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eCFR :: 30 CFR Part 203 -- Relief or Reduction in Royalty Rates
This content is from the eCFR and is authoritative but unofficial.
Displaying title 30, up to date as of 6/03/2024. Title 30 was last amended 5/31/2024.
Title 30 —Mineral Resources
Chapter II —Bureau of Safety and Environmental Enforcement, Department of the Interior
Subchapter A —Minerals Revenue Management
ENHANCED CONTENT - TABLE OF CONTENTS
Part 203 Relief or Reduction in Royalty Rates
https://www.ecfr.gov/current/title-30/chapter-II/subchapter-A/part-203
203.0 – 203.91
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Subpart A
§ 203.0
§ 203.1
§ 203.2
§ 203.3
§ 203.4
§ 203.5
Subpart B
eCFR :: 30 CFR Part 203 -- Relief or Reduction in Royalty Rates
General Provisions
203.0 – 203.5
What definitions apply to this part?
What is BSEE's authority to grant royalty relief?
How can I obtain royalty relief?
Do I have to pay a fee to request royalty relief?
How do the provisions in this part apply to different types of leases and projects?
What is BSEE's authority to collect information?
OCS Oil, Gas, and Sulfur General
203.30 – 203.91
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Royalty Relief for Drilling Ultra-Deep Wells on Leases Not Subject to Deep Water Royalty 203.30 – 203.36
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 ultradeep 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 203.40 – 203.49
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 ultradeep 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
203.50 – 203.56
§ 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?
Royalty Relief for Pre-Act Deep Water Leases and for Development and Expansion
203.60 – 203.80
Projects
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eCFR :: 30 CFR Part 203 -- Relief or Reduction in Royalty Rates
§ 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 – 203.91
§ 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]
PART 203—RELIEF OR REDUCTION IN ROYALTY RATES
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.
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Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.
Subpart A—General Provisions
§ 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
(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 royalty-suspension
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:
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(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
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 lease-development
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.
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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
(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
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(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 bottom-hole
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.
§ 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.
(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);
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(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 ultradeep 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.
§ 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 production (i.e., End-oflife lease),
Would abandon otherwise
potentially recoverable
resources but seek to increase
production by operating beyond
the point at which the lease is
economic under the existing
royalty rate,
A reduced royalty rate on current
monthly production and a higher
royalty rate on additional monthly
production (see §§ 203.50 through
203.56).
(b) Located in a designated
GOM deep water area (i.e., 200
meters or greater) and
acquired in a lease sale held
before November 28, 1995, or
after November 28, 2000,
Propose an expansion project
and can demonstrate your
project is uneconomic without
royalty relief,
A royalty suspension for a minimum
production volume plus any
additional production large enough
to make the project economic (see
§§ 203.60 through 203.79).
(c) Located in a designated
GOM deep water area and
acquired in a lease sale held
before November 28, 1995
(Pre-Act lease),
Are on a field from which no
current pre-Act lease produced
(other than test production)
before November 28, 1995,
(Authorized field,)
A royalty suspension for a minimum
production volume plus any
additional volume needed to make
the field economic (see §§ 203.60
through 203.79).
(d) Located in a designated
GOM deep water area and
acquired in a lease sale held
after November 28, 2000,
Propose a development project
and can demonstrate that the
suspension volume, if any, for
your lease is not enough to
make development economic,
A royalty suspension for a minimum
production volume plus any
additional volume needed to make
your project economic (see §§
203.60 through 203.79).
(e) Where royalty relief would
recover significant additional
resources or, offshore Alaska
or in certain areas of the GOM,
would enable development,
Are not eligible to apply for endof-life or deep water royalty
relief, but show us you meet
certain eligibility conditions,
A royalty modification in size,
duration, or form that makes your
lease or project economic (see §
203.80).
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If you have a lease . . .
And if you . . .
Then we may grant you . . .
(f) Located in a designated
GOM shallow water area and
acquired in a lease sale held
before January 1, 2001, or after
January 1, 2004, or have
exercised an option to
substitute for royalty relief in
your lease terms,
Drill a deep well on a lease that
is not eligible for deep water
royalty relief and you have not
previously produced oil or gas
from a deep well or an ultra-deep
well,
A royalty suspension for a volume of
gas produced from successful deep
and ultra-deep wells, or, for certain
unsuccessful deep and ultra-deep
wells, a smaller royalty suspension
for a volume of gas or oil produced
by all wells on your lease (see §§
203.40 through 203.49).
(g) Located in a designated
GOM shallow water area,
Drill and produce gas from an
ultra-deep well on a lease that is
not eligible for deep water
royalty relief and you have not
previously produced oil or gas
from an ultra-deep well,
A royalty suspension for a volume of
gas produced from successful ultradeep and deep wells on your lease
(see §§ 203.30 through 203.36).
(h) Located in planning areas
offshore Alaska,
Propose an expansion project or
propose a development project
and can demonstrate that the
project is uneconomic without
relief or that the suspension
volume, if any, for your lease is
not enough to make
development economic,
A royalty suspension for a minimum
production volume plus any
additional volume needed to make
your project economic (see §§
203.60, 203.62, 203.67 through
203.70, 203.73, and 203.76 through
203.79).
§ 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]
§ 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.
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Deep water
Endof-life
lease
Expansion
project
Preact
lease
Development
project
X
X
X
(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)
X
X
X
(4) G&G report
X
X
X
(5) Engineering report
X
X
X
(6) Production report
X
X
X
(7) Deep water cost report
X
X
X
Information elements
(1) Administrative information report
X
(2) Net revenue and relief justification report
(prescribed format)
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
Endof-life
lease
Expansion
project
Preact
lease
Development
project
(1) Fabricator's confirmation report
X
X
X
(2) Post-production development report approved
by an independent certified public accountant
(CPA) * * *
X
X
X
Confirmation elements
(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
Approval conditions
End-oflife
lease
(1) At least 12 of the last 15 months have the
required level of production
X
(2) Already producing
X
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Deep water
Approval conditions
End-oflife
lease
(3) A producible well into a reservoir that has
not produced before
(4) Royalties for qualifying months exceed 75
percent of net revenue (NR)
Expansion
Preact
lease
Development
project
X
X
X
X
X
X
X
(5) Substantial investment on a pre-Act lease
(e.g., platform, subsea template)
(6) Determined to be economic only with relief
(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
Redetermination conditions
(1) After 12 months under current rate, criteria
same as for approval
End-oflife
lease
Expansion
project
Preact
lease
Development
project
X
X
X
X
(2) For material change in geologic data, prices,
costs, or available technology
(e) The following table indicates by an X, and §§ 203.53 and 203.69 describe, the characteristics of approved royalty relief.
Deep water
Relief rate and volume, subject to certain
conditions
Endof-life
lease
(1) One-half pre-application effective lease rate on
the qualifying amount, 1.5 times pre-application
effective lease rate on additional production up to
twice the qualifying amount, and the preapplication effective lease rate for any larger
volumes
X
(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
production
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Expansion
project
Preact
lease
Development
project
X
X
X
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Deep water
Relief rate and volume, subject to certain
conditions
Endof-life
lease
Expansion
project
Preact
lease
(4) Suspension volume is at least 17.5, 52.5 or
87.5 million barrels of oil equivalent (MMBOE)
Development
project
X
(5) Suspension volume is at least the minimum
set in the Notice of Sale, the lease, or the
regulations
X
(6) Amount needed to become economic
X
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
Endof-life
lease
Expansion
project
Preact
lease
(2) Average NYMEX price for last calendar year
exceeds $28/bbl or $3.50/mcf, escalated by the
gross domestic product (GDP) deflator since
1994
X
X
(3) Average prices for designated periods
exceed levels we specify in the Notice of Sale or
the lease
X
Full royalty resumes when
(1) Average NYMEX price for last 12 months is
at least 25 percent above the average for the
qualifying months.
Development
project
X
X
(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
Relief withdrawn or reduced
End-oflife
lease
(1) If recipient requests
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
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Expansion
project
Preact
lease
Development
project
X
X
X
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Deep water
End-oflife
lease
Expansion
project
Preact
lease
Development
project
(4) Recipient does not submit post-production report
that compares expected to actual costs
X
X
X
(5) Recipient changes development system
X
X
X
(6) Recipient excessively delays starting fabrication
X
X
X
(7) Recipient spends less than 80 percent of proposed
pre-production costs prior to start of production
X
X
X
(8) Amount of relief volume is produced
X
X
X
Relief withdrawn or reduced
§ 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]
Subpart B—OCS Oil, Gas, and Sulfur General
Royalty Relief for Drilling Ultra-Deep Wells on Leases Not Subject to Deep Water Royalty Relief
§ 203.30 Which leases are eligible for royalty relief as a result of drilling a phase 2 or phase 3 ultra-deep well?
Your lease may receive a royalty suspension volume (RSV) under §§ 203.31 through 203.36 if the lease meets all the requirements of
this section.
(a) The lease is located in the GOM wholly west of 87 degrees, 30 minutes West longitude in water depths entirely less than
400 meters deep.
(b) The lease has not produced gas or oil from a deep well or an ultra-deep well, 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:
Then your lease earns an RSV on this volume of
gas production:
(1) An original well,
35 BCF.
(2) A sidetrack with a sidetrack measured
depth of at least 20,000 feet,
35 BCF.
(3) An ultra-deep short sidetrack that is a
phase 2 ultra-deep well,
4 BCF plus 600 MCF times
sidetrack measured depth (rounded to the nearest
100 feet) but no more than 25 BCF.
(4) An ultra-deep short sidetrack that is a
phase 3 ultra-deep well,
0 BCF.
(b)
(1) This paragraph applies if your lease:
(i)
Has produced gas or oil from a deep well with a perforated interval the top of which is less than 18,000 feet TVD
SS;
(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 ultradeep well that is . . .
Then your lease earns an RSV on this volume of
gas production:
(i) An original well or a sidetrack with a
sidetrack measured depth of at least
20,000 feet TVD SS,
10 BCF.
(ii) An ultra-deep short sidetrack,
4 BCF plus 600 MCF times sidetrack measured
depth (rounded to the nearest 100 feet) but no
more than 10 BCF.
(c) 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.
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(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 ultradeep 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 ultradeep 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
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(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 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.
§ 203.32 What other requirements or restrictions apply to royalty relief for a qualified phase 2 or phase 3 ultradeep 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.
§ 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.
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(b) This paragraph applies to any lease with a qualified phase 2 or phase 3 ultra-deep well that is not within a BSEE-approved
unit. Subject to the price conditions of § 203.36, you must apply the RSV prescribed in § 203.31 as required under the
following paragraphs (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
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 non-unitized portion of lease A that earns lease A an RSV of 35 BCF under § 203.31, one
qualified deep well on the unitized portion of lease A (drilled after the ultra-deep well on the non-unitized
portion of that lease) and a qualified phase 2 ultra-deep well on lease B that earns lease B a 35 BCF RSV
under § 203.31. The participating area percentages allocate 40 percent of production from both of the unit
qualified wells to lease A and 60 percent to lease B. If the non-unitized qualified phase 2 ultra-deep well on
lease A produces 12 BCF, and the unitized qualified well on lease A produces 18 BCF, and the qualified well
on lease B produces 37 BCF, then the production volume from and allocated to lease A to which the lease A
RSV applies is 34 BCF [12 + (18 + 37)(0.40)]. The production volume allocated to lease B to which the lease
B RSV applies is 33 BCF [(18 + 37)(0.60)]. 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.
§ 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:
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(1) March 26, 2003, on a lease that is located entirely or partly in water less than 200 meters deep; or
(2) May 18, 2007, on a lease that is located entirely in water more than 200 meters deep.
§ 203.35 What administrative steps must I take to use the RSV earned by a qualified phase 2 or phase 3 ultradeep 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.
(3) The delay in beginning production is for reasons beyond your control, such as adverse weather and accidents which
BSEE deems were unavoidable.
§ 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,
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.
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A price threshold
in year 2007
dollars of . . .
(2) $4.55 per
MMBtu,
Applies to . . .
(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.
(3) $4.08 per
MMBtu,
(i) The first 20 BCF of RSV earned by a well that is located on a nonconverted lease issued in OCS Lease Sale 178.
(4) $5.83 per
MMBtu,
(i) The first 20 BCF of RSV earned by a well that is located on a nonconverted 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.
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
Example 2:
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;
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(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 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.
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?
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;
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(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.
§ 203.41 If I have a qualified deep well or a qualified phase 1 ultra-deep well, what royalty relief would my lease
earn?
(a) To qualify for a suspension volume under paragraphs (b) or (c) of this section, your lease must meet the requirements in §
203.40 and the requirements in the following table.
If your lease has not . . .
And if it later . . .
Then your lease . . .
(1) produced gas or oil from any
deep well or ultra-deep well,
Has a qualified deep well or qualified
phase 1 ultra-deep well,
earns an RSV
specified in
paragraph (b) of this
section.
(2) produced gas or oil from a
well with a perforated interval
whose top is 18,000 feet TVD SS
or deeper,
Has a qualified deep well with a
perforated interval whose top is 18,000
feet TVD SS or deeper or a qualified
phase 1 ultra-deep well,
earns an RSV
specified in
paragraph (c) of this
section.
(b) If your lease meets the requirements in paragraph (a)(1) of this section, it earns the RSV prescribed in the following table:
If you have a qualified deep well or a qualified
phase 1 ultra-deep well that is:
Then your lease earns an RSV on this volume of
gas production:
(1) An original well with a perforated interval
the top of which is from 15,000 to less than
18,000 feet TVD SS,
15 BCF.
(2) A sidetrack with a perforated interval the
top of which is from 15,000 to less than
18,000 feet TVD SS,
4 BCF plus 600 MCF times sidetrack measured
depth (rounded to the nearest 100 feet) but no
more than 15 BCF.
(3) An original well with a perforated interval
the top of which is at least 18,000 feet TVD
SS,
25 BCF.
(4) A sidetrack with a perforated interval the
top of which is at least 18,000 feet TVD SS,
4 BCF plus 600 MCF times sidetrack measured
depth (rounded to the nearest 100 feet) but no
more than 25 BCF.
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(c) If your lease meets the requirements in paragraph (a)(2) of this section, it earns the RSV prescribed in the following table.
The RSV specified in this paragraph is in addition to any RSV your lease already may have earned from a qualified deep well
with a perforated interval whose top is from 15,000 feet to less than 18,000 feet TVD SS.
If you have a qualified deep well or a qualified
phase 1 ultra-deep well that is . . .
Then you earn an RSV on this amount of gas
production:
(1) An original well or a sidetrack with a
perforated interval the top of which is from
15,000 to less than 18,000 feet TVD SS,
0 BCF.
(2) An original well with a perforated interval the
top of which is 18,000 feet TVD SS or deeper,
10 BCF.
(3) A sidetrack with a perforated interval the top
of which is 18,000 feet TVD SS or deeper,
4 BCF plus 600 MCF times sidetrack
measured depth (rounded to the nearest 100
feet) but no more than 10 BCF.
(d) 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
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(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 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.
§ 203.42 What conditions and limitations apply to royalty relief for deep wells and phase 1 ultra-deep wells?
The conditions and limitations in the following table apply to royalty relief under § 203.41.
If . . .
Then . . .
(a) Your lease has produced gas or oil from a well
with a perforated interval the top of which is 18,000
feet TVD SS or deeper,
your lease cannot earn an RSV under § 203.41 as a
result of drilling any subsequent deep wells or phase
1 ultra-deep wells.
(b) You determine RSV under § 203.41 for the first
qualified deep well or qualified phase 1 ultra-deep
well on your lease (whether an original well or a
sidetrack) because you drilled and produced it
within the time intervals set forth in the definitions
for qualified 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.
(c) A qualified deep well or qualified phase 1 ultradeep well on your lease is within a unitized portion
of your lease,
the RSV earned by that well under § 203.41 applies
only to production from qualified wells on or
allocated to your lease and not to other leases
within the unit.
(d) Your qualified deep well or qualified phase 1
ultra-deep well is a directional well (either an
original well or a sidetrack) drilled across a lease
line,
the lease with the perforated interval that initially
produces earns the RSV. However, if the perforated
interval crosses a lease line, the lease where the
surface of the well is located earns the RSV.
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If . . .
Then . . .
(e) You earn an RSV under § 203.41,
that RSV is in addition to any RSS for your lease
under § 203.45 that results from a different
wellbore.
(f) Your lease earns an RSV under § 203.41 and
later produces from a well that is not a qualified
well,
the RSV is not forfeited or terminated, but you may
not apply the RSV under § 203.41 to production
from the non-qualified well.
(g) You qualify for an RSV under paragraphs (b) or
(c) of § 203.41,
you still owe minimum royalties or rentals in
accordance with your lease terms.
(h) You transfer your lease,
unused RSVs transfer to a successor lessee and
expire with the lease.
Example to paragraph (b):
If your first qualified deep well is a sidetrack with a perforated interval whose top is 16,000 feet
TVD SS and earns an RSV of 12.5 BCF, and you later drill a qualified original deep well to 17,000 feet TVD SS, the RSV for your
lease remains at 12.5 BCF and does not increase to 15 BCF. However, under paragraph (c) of § 203.41, if you subsequently
drill a qualified deep well to a depth of 18,000 feet or greater TVD SS, you may earn an additional RSV.
§ 203.43 To which production do I apply the RSV earned from qualified deep wells or qualified phase 1 ultradeep 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
(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
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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 non-unitized portion of lease A, one qualified 18,500-foot TVD SS deep well on the unitized
portion of lease A, and a qualified 19,400-foot TVD SS deep well on lease B. The participating area percentages
allocate 32 percent of production from both of the unit qualified deep wells to lease A and 68 percent to lease B.
If the non-unitized qualified deep well on lease A produces 12 BCF and the unitized qualified deep well on lease
A produces 15 BCF, and the qualified deep well on lease B produces 10 BCF, then the production volume from
and allocated to lease A to which the lease an RSV applies is 20 BCF [12 + (15 + 10) * (0.32)]. The production
volume allocated to lease B to which the lease B RSV applies is 17 BCF [(15 + 10) * (0.68)].
(d) You must begin paying royalties when the cumulative production of gas from all qualified wells on your lease, or allocated to
your lease under paragraph (c) of this section, reaches the applicable RSV allowed under § 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;
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(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.
§ 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.
§ 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.
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 an ultra-deep well,
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Then your lease earns an RSS on
this volume of oil and gas
production as prescribed in this
section and § 203.46:—
5 BCFE.
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If you have a certified unsuccessful well that is:—
Then your lease earns an RSS on
this volume of oil and gas
production as prescribed in this
section and § 203.46:—
(2) A sidetrack (with a sidetrack measured depth of at least
10,000 feet) and your lease has not produced gas or oil from
a deep well or an ultra-deep well,
0.8 BCFE plus 120 MCFE times
sidetrack measured depth
(rounded to the nearest 100 feet)
but no more than 5 BCFE.
(3) An original well or a sidetrack (with a sidetrack measured
depth of at least 10,000 feet) and your lease has produced
gas or oil from a deep well with a perforated interval the top
of which is from 15,000 to less than 18,000 feet TVD SS,
2 BCFE.
(b) This paragraph applies to oil and gas volumes you report on the OGOR-A for your lease under 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.
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
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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.
§ 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.
§ 203.47 What administrative steps do I take to obtain and use the royalty suspension supplement?
(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
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(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.
§ 203.48 Do I keep royalty relief if prices rise significantly?
(a) You must pay royalties on all gas and oil production for which an RSV or an RSS otherwise would be allowed under §§
203.40 through 203.47 for any calendar year when the average daily closing NYMEX natural gas price exceeds the
applicable threshold price shown in the following table.
For a lease located in water
...
And issued . . .
The applicable threshold price is . . .
(1) Partly or entirely less
than 200 meters deep,
before
December 18,
2008,
$10.15 per MMBtu, adjusted annually after
calendar year 2007 for inflation.
(2) Partly or entirely less
than 200 meters deep,
after
December 18,
2008,
$4.55 per MMBtu, adjusted annually after
calendar year 2007 for inflation unless the lease
terms prescribe a different price threshold.
(3) Entirely more than 200
meters and entirely less
than 400 meters deep,
on any date,
$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.
§ 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
§ 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.
§ 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).
§ 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.
§ 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.
§ 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 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;
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(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.
§ 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.
§ 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.
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?
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).
§ 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.
§ 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;
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(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.
§ 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.
§ 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.
§ 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.
(c) We may ask to extend the review period for your application under the conditions in the following table.
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If . . .
Then we may . . .
(1) We need more records to audit sunk
costs,
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 reason, such as missing vital
information or inconsistent or
inconclusive supporting data,
Add another 30 days. We may add more than 30 days,
but only if you agree.
(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.
§ 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
And we do not decide within the time specified,
As long as
you
(a) An authorized
field,
You get the minimum suspension volumes specified in § 203.69,
Abide by §§
203.70 and
203.76.
(b) An expansion
project,
You get a royalty suspension for the first year of production,
Abide by §§
203.70 and
203.76.
(c) A development
project,
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,
Abide by §§
203.70 and
203.76.
§ 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.
§ 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.
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We will . . .
When determining . . .
(1) Include sunk costs,
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.
(2) Not include sunk costs,
Whether an authorized field, a development project, or an expansion
project can become economic with full relief (see § 203.67).
(3) Not include sunk costs,
How much suspension volume is necessary to make the field, a
development project, or an expansion project economic (see § 203.69(c)).
(4) Include sunk costs for
the project discovery well on
each lease,
Whether a development project or an expansion project needs relief to
become economic.
§ 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 . . .
A volume equal to the combined royalty
suspension volumes (or the volume
equivalent based on the data in your
approved application for other forms of
royalty suspension) with which BSEE issued
the leases participating in the application
that have or plan a well into a reservoir
identified in the application,
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Plus . . .
10 percent of the median of
the distribution of known
recoverable resources upon
which BSEE based approval
of your application from all
reservoirs included in the
project.
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The minimum royalty suspension volume
is . . .
For . . .
(2) Leases offshore
Alaska or other
deep water GOM
leases issued in
sales after
November 28, 2000,
Plus . . .
A volume equal to 10 percent of the median
of the distribution of known recoverable
resources upon which BSEE based approval
of your application from all reservoirs
included in the project.
(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 waterdepth 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.
§ 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
When due to BSEE
Due date extensions
(a) Fabricator's
confirmation
report.
Within 18 months after approval of
relief.
BSEE Director may grant you an extension
under § 203.79(c) for up to 6 months.
(b) Post-production
report.
Within 120 days after the start of
production that is subject to the
approved royalty suspension volume.
With acceptable justification from you, the
BSEE Regional Director for your region may
extend the due date up to 30 days.
§ 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:
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If . . .
Then . . .
And . . .
(1) We assign an
eligible lease to
your authorized
field after we
approve relief,
We will not change your
authorized field's royalty
suspension volume determined
under § 203.69,
Production from the assigned eligible
lease(s) counts toward 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.
(2) We assign a
pre-Act or postNovember 2000
deep water
lease to your
field after we
approve your
application,
We will not change your field's
royalty suspension volume,
The assigned lease(s) may share in any
remaining royalty relief by filing the shortform 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.
(3) We assign
another lease
that you operate
to your field
while we are
evaluating your
application,
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.
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If . . .
Then . . .
And . . .
(4) We assign
another
operator's lease
to your field
while we are
evaluating your
application,
We will change your field's
minimum suspension volume
provided the assigned lease joins
the application and is entitled to a
larger minimum suspension
volume,
(i) You both toll the time period for
evaluation until both of you modify your
application to be consistent with the new
field;
(ii) We have an additional 60 days to
review the new 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.
(5) We reassign
a well on a preAct, eligible, or
royalty
suspension
lease from field
A to field B,
The past production from the well
counts toward the royalty
suspension volume that we grant
under § 203.69 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.
§ 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.
§ 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.
§ 203.74 When will BSEE reconsider its determination?
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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.
§ 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.
§ 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
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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.
§ 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.
§ 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 . . .
The base price threshold is . . .
(1) Pre-Act leases in the GOM,
set by statute.
(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,
indicated in your original lease agreement
or, if none, those in the Notice of Sale
under which your lease was issued.
(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 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:
(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
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(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.
§ 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.
§ 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
§ 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
End-oflife
lease
Deep water
Expansion
project
Pre-act
lease
Development
project
X
X
X
(3) Economic viability & relief justification
report (RSVP model inputs justified by
other required reports)
X
X
X
(4) G&G report
X
X
X
(5) Engineering report
X
X
X
(6) Production report
X
X
X
(7) Deep water cost report
X
X
X
(8) Fabricator's confirmation report
X
X
X
(9) Post-production development report
X
X
X
(1) Administrative information Report
X
(2) Net revenue & relief justification
report
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.
§ 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.
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(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.
[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36148, June 6, 2016]
§ 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).
§ 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;
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(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.
§ 203.85 What is in an economic viability and relief justification report?
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:
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(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.
§ 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 500-feet,
(ii) The 1-inch type log shows missing sections from other logs where faulting occurs,
(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:
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(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.
§ 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.
(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.);
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(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.
§ 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.
§ 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
(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
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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).
§ 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.
§ 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]
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]
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| File Type | application/pdf |
| File Title | eCFR :: 30 CFR Part 203 -- Relief or Reduction in Royalty Rates |
| File Modified | 2024-06-05 |
| File Created | 2024-06-05 |