significant” means that the new G&G data:
(1) Results from drilling new wells or getting new three-dimensional seismic data and information (but not reinterpreting old
data);
(2) Did not exist at the time of the earlier application; and
(3) Changes your estimates of gross resource size, quality, or projected flow rates enough to materially affect the results of
our earlier determination.
(b) You demonstrate in your new application that the technology that most efficiently develops this field or lease was not
considered or deemed feasible in the original application. Your newly proposed technology must improve the profitability, under
equivalent market conditions, of the field or lease relative to the development system proposed in the prior application.
(c) Your current reference price decreases by more than 25 percent from your base reference price as calculated under
this paragraph.
(1) Your current reference price is a weighted-average of daily closing prices on the NYMEX for light sweet crude oil and
natural gas over the most recent full 12 calendar months;
(2) Your base reference price is a weighted average of daily closing prices on the NYMEX for light sweet crude oil and
natural gas for the full 12 calendar months preceding the date of your most recently approved application for this royalty relief;
and
(3) The weighting factors are the proportions of the total production volume (in BOE) for oil and gas associated with the
most likely scenario (identified in §§203.85 and 203.88) from your most recently approved application for this royalty relief.
(d) Before starting to build your development and production system, you have revised your estimated development costs,
and they are more than 120 percent of the eligible development costs associated with the most likely scenario from your most
recently approved application for this royalty relief.
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§203.75   What risk do I run if I request a redetermination?
If you request a redetermination after we have granted you a suspension volume, you could lose some or all of the
previously granted relief. This can happen because you must file a new complete application and pay the required fee, as
discussed in §203.62. We will evaluate your application under §203.67 using the conditions prevailing at the time of your
redetermination request. In our evaluation, we may find that you should receive a larger, equivalent, smaller, or no suspension
volume. This means we could find that you do not qualify for the amount of relief previously granted or for any relief at all.
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§203.76   When might BSEE withdraw or reduce the approved size of my relief?
We will withdraw approval of relief for any of the following reasons.
(a) You change the type of development system proposed in your application (e.g., change from a fixed platform to floating
production system, or from an independent development and production system to one with subsea wells tied back to a host
production facility, etc.).
(b) You do not start building the proposed development and production system within 18 months of the date we approved
your application, unless the BSEE Director grants you an extension under §203.79(c). If you start building the proposed system
and then suspend its construction before completion, and you do not restart continuous building of the proposed system within
18 months of our approval, we will withdraw the relief we granted.
(c) Your actual development costs are less than 80 percent of the eligible development costs estimated in your
application's most likely scenario, and you do not report that fact in your post-production development report (§203.70).
Development costs are those expenditures defined in §203.89(b) incurred between the application submission date and start of
production. If you report this fact in the post-production development report, you may retain the lesser of 50 percent of the
original royalty suspension volume or 50 percent of the median of the distribution of the potentially recoverable resources
anticipated in your application.
(d) We granted you a royalty-suspension volume after you qualified for a redetermination under §203.74(c), and we find out
your actual development costs are less than 90 percent of the eligible development costs associated with your application's
most likely scenario. Development costs are those expenditures defined in §203.89(b) incurred between your application
submission date and start of production.
(e) You do not send us the fabrication confirmation report or the post-production development report, or you provide false
or intentionally inaccurate information that was material to our granting royalty relief under this section. You must pay royalties
and late-payment interest determined under 30 U.S.C. 1721 and 30 CFR 1218.54 on all volumes for which you used the royalty
suspension. You also may be subject to penalties under other provisions of law.
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§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 BSEE Regional office for your region.
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§203.78   Do I keep relief approved by BSEE under this part for my lease, unit or project if prices rise significantly?
If prices rise above a base price threshold for light sweet crude oil or natural gas, you must pay full royalties on production
otherwise subject to royalty relief approved by BSEE under §§203.60-203.77 for your lease, unit or project as prescribed in this
section.
(a) The following table shows the base price threshold for various types of leases, subject to paragraph (b) of this section.
Note that, for post-November 2000 deepwater leases in the GOM, price thresholds apply on a lease basis, so different leases
on the same development project or expansion project approved for royalty relief may have different price thresholds.
For . . .
(1) Pre-Act leases in the GOM,
(2) Post-November 2000 deep water leases in the GOM or leases
offshore of Alaska for which the lease or Notice of Sale set a base price
threshold,
(3) Post-November 2000 deep water leases in the GOM or leases
offshore of Alaska for which the lease or Notice of Sale did not set a
base price threshold,

The base price threshold is . . .
set by statute.
indicated in your original lease agreement or, if none,
those in the Notice of Sale under which your lease
was issued.
the threshold set by statute for pre-Act leases.

(b) An exception may occur if we determine that the price thresholds in paragraphs (a)(2) or (a)(3) of this section mean the
royalty suspension volume set under §203.69 and in lease terms would provide inadequate encouragement to increase
production or development, in which circumstance we could specify a different set of price thresholds on a case-by-case basis.
(c) Suppose your base oil price threshold set under paragraph (a) is $28.00 per barrel, and the daily closing NYMEX light
sweet crude oil prices for the previous calendar year exceeds $28.00 per barrel, as adjusted in paragraph (h) of this section. In
this case, we retract the royalty relief authorized in this subpart and you must:
(1) Pay royalties on all oil production for the previous year at the lease stipulated royalty rate plus interest (under 30 U.S.C.
1721 and 30 CFR 1218.54) by March 31 of the current calendar year, and
(2) Pay royalties on all your oil production in the current year.
(d) Suppose your base gas price threshold set under paragraph (a) is $3.50 per million British thermal units (Btu), and the
daily closing NYMEX light sweet crude oil prices for the previous calendar year exceeds $3.50 per million Btu, as adjusted in
paragraph (h) of this section. In this case, we retract the royalty relief authorized in this subpart and you must:

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(1) Pay royalties on all gas production for the previous year at the lease stipulated royalty rate plus interest (under 30
U.S.C. 1721 and 30 CFR 1218.54) by March 31 of the current calendar year, and
(2) Pay royalties on all your gas production in the current year.
(e) Production under both paragraphs (c) and (d) of this section counts as part of the royalty-suspension volume.
(f) You are entitled to a refund or credit, with interest, of royalties paid on any production (that counts as part of the royaltysuspension volume):
(1) Of oil if the arithmetic average of the closing prices for the current calendar year is $28.00 per barrel or less, as adjusted
in paragraph (h) of this section, and
(2) Of gas if the arithmetic average of the closing natural gas prices for the current calendar year is $3.50 per million Btu or
less, as adjusted in paragraph (h) of this section.
(g) You must follow our regulations in the Office of Natural Resources Revenue, 30 CFR chapter XII, for receiving refunds
or credits.
(h) We change the prices referred to in paragraphs (c), (d), and (f) of this section periodically. For pre-Act leases, these
prices change during each calendar year after 1994 by the percentage that the implicit price deflator for the gross domestic
product changed during the preceding calendar year. For post-November 2000 deepwater leases, these prices change as
indicated in the lease instrument or in the Notice of Sale under which we issued the lease.
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§203.79   How do I appeal BSEE's decisions related to royalty relief for a deepwater lease or a development or
expansion project?
(a) Once we have designated your lease as part of a field and notified you and other affected operators of the designation,
you can request reconsideration by sending the BSEE Director a letter within 15 days that also states your reasons. The BSEE
Director's response is the final agency action.
(b) Our decisions on your application for relief from paying royalty under §203.67 and the royalty-suspension volumes
under §203.69 are final agency actions.
(c) If you cannot start construction by the deadline in §203.76(b) for reasons beyond your control (e.g., strike at the
fabrication yard), you may request an extension up to 1 year by writing the BSEE Director and stating your reasons. The BSEE
Director's response is the final agency action.
(d) We will notify you of all final agency actions by certified mail, return receipt requested. Final agency actions are not
subject to appeal to the Interior Board of Land Appeals under 30 CFR part 290 and 43 CFR part 4. They are judicially
reviewable under section 10(a) of the Administrative Procedure Act (5 U.S.C. 702) only if you file an action within 30 days of the
date you receive our decision.
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§203.80   When can I get royalty relief if I am not eligible for royalty relief under other sections in the subpart?
We may grant royalty relief when it serves the statutory purposes summarized in §203.1 and our formal relief programs,
including but not limited to the applicable levels of the royalty suspension volumes and price thresholds, provide inadequate
encouragement to promote development or increase production. Unless your lease lies offshore of Alaska or wholly west of 87
degrees, 30 minutes West longitude in the GOM, your lease must be producing to qualify for relief. Before you may apply for
royalty relief apart from our programs for end-of-life leases or for pre-Act deep water leases and development and expansion
projects, we must agree that your lease or project has two or more of the following characteristics:
(a) The lease has produced for a substantial period and the lessee can recover significant additional resources. Significant
additional resources mean enough to allow production for at least a year more than would be profitable without royalty relief.
(b) Valuable facilities (e.g., a platform or pipeline that would be removed upon lease relinquishment) exist that we do not
expect a successor lessee to use. If the facilities are located off the lease, their preservation must depend on continued
production from the lease applying for royalty relief. We will only consider an allocable share of costs for off-lease facilities in the
relief application.
(c) A substantial risk exists that no new lessee will recover the resources.
(d) The lessee made major efforts to reduce operating costs too recently to use the formal program for royalty relief (e.g.,
recent significant change in operations).
(e) Circumstances beyond the lessee's control, other than water depth, preclude reliance on one of the existing royalty
relief programs.
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ReQuired Reports
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§203.81   What supplemental reports do royalty-relief applications require?
(a) You must send us the supplemental reports, indicated in the following table by an X, that apply to your field. Sections
203.83 through 203.91 describe these reports in detail.

Required reports
(1) Administrative information Report
(2) Net revenue & relief justification report
(3) Economic viability & relief justification report (RSVP model inputs
justified by other required reports)
(4) G&G report
(5) Engineering report
(6) Production report
(7) Deep water cost report
(8) Fabricator's confirmation report
(9) Post-production development report

Deep water
End-of-life Expansion Pre-act
lease
project
lease
X
X
X
X
X
X
X
X
X
X
X
X

Development
project
X

X
X
X
X
X
X

X
X
X
X
X
X
X

(b) You must certify that all information in your application, fabricator's confirmation and post-production development
reports is accurate, complete, and conforms to the most recent content and presentation guidelines available from the BSEE
Regional office for your region.
(c) With your application and post-production development report, you must submit an additional report prepared by an
independent CPA that:
(1) Assesses the accuracy of the historical financial information in your report; and
(2) Certifies that the content and presentation of the financial data and information conform to our most recent guidelines
on royalty relief. This means the data and information must:
(i) Include only eligible costs that are incurred during the qualification months; and
(ii) Be shown in the proper format.
(d) You must identify the people in the CPA firm who prepared the reports referred to in paragraph (c) of this section and
make them available to us to respond to questions about the historical financial information. We may also further review your
records to support this information.
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§203.82   What is BSEE's authority to collect this information?
The Office of Management and Budget (OMB) approved the information collection requirements in part 203 under 44
U.S.C. 3501 et seq., and assigned OMB control number 1010-0071.
(a) We use the information to determine whether royalty relief will result in production that wouldn't otherwise occur. We
rely largely on your information to make these determinations.
(1) Your application for royalty relief must contain enough information on finances, economics, reservoirs, G&G
characteristics, production, and engineering estimates for us to determine whether:
(i) We should grant relief under the law, and
(ii) The requested relief will ultimately recover more resources and return a reasonable profit on project investments.
(2) Your fabricator confirmation and post-production development reports must contain enough information for us to verify
that your application reasonably represented your plans.
(b) Applicants (respondents) are Federal OCS oil and gas lessees. Applications are required to obtain or retain a benefit.
Therefore, if you apply for royalty relief, you must provide this information. We will protect information considered proprietary
under applicable law and under regulations at §203.63 and 30 CFR part 250.
(c) The Paperwork Reduction Act of 1995 requires us to inform you that we may not conduct or sponsor, and you are not
required to respond to, a collection of information unless it displays a currently valid OMB control number.
(d) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing
the burden, to the Information Collection Clearance Officer, Bureau of Safety and Environmental Enforcement, 45600 Woodland
Road, Sterling, VA 20166.

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[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36148, June 6, 2016]

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§203.83   What is in an administrative information report?
This report identifies the field or lease for which royalty relief is requested and must contain the following items:
(a) The field or lease name;
(b) The serial number of leases we have assigned to the field, names of the lease title holders of record, the lease
operators, and whether any lease is part of a unit;
(c) Well number, API number, location, and status of each well that has been drilled on the field or lease or project (not
required for non-oil and gas leases);
(d) The location of any new wells proposed under the terms of the application (not required for non-oil and gas leases);
(e) A description of field or lease history;
(f) Full information as to whether you will pay royalties or a share of production to anyone other than the United States, the
amount you will pay, and how much you will reduce this payment if we grant relief;
(g) The type of royalty relief you are requesting;
(h) Confirmation that BOEM approved a DOCD or supplemental DOCD (Deep Water expansion project applications only);
and
(i) A narrative description of the development activities associated with the proposed capital investments and an
explanation of proposed timing of the activities and the effect on production (Deep Water applications only).
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§203.84   What is in a net revenue and relief justification report?
This report presents cash flow data for 12 qualifying months, using the format specified in the “Guidelines for the
Application, Review, Approval, and Administration of Royalty Relief for End-of-Life Leases”, U.S. Department of the Interior,
BSEE. Qualifying months for an oil and gas lease are the most recent 12 months out of the last 15 months that you produced at
least 100 BOE per day on average. Qualifying months for other than oil and gas leases are the most recent 12 of the last 15
months having some production.
(a) The cash flow table you submit must include historical data for:
(1) Lease production subject to royalty;
(2) Total revenues;
(3) Royalty payments out of production;
(4) Total allowable costs; and
(5) Transportation and processing costs.
(b) Do not include in your cash flow table the non-allowable costs listed at 30 CFR 1220.013 or:
(1) OCS rental payments on the lease(s) in the application;
(2) Damages and losses;
(3) Taxes;
(4) Any costs associated with exploratory activities;
(5) Civil or criminal fines or penalties;
(6) Fees for your royalty relief application; and
(7) Costs associated with existing obligations (e.g., royalty overrides or other forms of payment for acquiring the lease,
depreciation on previously acquired equipment or facilities).
(c) We may, in reviewing and evaluating your application, disallow costs when you have not shown they are necessary to
operate the lease, or if they are inconsistent with end-of-life operations.
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§203.85   What is in an economic viability and relief justification report?

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This report should show that your project appears economic without royalties and sunk costs using the RSVP model we
provide. The format of the report and the assumptions and parameters we specify are found in the “Guidelines for the
Application, Review, Approval and Administration of the Deep Water Royalty Relief Program,” U.S. Department of the Interior,
BSEE. Clearly justify each parameter you set in every scenario you specify in the RSVP. You may provide supplemental
information, including your own model and results. The economic viability and relief justification report must contain the
following items for an oil and gas lease.
(a) Economic assumptions we provide which include:
(1) Starting oil and gas prices;
(2) Real price growth;
(3) Real cost growth or decline rate, if any;
(4) Base year;
(5) Range of discount rates; and
(6) Tax rate (for use in determining after-tax sunk costs).
(b) Analysis of projected cash flow (from the date of the application using annual totals and constant dollar values) which
shows:
(1) Oil and gas production;
(2) Total revenues;
(3) Capital expenditures;
(4) Operating costs;
(5) Transportation costs; and
(6) Before-tax net cash flow without royalties, overrides, sunk costs, and ineligible costs.
(c) Discounted values which include:
(1) Discount rate used (selected from within the range we specify).
(2) Before-tax net present value without royalties, overrides, sunk costs, and ineligible costs.
(d) Demonstrations that:
(1) All costs, gross production, and scheduling are consistent with the data in the G&G, engineering, production, and cost
reports (§§203.86 through 203.89) and
(2) The development and production scenarios provided in the various reports are consistent with each other and with the
proposed development system. You can use up to three scenarios (conservative, most likely, and optimistic), but you must link
each to a specific range on the distribution of resources from the RSVP Resource Module.
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§203.86   What is in a G&G report?
This report supports the reserve and resource estimates used in the economic evaluation and must contain each of the
following elements.
(a) Seismic data which includes:
(1) Non-interpreted 2D/3D survey lines reflecting any available state-of-the-art processing technique in a format readable
by BSEE and specified by the deep water royalty relief guidelines;
(2) Interpreted 2D/3D seismic survey lines reflecting any available state-of-the-art processing technique identifying all
known and prospective pay horizons, wells, and fault cuts;
(3) Digital velocity surveys in the format of the GOM region's letter to lessees of 10/1/90;
(4) Plat map of “shot points;” and
(5) “Time slices” of potential horizons.
(b) Well data which includes:
(1) Hard copies of all well logs in which—
(i) The 1-inch electric log shows pay zones and pay counts and lithologic and paleo correlation markers at least every 500feet,
(ii) The 1-inch type log shows missing sections from other logs where faulting occurs,

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(iii) The 5-inch electric log shows pay zones and pay counts and labeled points used in establishing resistivity of the
formation, 100 percent water saturated (Ro) and the resistivity of the undisturbed formation (Rt), and
(iv) The 5-inch porosity logs show pay zones and pay counts and labeled points used in establishing reservoir porosity or
labeled points showing values used in calculating reservoir porosity such as bulk density or transit time;
(2) Digital copies of all well logs spudded before December 1, 1995;
(3) Core data, if available;
(4) Well correlation sections;
(5) Pressure data;
(6) Production test results;
(7) Pressure-volume-temperature analysis, if available; and
(8) A table listing the wells and completions, and indicating which sands and fault blocks will be targeted for completion or
recompletion.
(c) Map interpretations which includes for each reservoir in the field:
(1) Structure maps consisting of top and base of sand maps showing well and seismic shot point locations;
(2) Isopach maps for net sand, net oil, net gas, all with well locations;
(3) Maps indicating well surface and bottom hole locations, location of development facilities, and shot points; and
(4) An explanation for excluding the reservoirs you are not planning to develop.
(d) Reservoir-specific data which includes:
(1) Probability of reservoir occurrence with hydrocarbons;
(2) Probability the hydrocarbon in the reservoir is all oil and the probability it is all gas;
(3) Distributions or point estimates (accompanied by explanations of why distributions less appropriately reflect the
uncertainty) for the parameters used to estimate reservoir size, i.e., acres and net thickness;
(4) Most likely values for porosity, salt water saturation, volume factor for oil formation, and volume factor for gas formation;
(5) Distributions or point estimates (accompanied by explanations of why distributions less appropriately reflect the
uncertainty) for recovery efficiency (in percent) and oil or gas recovery (in stock-tank-barrels per acre-foot or in thousands of
cubic feet per acre foot);
(6) A gas/oil ratio distribution or point estimate (accompanied by explanations of why distributions less appropriately reflect
the uncertainty) for each reservoir;
(7) A yield distribution or point estimate (accompanied by explanations of why distributions less appropriately reflect the
uncertainty) for each gas reservoir; and
(8) Reserve or resource distribution by reservoir.
(e) Aggregated reserve and resource data which includes:
(1) The aggregated distributions for reserves and resources (in BOE) and oil fraction for your field computed by the
resource module of our RSVP model;
(2) A description of anticipated hydrocarbon quality (i.e., specific gravity); and
(3) The ranges within the aggregated distribution for reserves and resources that define the development and production
scenarios presented in the engineering and production reports. Typically there will be three ranges specified by two positive
reserve and resource points on the aggregated distribution. The range at the low end of the distribution will be associated with
the conservative development and production scenario; the middle range will be related to the most likely development and
production scenario; and, the high end range will be consistent with the optimistic development and production scenario.
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§203.87   What is in an engineering report?
This report defines the development plan and capital requirements for the economic evaluation and must contain the
following elements.
(a) A description of the development concept (e.g., tension leg platform, fixed platform, floater type, subsea tieback, etc.)
which includes:
(1) Its size along with basic design specifications and drawings; and
(2) The construction schedule.

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(b) An identification of planned wells which includes:
(1) The number;
(2) The type (platform, subsea, vertical, deviated, horizontal);
(3) The well depth;
(4) The drilling schedule;
(5) The kind of completion (single, dual, horizontal, etc.); and
(6) The completion schedule.
(c) A description of the production system equipment which includes:
(1) The production capacity for oil and gas and a description of limiting component(s);
(2) Any unusual problems (low gravity, paraffin, etc.);
(3) All subsea structures;
(4) All flowlines; and
(5) Schedule for installing the production system.
(d) A discussion of any plans for multi-phase development which includes the conceptual basis for developing in phases
and goals or milestones required for starting later phases.
(e) A set of development scenarios consisting of activity timing and scale associated with each of up to three production
profiles (conservative, most likely, optimistic) provided in the production report for your field (§203.88). Each development
scenario and production profile must denote the likely events should the field size turn out to be within a range represented by
one of the three segments of the field size distribution. If you send in fewer than three scenarios, you must explain why fewer
scenarios are more efficient across the whole field size distribution.
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§203.88   What is in a production report?
This report supports your development and production timing and product quality expectations and must contain the
following elements.
(a) Production profiles by well completion and field that specify the actual and projected production by year for each of the
following products: oil, condensate, gas, and associated gas. The production from each profile must be consistent with a
specific level of reserves and resources on the aggregated distribution of field size.
(b) Production drive mechanisms for each reservoir.
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§203.89   What is in a cost report?
This report lists all actual and projected costs for your field, must explain and document the source of each cost estimate,
and must identify the following elements.
(a) Sunk costs. Report sunk costs in dollars not adjusted for inflation and only if you have documentation.
(b) Appraisal, delineation and development costs. Base them on actual spending, current authorization for expenditure,
engineering estimates, or analogous projects. These costs cover:
(1) Platform well drilling and average depth;
(2) Platform well completion;
(3) Subsea well drilling and average depth;
(4) Subsea well completion;
(5) Production system (platform); and
(6) Flowline fabrication and installation.
(c) Production costs based on historical costs, engineering estimates, or analogous projects. These costs cover:
(1) Operation;
(2) Equipment; and

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(3) Existing royalty overrides (we will not use the royalty overrides in evaluations).
(d) Transportation costs, based on historical costs, engineering estimates, or analogous projects. These costs cover:
(1) Oil or gas tariffs from pipeline or tankerage;
(2) Trunkline and tieback lines; and
(3) Gas plant processing for natural gas liquids.
(e) Abandonment costs, based on historical costs, engineering estimates, or analogous projects. You should provide the
costs to plug and abandon only wells and to remove only production systems for which you have not incurred costs as of the
time of application submission. You should also include a point estimate or distribution of prospective salvage value for all
potentially reusable facilities and materials, along with the source and an explanation of the figures provided.
(f) A set of cost estimates consistent with each one of up to three field-development scenarios and production profiles
(conservative, most likely, optimistic). You should express costs in constant real dollar terms for the base year. You may also
express the uncertainty of each cost estimate with a minimum and maximum percentage of the base value.
(g) A spending schedule. You should provide costs for each year (in real dollars) for each category in paragraphs (a)
through (f) of this section.
(h) A summary of other costs which are ineligible for evaluating your need for relief. These costs cover:
(1) Expenses before first discovery on the field;
(2) Cash bonuses;
(3) Fees for royalty relief applications;
(4) Lease rentals, royalties, and payments of net profit share and net revenue share;
(5) Legal expenses;
(6) Damages and losses;
(7) Taxes;
(8) Interest or finance charges, including those embedded in equipment leases;
(9) Fines or penalties; and
(10) Money spent on previously existing obligations (e.g., royalty overrides or other forms of payment for acquiring a
financial position in a lease, expenditures for plugging wells and removing and abandoning facilities that existed on the
application submission date).
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§203.90   What is in a fabricator's confirmation report?
This report shows you have committed in a timely way to the approved system for production. This report must include the
following (or its equivalent for unconventionally acquired systems):
(a) A copy of the contract(s) under which the fabrication yard is building the approved system for you;
(b) A letter from the contractor building the system to the BSEE Regional Director for your region certifying when
construction started on your system; and
(c) Evidence of an appropriate down payment or equal action that you've started acquiring the approved system.
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§203.91   What is in a post-production development report?
For each cost category in the deep water cost report, you must compare actual costs up to the date when production starts
to your planned pre-production costs. If your application included more than one development scenario, you need to compare
actual costs with those in your scenario of most likely development. Also, you must have this report certified by an independent
CPA according to §203.81(c).
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Subpart C—Federal and Indian Oil [Reserved]
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Subpart D—Federal and Indian Gas [Reserved]
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Subpart E—Solid Minerals, General [Reserved]
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Subpart F [Reserved]
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Subpart G—Other Solid Minerals [Reserved]
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Subpart H—Geothermal Resources [Reserved]
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Subpart I—OCS Sulfur [Reserved]
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