[Federal Register Volume 69, Number 16 (Monday, January 26, 2004)]
[Rules and Regulations]
[Pages 3492-3514]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-1299]


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DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 203

RIN 1010-AD01


Oil and Gas and Sulphur Operations in the Outer Continental 
Shelf--Relief or Reduction in Royalty Rates--Deep Gas Provisions

AGENCY: Minerals Management Service (MMS), Interior.

ACTION: Final rule.

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SUMMARY: This rule provides temporary incentives in the form of royalty 
suspension volumes for producing gas from certain deep wells (at least 
15,000 feet below sea level). The rule also provides a royalty 
suspension supplement for drilling certain unsuccessful deep wells. The 
rule also provides price thresholds that may result in discontinuation 
of the royalty relief.

EFFECTIVE DATE: This rule is effective March 1, 2004.

FOR FURTHER INFORMATION CONTACT: Marshall Rose, Chief, Economics 
Division, Minerals Management Service, at (703) 787-1536. E-mail: 
[email protected]. Address: Minerals Management Service, MS 4050, 
381 Elden Street, Herndon, Virginia 20170.

SUPPLEMENTARY INFORMATION: Title 30 CFR part 203 regulates the 
reduction of oil and gas royalty under 43 U.S.C. 1337(a)(3). Under 
section 1337(a)(3)(B), MMS may reduce, modify, or eliminate royalties 
on certain producing or non-producing leases or categories of leases to 
promote development or increased production or to encourage production 
of marginal resources, in the Gulf of Mexico (GOM) west of 87 degrees, 
30 minutes West longitude.
    Objective: The objective of the deep gas incentive provided in this 
rule is to increase the volume of natural gas production from the Outer 
Continental Shelf (OCS) by encouraging lessees to quickly explore for 
and develop deep-well gas reserves. That activity will provide near-
term supplies to help alleviate potential natural gas shortages and 
help moderate prices over the next decade.
    In the short-term, supply and demand for natural gas tend to be 
relatively inelastic, which can cause large fluctuations in price 
during periods of relative scarcity or abundance of supply. In recent 
years, higher prices during periods of tight supply have been evident, 
spiking at over $8 per million British thermal units (MMBtu) on the New 
York Mercantile Exchange (NYMEX) during the winter of 2000-2001. High 
and volatile natural gas prices contribute to a climate of uncertainty, 
thereby inhibiting continuous, sustained investment in deep gas 
development. High natural gas prices during periods of tight supply 
have hurt households, farmers, businesses, and negatively affected our 
economy as a whole. Without new sources of domestic natural gas, the 
United States (U.S.) will likely experience continued tightness of 
supply, price volatility, and increased reliance on imports from Canada 
and liquefied natural gas (LNG) from overseas.
    While our nation's natural gas resources are substantial, much of 
the remaining resources on available Federally regulated lands (i.e., 
those areas which remain open to leasing and exploration), will be 
increasingly costly to produce because of higher exploration and 
production costs and greater technical challenges of recovering gas 
from deep-water, deep formations, and harsh environments. Though 
significant potential natural gas finds may exist in the deep-water OCS 
and from areas in Alaska or onshore in the Rocky Mountain States, 
significant contribution from these areas is not expected until after 
2008.
    For new sources of gas supply in the near-term, the shallow waters 
of the GOM hold the greatest promise. MMS determined that one 
initiative to encourage rapid exploration and development of new 
natural gas reserves is to provide financial incentives to encourage 
new and earlier drilling of deep gas resources--approximately three 
miles and deeper--below existing platforms in the GOM. Natural gas 
prospects at this depth pose a technological challenge, but the gas can 
be accessed and transported using existing infrastructure in this 
mature oil- and gas-producing basin. Providing royalty relief can 
encourage timely and profitable deep gas production. Suspending some of 
the royalty payments due the Government on lease production can promote 
and accelerate new natural gas production by ensuring a viable rate of 
return to lessees for exploration and development of certain otherwise 
marginal deep gas prospects or by increasing industry's expected 
financial return from exploring and developing deep gas on their 
shallow water OCS leases relative to other (e.g., foreign) investments.
    The continued success of the Federal offshore oil and gas program 
is due, in part, to the judicious use of leasing, financial, and other 
incentives to promote continued industry interest and investment in new 
technologies for exploration and development in frontier areas of the 
OCS. The U.S. can benefit in many ways from increased domestic natural 
gas production. Exploration, development, and production of Federal 
natural gas resources by private firms yield significant economic 
benefits including payment of $2 to $4 billion in royalties annually to 
the Federal Treasury. The incentive in this rule is intended to provide 
significant social benefits by helping sustain domestic natural gas 
supplies and moderate energy costs to consumers, while minimizing costs 
to the Federal Treasury. The effects of this rule can help consumers by 
expanding the supply of natural gas from sources that might never have 
been discovered or accelerating production that may not have occurred 
until much later in the future.
    MMS estimates that this incentive could provide about 4.4 trillion 
cubic feet (TCF) of additional hydrocarbon production (of which 3.6 TCE 
is gas) over the next 16 years, which will help moderate prices and 
save consumers about $500 million in natural gas costs per year over 
the next decade. Although Federal royalty payments will be lower while 
any gas production is royalty-free, MMS expects that the increased 
production will eventually provide royalty revenue that would offset 
the lost revenue experienced during early years of the incentive 
program. MMS estimates that the rule could result in a present value 
loss in Federal royalty collections over 16 years of from $150 million 
to $220 million (depending on

[[Page 3493]]

price volatility) out of some $47 billion collected. Total Federal 
collections from leasing now run about $5 billion per year.

Background

    Natural gas, one of the most important fuel sources in the U.S. 
economy, supplies almost a quarter of the Nation's energy needs. 
Natural gas is a relatively reliable source of energy because a high 
proportion of domestic consumption is met by domestic production. In 
2002, the U.S. produced about 19 TCF of natural gas, which supplied 
about 84 percent of U.S. demand totaling about 23 TCF. Imports of 
natural gas (primarily from Canada) and a small amount of LNG from 
Algeria, Qatar, and Trinidad and Tobago, supplied the remaining 4 TCF 
(16 percent).
    Heating and electricity generation have traditionally been the 
predominant uses of natural gas, but demand for natural gas is 
projected to grow in all sectors of the economy, especially as a fuel 
source for electricity generation. Natural gas fuels about 20 percent 
of current electricity generation, but this percentage is expected to 
increase dramatically because an increasing number of our electric 
generating plants are switching to natural gas for power generation and 
planned future capacity is expected to rely primarily on natural gas. 
This will contribute to a dramatic increase in U.S. demand for natural 
gas in the next 10-20 years. The Energy Information Administration 
(EIA) of the Department of Energy projects that the U.S. demand for 
natural gas could increase by more than 50 percent in the next 20 
years, increasing from 22 TCF in 2003 to 35 TCF in 2025. Though LNG 
imports from overseas are expected to increase over time, helping to 
supply some of the demand growth, even optimistic estimates suggest 
that about 80 percent of the expected increase in consumption will need 
to be supplied from domestic sources.
    In 2002, the Federal OCS was the single largest source of oil and 
gas for the nation--larger than any State or foreign supplier. The 
majority of Federal production comes from the GOM. The OCS currently 
provides about 14 billion cubic feet (BCF) of natural gas per day 
(about 5 TCF annually) for U.S. consumers, supplying about 25 percent 
of domestic demand. The OCS is expected to remain a significant source 
for increased supply of natural gas to meet U.S. demand in the long 
term because it contains about one-third of the remaining undiscovered 
technically recoverable natural gas resources in the U.S. MMS projects 
that the GOM could contain 193 TCF of undiscovered natural gas, which 
represents about 53 percent of the total OCS estimate of undiscovered 
gas resources (362 TCF).
    Continued production of natural gas from the GOM OCS may be the key 
to a stable and secure natural gas future for the U.S., but there is 
concern about the ability of the OCS to maintain its current level of 
production over the coming decades. Total proven natural gas reserves 
on the GOM OCS have declined dramatically from nearly 46 TCF in 1986 to 
approximately 24 TCF in 1999. [Estimated Oil &Gas Reserves, Gulf of 
Mexico Dec. 31, 1999, OCS Report MMS 2002-007]. Recent gas discoveries 
in the mature producing areas of the GOM are smaller than previous 
reserves and are depleted more rapidly. The production rate per well 
has been declining. To maintain or increase the existing level of 
domestic natural gas supplies, the nation needs more well completions 
to offset these declines. Without dramatic change in exploration and 
development patterns, production from the GOM may not be able to meet 
the expected share of future natural gas supply needed from the OCS to 
meet growing demand. Energy producers now have to look in more remote 
locations, using innovative technologies, and the government needs to 
encourage identification and development of new sources.
    President Bush's National Energy Policy (NEP) provides a long-term 
energy strategy for securing America's energy future and addresses 
production of traditional energy sources, alternative and renewable 
sources, and energy conservation and efficiency. Natural gas is an 
important cornerstone of the NEP because it is relatively efficient and 
clean-burning, as it produces fewer emissions than other fossil fuels, 
and is an abundant domestic resource. As such, the NEP encourages the 
environmentally responsible development of natural gas to meet the 
Nation's near-term demand.
    The NEP recommended that the Secretary of the Interior consider 
economic incentives for offshore oil and gas development where 
warranted by specific circumstances. To encourage increased energy 
investment--a long-term process--industry needs certainty and 
stability, and incentives that are predictable and transparent. In 
particular, the NEP recommended that the Secretary of the Interior 
explore opportunities to provide royalty reductions for enhanced oil 
and gas recovery; for reduction of risk associated with production in 
frontier areas or deep gas formations; and for development of small 
fields that would otherwise be uneconomic. This deep gas rule 
implements one part of MMS's responsibilities under the NEP to promote 
environmentally sound production of our Nation's energy resources, 
using royalty suspensions to reduce financial risks associated with 
production of OCS deep gas formations.

Deep Shelf Gas

    Total GOM natural gas production has been fairly constant at about 
5 TCF per year for the last 20 years. Currently, about 75 percent of 
this production comes from reservoirs in shallow waters of the shelf. 
However, since 1996, production from the shelf has been declining at a 
precipitous 30 percent rate, from 4.8 TCF in 1997 to about 3.4 TCF in 
2002. During this time, increasing production from deep-water areas has 
kept OCS production stable. As shelf production continues to decline in 
both shallow and deep water, there could be a significant drop in OCS 
production of natural gas over the next 5-10 years unless new reserves 
can be found and brought on line quickly. To maintain GOM production 
levels near 5 TCF, or to increase aggregate production, a high level of 
exploration activity in both shallow and deep-water areas of the GOM 
will be needed.
    The shallow waters of the GOM have been actively explored and any 
natural gas remaining in shallow-depth reservoirs, i.e., less than 
15,000 feet total vertical depth subsea (TVD SS) is expected to be 
found in a large number of smaller, isolated reservoirs. Many 
marginally economic wells will be required to exploit those resources. 
In contrast, relatively few wells, only about 2,100 (5 percent of 
total) have been drilled to deep depths on the shelf, including 64 in 
2002. The potential for large new reservoirs with high production rates 
is greater at deep depths than in more mature, shallower areas.
    Recent deep gas discoveries on the OCS have shown that these new 
deep-shelf completions can produce gas volumes of 20-80 million cubic 
feet per day (MMCFd) or more. However, deeper drilling requires 
upgraded rigs, higher well costs, and considerably longer drilling 
times. Greater well depths and higher pressures and temperatures make 
deep-shelf targets riskier and more costly to drill. Target reservoirs 
therefore need to be substantially larger at deep-depth to warrant the 
larger investment. So far, the failures from drilling deep gas wells on 
the shelf outnumber successes. Industry reports, and MMS data confirms, 
that there is only a 1 in 4 chance of successfully drilling a deep gas 
well, which can cost $8 to $20 million per well, at drilling

[[Page 3494]]

depths 15,000-20,000 feet TVD SS. Increased experience and improvements 
in technology over time, encouraged by the economic incentives in this 
rule, should continue to reduce both the risks and costs.
    Industry has made significant advances in developing technology to 
enable drilling to deep geologic horizons. Continued advances in 
directional drilling will help lower costs and foster recovery of 
additional resources from a single development site. New seismic 
technology provides an opportunity for industry to map promising 
prospects at deep depths, but the quality of imaging thus far is 
relatively poor. New and improved technologies are still needed for 
seismic exploration and to solve many of the technological and 
mechanical challenges that will lower drilling costs and enable safe 
and efficient drilling in conditions of extremely high temperature and 
pressure.
    Renewed interest in deep-shelf gas in shallow water may help stem 
the tide of declining gas reserves and production from the GOM shelf. 
To date, operators who discover deep gas are able to bring production 
on line quickly, and at high flow rates. For example, the deep gas 
discovery in South Timbalier Block 204 in 2000 began production in 
2001, and achieved peak production of 350 MMCFd in 2002. But higher 
flow rate wells can also decline rapidly. Therefore, a large number of 
wells will need to be drilled to sustain GOM production. Growing demand 
for natural gas and strong prices have renewed industry's interest in 
this expensive and technically challenging deep gas play and revived 
this mature producing province in the GOM.
    To jump-start increased drilling of natural gas from deep horizons, 
MMS expanded its royalty relief program and began offering a royalty 
relief incentive for shallow water leases in OCS lease sales starting 
in 2001. This incentive provided a suspension of royalties on the first 
20 BCF of deep gas production for all OCS tracts in less than 200 
meters of water where a new deep gas reservoir 15,000 feet or greater 
subsea is drilled and begins production within the first 5 years of the 
life of the lease. Royalty relief is provided only when specified 
annual price threshold ceilings for natural gas are not exceeded. The 
incentive has revived bidding for leases in shallow water in the 
Central GOM and industry is making plans to drill to deep depths on 
these leases. Because of the significant infrastructure--platforms, 
producing facilities, and pipelines--that already exists in this mature 
producing basin, any new deep gas production can be transported quickly 
to markets.
    However, these deep drilling incentives cover only the 1,240 new 
shallow water leases issued since 2001, a portion of the shelf's deep 
gas potential. Production from deep wells on 2,400 existing leases in 
shallow water, where significant infrastructure already is in place, is 
the most attractive source of additional natural gas on the OCS. MMS 
estimated in 2003 (OCS Report, MMS 2003-026 ``Gulf of Mexico OCS Deep 
Shelf Gas Update: 2001-2002'') that there could be 5 to 20 TCF--with a 
most likely value of 10.5 TCF--of recoverable natural gas present in 
deep depths underlying the shallow water shelf portion of the OCS. 
Recent analysis based on new seismic technology has suggested that even 
greater potential may exist for technically recoverable gas resources 
from deep depth locations. (DOI-MMS Press Release 3012, 
November 19, 2003). The majority of that potential (at least 60 
percent) is expected to underlie active leases that were issued before 
2001. This rule is targeted to provide an incentive for these 2,400 
leases, where drilling could commence almost immediately and production 
could be on line within 1-2 years. Companies holding leases issued 
before 2001 will now have incentive to drill deep wells comparable to 
incentives provided for new leases, thereby encouraging more drilling 
of new deep wells and deepening of existing ones. Additional production 
from existing leases will help extend the economic life of those leases 
and the existing infrastructure in the GOM. Deep gas production will 
help bridge the expected mid-term shortfall in natural gas supplies 
until large field development from new deep-water and onshore prospects 
comes on line in the future.

Summary of the Deep Gas Royalty Relief Program

    This summary discusses the various components of the royalty relief 
provisions for deep gas production in shallow water. For leases 
eligible to receive such royalty relief, MMS will suspend royalty 
payments after certain deep drilling activities and outcomes occur. A 
lease will be eligible to receive royalty relief for deep gas wells if 
it:
    (1) Is located in the GOM wholly west of 87 degrees, 30 minutes 
West longitude; and entirely in water depths less than 200 meters (or 
partly in water depths less than 200 meters if issued in lease sales 
that did not provide for non-discretionary deep-water royalty relief), 
and
    (2) Was in existence on January 1, 2001; was issued in a lease sale 
held after that date, and the lessee exercised its option before 180 
days after the effective date of the final rule or 180 days after the 
lease was issued, whichever is later, to substitute the terms of this 
rule for the deep gas royalty relief terms in the original lease 
instrument; or is issued in a future lease sale with terms that 
reference this rule, and
    (3) Has production within 5 years after the effective date of final 
rule (or within 6 years if the lessee has obtained a 1-year extension) 
from a qualified deep well drilled after March 26, 2003, or
    (4) Has no gas or oil production from a deep well with a perforated 
interval the top of which is 18,000 feet TVD SS or deeper, but has a 
certified unsuccessful original well, or a certified unsuccessful 
sidetrack whose length is at least 10,000 feet, drilled after March 26, 
2003, to depth of at least 18,000 feet TVD SS within 5 years after the 
effective date of the final rule.
    The form of the royalty relief is a royalty suspension volume (RSV) 
or royalty suspension supplement (RSS). An RSV under this rule is the 
amount of qualified deep well gas production from a lease, or allocated 
to a lease under a unit agreement, that will be royalty free as a 
result of the incentive earned from drilling certain successful wells 
and sidetracks. An RSS is the amount of future oil and gas production 
from, or allocated under a unit agreement to, a lease from all wells 
regardless of depth or drilling date or hydrocarbon (gas or oil) 
produced that will be royalty free as the result of the incentive 
earned from drilling certified unsuccessful wells and sidetracks.
    For deep wells, i.e., original wells or sidetracks, to qualify for 
RSV and RSS as specified in Table 1, they must meet certain 
requirements as described in detail below:
    (1) The vast majority of shallow water leases have not yet drilled 
and produced gas or oil from deep depths. For those leases, drilling a 
new deep well may earn an RSV of 15 BCF when drilled (and perforated) 
to the vertical depth interval between 15,000 to less than 18,000 feet 
subsea; or an RSV of 25 BCF when drilled (and perforated) to vertical 
depths of at least 18,000 feet subsea. Drilling a sidetrack may earn a 
prorated RSV based in part on its measured depth (i.e., length from the 
point of departure from the original hole), up to a maximum of 15 or 25 
BCF (depending on which deep depth interval is reached).

[[Page 3495]]

    (2) While the rule was being developed, MMS did not want to 
discourage or delay deep drilling, so the proposed rule provided that 
any new wellbore on which drilling started on or subsequent to March 
26, 2003, targeted to below 15,000 feet vertical depth, could still 
qualify the lease for an RSV. The specification of an RSV for 
sidetracks, as well as the additional RSV for a second deeper qualified 
well, was added to the final rule as a result of MMS's review and 
analysis of public comments on the proposed rule. Because the proposed 
rule envisioned the possibility of royalty relief in these latter 
cases, they have the same effective date as original wells.
    (3) If a new wellbore was drilled on a lease before March 26, 2003 
(the publication date of the proposed rule in the Federal Register), 
but has yet to produce, the lease may still earn an RSV from a 
qualified well or sidetrack that produces the first deep gas on the 
lease. But any subsequent production from the earlier unqualified well 
or sidetrack cannot share in any RSV.
    (4) Generally, an RSV cannot be earned on a lease that has a deep 
well that produced before March 26, 2003. However, MMS is providing an 
exception when those deep wells or sidetracks on a lease produced from 
the depth interval between 15,000 and 18,000 feet TVD SS. For those 
leases, to encourage additional deep drilling to deeper horizons, 
subsequent wells or sidetracks drilled (and perforated) to at least 
18,000 feet TVD SS may qualify the lease for an RSV of 10 BCF for an 
original wellbore, or a prorated RSV--up to a maximum of 10 BCF--for a 
sidetrack, based in part on its measured depth (see table below).
    (5) A lease will qualify for an RSS that may be applied to any 
subsequent gas and oil production from or allocated to the lease if it:
    a. Has an unsuccessful original well or an unsuccessful sidetrack 
at least 10,000 feet in length that reaches a target on the lease at a 
depth of at least 18,000 feet TVD SS, and the drilling began on or 
after March 26, 2003, and no later than 5 years after the effective 
date of the final rule;
    b. Has started drilling that well before producing gas or oil from 
an original well or sidetrack on the lease with a perforated interval 
the top of which is 18,000 feet TVS SS or deeper; and
    c. Receives subsequent confirmation from MMS that the drilling 
effort was deep enough but unsuccessful. MMS relies on data that the 
lessee provides within 60 days after the well reaches its total depth.
    (6) A lessee cannot obtain both a full RSV and a full RSS from the 
same wellbore. If a certified unsuccessful well later produces, then 
any portion of the RSS taken (plus gas and oil produced during periods 
that would have been royalty-free but for the fact that gas prices 
exceed the price threshold) would have to be subtracted from any RSV 
earned from that well. Also, the lessee could not use any remaining RSS 
earned from that well, beginning when the RSV is earned from that well.
    (7) The RSS resulting from drilling a certified unsuccessful 
original well is 5 billion cubic feet of gas equivalent (BCFE) if the 
lease has not produced from any deep well before the certified 
unsuccessful well is drilled. The RSS for a certified unsuccessful 
sidetrack is prorated in the same proportion of the RSV as for an 
original well (0.8 BCFE plus 120 MCFE times the sidetrack measured 
depth, rounded to the nearest 100 feet), but no more than 5 BCFE, if 
the lease has not produced from any deep well. If the lease has 
produced from a deep well in the 15,000-18,000 feet TVD SS interval 
before a certified unsuccessful original well, or a sidetrack of at 
least 10,000 feet measured depth is drilled, the RSS resulting from 
drilling the certified unsuccessful original well is 2 BCFE.
    The following table shows the royalty suspensions in BCF that a 
lessee can earn for deep wells--original wells or sidetracks--on a 
lease drilled and completed with a perforated interval the top of which 
is at or below 15,000 feet TVD SS, and the RSS, in BCFE, that a lessee 
can earn for certified unsuccessful original wells or sidetracks on a 
lease drilled to a least 18,000 feet TVD SS.

 Table 1.--Royalty Suspension Volumes (RSV) and Royalty Suspension Supplements (RSS) Earned From Deep Gas Wells
                              on OCS Leases in Shallow Waters of the Gulf of Mexico
----------------------------------------------------------------------------------------------------------------
                                                                          For a qualified      For a certified
                                   Date of initial                      deep well, a lease  unsuccessful well, a
                                  production or of                      receives an RSV on  lease receives up to
         Depth of Well             reaching target      Type of well      gas production    2 RSS on oil and gas
                                        depth                             from qualified     production from any
                                                                             wells of:            wells of:
----------------------------------------------------------------------------------------------------------------
A well 15,000 to less than       Before production   Original.........  15 BCF............  None.
 18,000 feet TVD SS (top of       from a well
 perforated interval).            15,000 feet TVD
                                  or deeper.
                                                     Sidetrack........  4 BCF + (600 MCF    None.
                                                                         times measured
                                                                         depth (to nearest
                                                                         100 feet));.
                                                                        Up to maximum of    ....................
                                                                         15 BCF.
A well 18,000 feet TVD SS or                         Original.........  25 BCF............  5 BCFE.
 deeper.
                                                     Sidetrack........  4 BCF + (600 MCF    0.8 BCFE + (120 MCFE
                                                                         times measured      times measured
                                                                         depth (to nearest   depth (to nearest
                                                                         100 feet));.        100 feet)) if
                                                                                             measured depth at
                                                                                             least 10,000 feet;
                                                                        Up to maximum of    Up to a maximum of 5
                                                                         25 BCF.             BCFE.
A well 18,000 feet TVD SS or     At the same time    Original.........  10 BCF............  2 BCFE.
 deeper (top of perforated        as or after
 interval).                       production from a
                                  qualified or
                                  unqualified well
                                  15,000-18,000
                                  feet deep.
(If initial production is from                       Sidetrack........  4 BCF + (600 MCF    2 BCFE.
 a qualified well, then the RSV                                          times measured
 is added to the RSV earned by                                           depth (to nearest
 the qualified well).                                                    100 feet));.
                                                                        Up to maximum of    ....................
                                                                         10 BCF.
----------------------------------------------------------------------------------------------------------------


[[Page 3496]]

    A lease may earn two RSSs of up to 5 BCFE each plus an RSV up to 25 
BCF. Thus, a lease could earn the right to produce as much as 35 BCF of 
natural gas royalty-free, that is, 10 BCFE because of two initial 
unsuccessful wells and then 25 BCF from a subsequent successful well 
drilled to at least 18,000 feet TVD SS. A current or successor lessee 
may also apply the RSV earned by the lease's first qualified well to 
any natural gas production from, or allocated under an approved unit 
agreement to, the lease from subsequent qualified wells.
    However, if the qualified wells are drilled to a depth 15,000 to 
less than 18,000 feet TVD SS, then the maximum RSV volume that can be 
applied to gas production is 15 BCF. If the first qualified deep well 
was drilled 15,000 to less than 18,000 feet TVD SS, and the second to a 
depth 18,000 feet TVD SS or deeper, then the lease would earn 15 BCF 
initially plus another 10 BCF for the second qualified deep well. In 
this case, gas production from all qualified wells on the lease share 
in any remaining RSV up to a total of 25 BCF, as long as the aggregate 
amount of royalty suspension volume used does not exceed the 25 BCF 
earned by drilling the qualified wells.
    A lease must have a qualified deep well before an RSV may apply to 
deep well gas produced on that lease, or allocated to the lease under a 
unit agreement. Therefore, if Lease A is in a unit and is allocated 
production from a qualified deep well on Lease B in the unit, then 
Lease A has no RSV unless it also has its own qualified deep well. If 
Lease A has earned no RSV, royalty must be paid on any deep well gas 
production allocated to it under a unit agreement.
    Finally, once production begins from a qualified deep well on a 
lease, the lessee must use the applicable RSV continuously for all gas 
production on or allocated to that lease from qualified deep wells. In 
other words, the lessee cannot delay applying the RSV to applicable 
production, and must apply the relief only to production occurring 
after this rule becomes effective.
    Any remaining RSV and RSS are subject to a natural gas threshold 
price of $9.34 per MMBtu, adjusted from year 2004 for inflation. If the 
average daily closing NYMEX natural gas price (for the nearby future 
delivery month) exceeds this adjusted level for that full calendar 
year, the lessee would have to pay full royalties on any production of 
natural gas or oil that would otherwise have royalties suspended due to 
royalty relief from a qualified deep well or certified unsuccessful 
deep well. Moreover, the volume produced during such a calendar year 
would count against the eligible RSV and RSS.

Modifications Made in the Final Rule

    The main elements of the deep gas royalty relief program described 
in the proposed rule have been retained in this final rule. In 
particular, a lease drilling to and producing natural gas from depths 
of 15,000-18,000 feet TVD SS may earn a royalty suspension volume (RSV) 
of 15 BCF. A lease drilling to and producing natural gas from depths of 
18,000 feet or deeper TVD SS may earn an RSV of 25 BCF. In each case 
the specified amounts of relief are earned if the first deep gas 
production on the lease occurs from an original well, i.e. a new 
wellbore not including sidetracks, that commenced drilling on or after 
the date of the proposed rule of March 26, 2003. Subsequent deep wells 
may share in the RSV earned by the first deep well.
    The final rule clarifies what production the royalty suspension 
volume applies to. As discussed in more detail below, the royalty 
suspension volume applies only to gas production from qualified deep 
wells on the lease, and not to gas production from wells in shallower 
depths or from deep wells that are not qualified wells as defined in 
the rule. (The deep gas royalty suspension volume does not apply to 
crude oil production, even if it comes from a deep well.) Because the 
RSV applies only to production from certain wells, and not to 
production from the lease as a whole, the final rule applies the RSV to 
the production reported on the Oil and Gas Operations Report, Part A 
(OGOR-A), which is the only report of production on the well level that 
lessees or operators must file with MMS. The monthly report of sales 
and royalty (the Form MMS-2014) reports production by product and 
production month on a lease level from all wells at all depths, not on 
a well level. Hence, it is not possible to use the volumes reported on 
Form MMS-2014 as the base to which the RSV is to be applied.
    The OGOR-A, however, reports all gas produced from an identified 
well, including flared gas, gas that is used as fuel on a lease, etc. 
In other words, volumes reported by well on the OGOR-A include both 
royalty-bearing and non-royalty-bearing production. Non-royalty-bearing 
production is not reported on the Form MMS-2014, but as explained 
above, that form reports production on a lease level. It is not 
possible to know from either the OGOR-A or the Form MMS-2014 how much 
production from a particular well was used as fuel or flared. Because 
the RSV will apply to production only from certain wells, the only 
practical option is to use the production figures reported on the OGOR-
A. Consequently, it is not possible to apply the RSV exactly only to 
royalty-bearing production from those wells. At the same time, however, 
the non-royalty-bearing production from a particular well is generally 
a very small percentage of the total production.
    The practical effect of applying the RSV to the production volumes 
reported on the OGOR-A is to reduce slightly the amount of actual 
royalty relief a lessee obtains below the stated volumes prescribed in 
the rule. However, because the percentage of non-royalty-bearing 
production generally is so small, we believe the effects are 
negligible.
    In addition, the lease may earn a royalty suspension supplement 
(RSS) of either 5 BCFE or 2 BCFE up to 5 BCFE from drilling an original 
well or a sidetrack (of at least 10,000 feet measured depth) to a 
target depth of at least 18,000 feet TVD SS that is not capable of 
production, or meets certain standards for encountering non-commercial 
amounts of hydrocarbons. To earn an RSS of 5 BCFE for an original well, 
or up to 5 BCFE for a sidetrack, for drilling unsuccessfully to 18,000 
feet TVD SS or deeper, the lease must not have produced gas or oil 
previously from any deep well. If the 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, the lease will receive an RSS 
of 2 BCFE for either an unsuccessful original well or an unsuccessful 
sidetrack (of at least 10,000 feet measured depth). A lease may earn up 
to two RSSs of up to 5 BCFE each in failed attempts to locate deep gas 
resources from wells that began drilling on or after March 26, 2003.
    MMS received a variety of comments on the manner in which we intend 
to treat unitization agreements. MMS concluded that the structure 
offered in the proposed rule is appropriate. The RSV and RSS are lease-
specific and not formally part of an MMS-approved unit agreement 
providing for production allocation. Hence, a lease must have a well 
drilled on it to deep depths to earn an RSV. The lease cannot be 
allocated any portion of another lease's RSV or RSS or redistribute its 
own RSV or RSS for use by other leases in the unit. MMS presumes that 
compensatory side arrangements between unit co-owners will evolve and 
prove to be a better way to deal with the distribution of royalty 
relief among unit owners than would be the case under formal MMS rules. 
In particular, such rules are subject to complications from changing 
partners

[[Page 3497]]

and revision of lease and unit agreement terms.
    We reconsidered the requirement that production must commence 
within 5 years after the date of the final rule for drilling to deep 
depths to qualify for relief. Some respondents recommended a longer 
period, in conjunction with discretion for MMS to grant extensions on a 
case-by-case basis. MMS acknowledges that circumstances beyond the 
lessee's control could prevent meeting the 5-year time frame. 
Accordingly, under certain conditions, MMS will extend the time 
required to start production for up to 1 year if drilling has reached 
the target depth and production would have started within 5 years 
following the date of the final rule, except for circumstances beyond 
the lessee's control.
    The basic features of the incentive program were generally well 
received by those commenting on the Proposed Rule for Relief or 
Reduction in Royalty Rates--Deep Gas Provisions (68 FR 14868). In 
consideration of comments offered at a workshop held in Houston on 
April 30, 2003, and comments submitted by 14 separate respondents to 
the proposed rule one month later, MMS made some changes in this final 
rule. Changes in three areas are noteworthy--leases with multiple deep 
wells, sidetrack deep wells, and the price threshold.
    Leases with Multiple Deep Wells: Under the proposed rule, a lease 
which first produced from deep depths (at least 15,000 feet TVD SS) as 
a result of a well commencing prior to the proposed rule would not have 
been eligible for deep gas royalty relief. MMS now believes that some 
relief from royalties is appropriate in the special instance where a 
lease has produced only from the 15,000-18,000 foot depth category and 
subsequently drills and produces after the proposed rule in the deeper 
depth category. This is the case because the prospective nature of a 
deeper depth drilling category is still unknown and some incentive 
could be effective at stimulating drilling to the deeper depths.
    We set the RSV earned in these cases for original wells at the 
difference in RSV's between relevant depth categories. So, if a lease 
has produced from 15,000-18,000 feet TVD SS before the proposed rule, 
or has produced from this depth interval after the proposed rule from a 
well drilled before the proposed rule, the lease is still eligible to 
earn 10 BCF in relief [25 BCF-15 BCF] from subsequent drilling and 
production from 18,000 feet or deeper TVD SS. Of course, in neither 
case do the unqualified wells earn any relief; nor can production from 
such wells share in relief earned by other wells, regardless of the 
sequence in which the unqualified well produces.
    Along these same lines, the proposed rule set the maximum RSV 
available to a lease equal to the RSV earned by the first qualified 
well. To encourage the operator to drill the most prospective target 
first, the final rule allows the lease's RSV to increase if a well is 
subsequently produced from a deeper depth category. So, drilling two 
qualified deep original wells--the first to 15,000-18,000 feet TVD SS, 
and the second to 18,000 feet or deeper TVD SS--earns the lease 15 BCF 
initially, followed by an extra 10 BCF for the second well. Thus, the 
lease has a total RSV of 25 BCF in this case.
    The same increment of 10 BCF would apply if the first qualified 
well was a sidetrack, and the second an original well. If an original 
well were first drilled into the 15,000-18,000 foot depth interval, 
followed by a sidetrack into the deeper interval, the sidetrack could 
earn an RSV up to 10 BCF depending on the length of the sidetrack (as 
discussed further below). In addition to this change in royalty relief 
on multiple-well leases, the final rule permits the second well to 
share all of the lease's RSV even if it is not drilled into the deepest 
depth interval.
    Sidetrack Deep Wells: We also decided to explicitly make deep 
sidetrack drilling eligible for relief in the final rule because 
sidetrack drilling may become an effective means to exploit deep gas 
resources. The proposed rule provided no specific incentive to drill 
additional sidetracks because MMS believed that the structure of the 
royalty relief expressly offered to original wells in the proposed rule 
would not have unduly biased drilling in favor of the more expensive 
original wells. However, MMS asked for comments on whether we also 
should include sidetracks. Responses emphasized the gap in our program 
which overlooked individual drilling opportunities containing potential 
resources too small to make undertaking an original well economical, 
even with royalty relief. Also, sidetracks occasionally are used to 
reclaim previously used platform slots, that is, to make maximum 
efficient use of existing facilities, which is an important feature of 
this program. For these reasons, MMS has decided to add sidetrack 
drilling to our royalty relief program in the final rule.
    The rule is now structured so that original wells and sidetracks 
are treated the same with regard to lease and well eligibility, with 
three main exceptions. First, the magnitude of sidetrack relief differs 
from the relief MMS makes available to original deep wells. Second, 
sidetrack relief earned can never exceed the amount of relief that 
would have been earned by an original well drilled under the same 
circumstance, to the equivalent depth. Third, the amount of sidetrack 
relief is based on measured depth from the previously drilled hole to 
the bottom hole of the sidetrack, rather than drilling depth.
    In general, the following equation gives the amount of relief 
earned by a qualified sidetrack well. The RSV is equal to 4 BCF plus 
0.6 BCF per 1,000 feet of measured depth drilled, that is, the length 
of the sidetrack. Sidetrack relief is constrained to not more than 15 
BCF for the first qualified deep well produced from 15,000-18,000 feet 
TVD SS or 25 BCF of the first qualified deep well produced 18,000 feet 
TVD SS or deeper. If deep production has already occurred from 15,000-
18,000 feet TVD SS on the lease, then drilling and producing a 
sidetrack to 18,000 feet TVD SS or deep can earn the amount of relief 
given by the equation but no more than 10 BCF. Of course, if deep 
production has already occurred at 18,000 feet TVD SS or deeper, 
drilling a sidetrack (or original well) to this depth interval (or to 
the shallower depth interval) earns no relief.
    A lease's eligibility for royalty relief is limited in several ways 
where there exists a sidetrack that commenced drilling to a deep depth 
interval before the proposed rule and either produced before the 
proposed rule or first produced from that deep depth interval after the 
date of the proposed rule. Otherwise, sidetracks are treated just like 
original deep wells. These restrictions mirror those imposed on 
drilling an original well before the proposed rule. First, the 
sidetrack does not earn relief and its production cannot share in any 
relief earned by other deep wells. Second, the lease cannot earn deep 
gas relief from any subsequent wells drilled to that same deep depth 
interval or to a shallower deep depth interval. Third, subsequent 
drilling of an otherwise qualified original well to a deeper depth 
interval earns relief in an amount equal to the difference in available 
RSV amount allowed for original wells in the relevant drilling depth 
categories, i.e., 10 BCF. Hence, if a sidetrack is drilled and produced 
before the proposed rule to a depth of 15,000-18,000 feet TVD SS, and 
an original well subsequently is drilled and produces from a depth 
18,000 feet TVD SS, or deeper, then the relief awarded the lease from 
the original well is 10 BCF [25 BCF-15 BCF]. Finally,

[[Page 3498]]

subsequently drilling and producing another sidetrack at a deeper depth 
interval may earn a full sidetrack RSV (see our Response to Comment No. 
7 below) up to the amount that could have been earned in the same 
circumstances had an original well been drilled, i.e., up to 10 BCF.
    Price Thresholds: The natural gas price threshold that MMS laid out 
in the proposed rule came under considerable scrutiny during public 
review and comment. Respondents expressed concern that MMS was about to 
introduce a drilling incentive program under which no otherwise 
eligible activity would qualify for the incentive owing to actual gas 
prices exceeding the threshold prices.
    MMS recognizes that if the gas prices existing in the summer of 
2003 are expected to persist, that circumstance alone will induce 
significant increases in deep gas drilling. However, volatile price 
swings, such as those the U.S. has experienced recently, will dampen 
the incentive to invest in finding new reserves, even if average prices 
for natural gas remain high.
    To test the potential benefit of different approaches to easing the 
disincentive created by a price threshold, MMS explicitly included gas 
price volatility in analysis of how much more deep drilling and 
production and how much less royalty collection would occur under 
various price thresholds. MMS used the simulation model to determine 
the likelihood in each year that a specific threshold price would be 
exceeded by the actual average yearly price, under different 
assumptions about price volatility. To the extent this might happen, 
the profitability of drilling would be adversely affected because the 
expected value of royalty relief is diminished as the likelihood of 
losing some portion of royalty relief increases in the presence of 
volatile prices.
    To measure the effect of a specific price threshold on incremental 
deep gas production, we assume the level of drilling is reduced 
proportionately to the expected reduction in the value of royalty 
relief occasioned by the price threshold policy. The likelihood that 
gas prices would exceed the applicable threshold price helps determine 
the expected reduction in the value of royalty relief. In this manner 
we are able to revise the drilling scenario and estimate the impacts of 
a price threshold option on aggregate program drilling and, ultimately, 
production.
    To measure the effect of a specific price threshold on federal 
royalties, we consider the revised drilling scenario in the presence of 
anticipated gas price volatility. Those instances where the stipulated 
price threshold level is exceeded result in royalty payments on 
otherwise royalty free production. We then value the royalties 
collected during those years, in conjunction with forgone royalties in 
other years, and adjust the base case no-threshold royalty option. 
Forgone royalty is the difference between royalty lost from production 
that would have occurred anyway without the incentive and royalty 
gained from extra production due to the incentive.
    MMS evaluated several options under each of two approaches--delayed 
application of a modestly higher price threshold or immediate 
application of a substantially higher price threshold--to easing the 
price threshold policy in the proposed rule. The delayed application 
options fared better on achieving incremental production while the 
immediate application options were more effective at reducing the 
forgone royalty. MMS determined that a $9.34/MMBtu gas price threshold 
in 2004 and escalated for inflation thereafter provided the best 
balance of incremental production and forgone royalty under the 
relatively high volatility conditions prevalent in the last decade. In 
comparison with a no price threshold policy, we estimate the $9.34 
price threshold level provides about 96 percent as much incremental 
production while reducing the forgone royalty by 35 percent.

Itemized Responses to Comments on the Proposed Rule

    The following section gives detailed responses to 13 categories of 
comments which MMS received on the proposed rule from 14 separate 
commentors.

1. Magnitudes of the Royalty Relief for Original Wells

    Comments: Overall, the industry comments supported the RSV and RSS 
amounts MMS provided in the proposed rule for the two drilling depth 
intervals. Other comments included the following: Quantifying generic 
RSV's is difficult because each drilling target is different. Apply the 
same RSS amount as for successful wells. (Chevron). We support a tiered 
system of RSV's (BP). The RSV's proposed are adequate (El Paso, API). 
The dry hole supplement is quite small given the risk and cost involved 
in deep gas activities (Noble).
    Response: MMS believes the RSS level should be kept at a fraction 
of the RSV amount to avoid creating an incentive to not complete a 
marginally economic and otherwise successful well. In the proposed 
rule, MMS asked questions about different combinations of royalty 
relief amounts, but for the most part commenters did not address these 
questions or their answers weren't responsive. Therefore, MMS has no 
new information that would support a change in the amounts of relief by 
drilling depth as specified in the proposed rule.

2. Lease Eligibility

    Comments: Drop the stipulation that leases with previous deep gas 
production not be eligible for this program. It is unclear why such 
leases are excluded (Pioneer). Include leases issued by the States 
before 1953, and subsequently ratified as Federal leases by Section (6) 
of the Outer Continental Shelf Lands Act (OCSLA) (43 U.S.C. 1335) 
(Exxon). Don't restrict the program to leases lying entirely in water 
depths less than 200 meters. Expand the deep gas program to deep waters 
(AAC).
    Response: Leases that already have deep gas production are more 
prospective in regards to additional deep depth drilling. Accordingly, 
the proposed rule targeted leases where deep depth drilling previously 
has either not occurred or has not been successful. Nevertheless, upon 
further investigation, it appears that, generally speaking, success at 
the 15,000-18,000 foot TVD SS depths does not have a dramatically 
positive effect on the anticipated drilling success at 18,000 feet TVD 
SS or deeper. Accordingly, the final rule modifies this constraint on 
lease eligibility. A lease with a deep depth producing well that was 
drilled prior to the proposed rule is eligible for royalty relief if, 
after publication date of the proposed rule, March 26, 2003, an 
additional well is drilled to a deeper depth interval and produces 
natural gas. MMS discusses elsewhere the specific terms of relief and 
amounts available to be earned.
    The omission from the proposed program of leases that were issued 
by the States before 1953 was inadvertent. In this final rule, these 
leases are now eligible for relief, along with all shallow water leases 
issued under Federal lease sales held before 2001.
    For leases lying partly in deep water, MMS prefers to avoid a 
situation in which any such lease can obtain non-discretionary relief 
from more than one categorical royalty relief program, e.g., deep-water 
and deep-depth drilling. The framework and parameters of each program 
were designed assuming no further categorical royalty relief would be 
provided. As of the summer of 2003, there were 132 leases issued before 
2001 and lying partly in water depths greater than 200 meters which are 
eligible for case-by-case or categorical royalty relief

[[Page 3499]]

under sections 302 and 304 of the Deep Water Royalty Relief Act 
(DWRRA). Eighty-two of these leases were issued from 1996-2000 and are 
covered under the categorical royalty relief program under section 304 
of the DWRRA. They are not eligible for the deep gas program. Fifty of 
the leases were issued before 1996, and are covered only by the 
discretionary royalty relief provisions of section 302 of the DWRRA, 43 
U.S.C. 1337(a)(3)(c). MMS's final rule extends eligibility for deep gas 
drilling relief to these 50 leases, as well as to any lease issued from 
sales held in 2001 or thereafter without DWRRA royalty relief 
eligibility and lying at least partly in less than 200 meters of water 
depth.

3. Drilling a Deep Well Before Date of the Proposed Rule

    Comments: Consider making deep wells drilled on leases with 
previous deep depth production eligible for relief if drilled to a 
substantially different depth, to new structures, or to depths at least 
100 feet deeper (Pioneer, McMoran). Clarify eligibility of a well or 
lease if a deep well commenced drilling before March 26, 2003. If this 
well subsequently produces, what is the effect on eligibility for 
royalty relief and on any relief already earned (El Paso)? Allow 
eligibility for wells that commenced drilling before the date of the 
proposed rule if not completed by that time (API).
    Response: Under the proposed rule, a lease would not be eligible 
for deep gas relief if it produced from deep depths before March 26, 
2003. If a deep well commenced drilling before that date, and 
subsequently was the first deep well to produce after that date, the 
lease would not be eligible for deep gas relief under the proposed 
rule.
    MMS has reconsidered our position on this issue. Our prior stance 
was based on the notions that (1) drilling and production before March 
26, 2003, reduced the economic risk associated with further deep gas 
drilling, and (2) drilling before March 26, 2003, was undertaken 
without the need for any incentive, so the production on the lease 
associated with this pre-rule activity should not be eligible for 
relief.
    MMS's modified position is that early successful drilling of deep 
gas does indeed reduce the risk of subsequent drilling to the same 
depth interval, but is much less likely to reduce the risks of drilling 
to deeper depth intervals. Also, MMS has concluded that elimination of 
relief to the entire lease from deep original wells drilled before 
March 26, 2003, but produced afterwards and first on the lease from 
deep depths, could encourage delays in the commencement of production 
from these wells until a subsequent well produces from deeper depths 
and earns relief. Hence, given these observations, MMS has made changes 
in the final rule.
    If an original well is drilled and produces from a perforated 
interval the top of which is 18,000 feet TVD SS or deeper before March 
26, 2003, the lease is not eligible for deep gas royalty relief. 
However, if the pre-March 26, 2003, drilling and production was to 
depths of 15,000-18,000 feet TVD SS, then subsequent drilling and 
production from a qualified original well at a deeper depth interval, 
i.e., at least 18,000 feet TVD SS, is eligible for deep gas relief in a 
lesser amount of 10 BCF, i.e., equal to the difference in RSV's for the 
two depth intervals. None of the production from the first 
(unqualified) deep well is eligible to share the relief earned by other 
subsequent wells.
    MMS has also reconsidered its position regarding the earlier 
formulation wherein the first deep well sets the upper limit on the RSV 
a lease can earn. This approach could encourage initial drilling to a 
less prospective but deeper depth, in order to capture a higher relief 
amount for the lease.
    To avoid this potential misallocation of resources, MMS structured 
the final rule so the total magnitude of RSV that can be earned on the 
lease is independent of the order in which wells to different deep 
depths are drilled. Thus, in the case of wells drilled first to 15,000-
18,000 TVD SS, and subsequently to 18,000 feet or deeper TVD SS, the 
lease could initially earn an RSV of 15 BCF, followed by earning an 
additional 10 BCF, so the aggregate amount earned by the lease, 25 BCF, 
is precisely what could have been acquired under the proposed rule from 
drilling the deepest well first. Further, deep wells less than 18,000 
feet TVD SS may use up to all the RSV earned by the lease. Note that 
the increment of 10 BCF for the very deep well is also precisely the 
same amount of relief awarded to a very deep well in the case discussed 
earlier where a well to 15,000-18,000 TVD SS feet was drilled and 
produced before March 26, 2003, or drilled before this date and 
produced afterwards.
    It is possible that a deep well could begin drilling before the 
date of the proposed rule and eventually produce after another 
successful deep well has been drilled and produced, resulting in 
royalty relief. In these cases, any royalty relief previously earned is 
retained. However, if the well that commenced drilling before the 
proposed rule produces first, a later successful well to that drilling 
depth category that would otherwise qualify for relief does not 
qualify. A third well will remain eligible for incremental relief of 10 
BCF if drilled to a depth interval at least 18,000 feet TVD SS, if both 
of the previous two deep wells were in the 15,000-18,000 foot depth 
range. In other words, this third well will receive the difference in 
RSV between the amount available in its depth interval and the amount 
associated with the depth interval of the two previous wells. If one or 
more of the two previous deep wells was drilled to the same depth 
interval as the third deep well, then that third well earns no added 
relief for the lease. It may, however, share in any relief earned by a 
previously drilled qualified well.
    The eligibility of sidetrack drilling for royalty relief in the 
final rule, which we discuss in detail in the next three sections, 
complicates somewhat the previously described arrangements. 
Conceptually, eligibility of sidetracks for royalty relief works in the 
same way as for original wells, except that the amounts of relief that 
can be earned in any situation are no more than, or, more typically, 
are less than those for original wells.
    In summary, we make the following changes for successful deep 
original wells:
    A. If a lease has been drilled and produced from deep depths before 
the proposed rule, the lease may remain eligible for an RSV if another 
well is drilled successfully to a deeper depth category. Under the 
proposed rule, production from a deep well that commenced drilling 
before the date of the proposed rule disqualified the lease from any 
further royalty relief. In the final rule, only further drilling to the 
same deep depth interval or shallower is disqualified. Subsequent 
drilling and production to the next deepest depth interval may earn up 
to 10 BCF of added relief.
    B. Because the deeper depth well may benefit from the earlier 
success, the magnitude of relief earned is set equal to the difference 
between the RSV's potentially available at the two drilling depth 
intervals. In the case of a lease already having produced from a depth 
of 15,000-18,000 feet TVD SS, a subsequent successful deep well drilled 
to a depth of 18,000 feet TVD SS or deeper now earns up to 10 BCF.
    C. If a lease has a deep original well which commenced drilling but 
had not produced before the date of the proposed rule, the original 
well will remain ineligible to earn relief or to use relief earned by 
other wells. MMS clarifies that the lessee can produce from that well 
at any time after the lease

[[Page 3500]]

has earned deep gas royalty relief without jeopardizing the relief. If, 
however, that well produces from a depth 15,000 to less than 18,000 
feet TVD SS before any qualified well produces at that depth interval, 
then the lease is ineligible for relief associated with that depth 
interval. Moreover, we add the flexibility to earn relief in the amount 
of 10 BCF for subsequent drilling to a deeper depth interval.

4. Eligibility of Sidetracks

    Comments: MMS should amend provisions that would allow sidetrack 
drilling to deep depths to become eligible for royalty relief. With 
over 3,500 platforms, it makes sense to use a previously drilled 
wellbore to drill a new deep test well (NOIA). Sidetracks eligibility 
will encourage deep drilling at least cost (Noble, Rowan, Pioneer). 
Many platforms are already slot limited, so drilling sidetracks avoids 
costly platform modifications (ExxonMobil, Marathon, Merit). Sidetracks 
are also more benign to the environment because they involve less drill 
cuttings and lower emissions than original wells (Shell, API, 
ExxonMobil, Marathon).
    Response: MMS agrees that including sidetrack drilling in the deep 
gas program is desirable. Although the average production of reserves 
from sidetracks is about two-thirds that of deep original wells per 
successful well drilling, that observation may suggest the marginal 
nature of certain drilling activities and their need for royalty relief 
incentives to undertake more of this type of drilling.
    For the most part the net cost (gross cost less expected value of 
the royalty relief) of drilling a vertical well with royalty relief 
will be higher than the gross cost of drilling a sidetrack well without 
royalty relief. Hence, the proposed rule did not anticipate a 
substantial number of cases in which royalty relief for original wells 
but not sidetracks would result in inefficient drilling decisions. We 
now recognize that expanded use of sidetrack drilling presents a more 
important opportunity for accelerating deep depth gas production than 
we anticipated. Increases in the use of reclaimed slots and 
advancements in the technology of sidetrack drilling offer significant 
opportunities to extract more deep depth resources in an economical 
way.
    Hence, we are adding sidetrack drilling to our deep gas incentive 
program in the same manner that relief applies to successful deep 
original wells, though the amounts of relief will vary in comparison to 
original wells. We do provide an RSS for certain types of unsuccessful 
sidetracks drilled to depths of at least 18,000 feet TVD SS. The 
minimum length the sidetrack must be drilled (measured depth) is 10,000 
feet to qualify for an RSS associated with a drilling failure.
    As is the case for original wells, sidetracks that begin drilling 
before the date the proposed rule was published are disqualified from 
royalty relief. If a deep sidetrack produced from 15,000-18,000 feet 
TVD SS before March 26, 2003, then any subsequent sidetracks or 
original wells to that same depth interval are also ineligible to earn 
royalty relief. Deep production undertaken before March 26, 2003, in 
the 15,000-18,000 foot interval also restricts the amount of relief 
that can be earned by either sidetracks or original wells drilled to a 
deeper depth interval to no more than 10 BCF. As with original wells, 
production from sidetracks that begin drilling before March 26, 2003, 
cannot share in any relief earned by qualified wells.

5. Defining Sidetracks for Deep Gas Royalty Relief

    Comment: One comment requested clarification of the definition that 
MMS would use for sidetracks as compared to bypasses if a sidetrack 
royalty relief program is adopted in the final regulations. The 
commenter referred to a slide presentation on sidetracks presented by 
MMS at the workshop held in Houston, Texas on April 30, 2003, in which 
one of the slides stated that, ``A sidetrack is drilled to a different 
target reservoir from the original well,'' and ``A well deepened to a 
new target is a sidetrack.'' Two other related slides were also 
presented. A slide on bypasses stated, ``A bypass is drilled to the 
same target reservoir as the original well,'' and ``Bypasses are 
generally drilled because of a mechanical problem with the well, such 
as blockage or unwanted deviation.'' The third slide explained that, 
``According to the proposed rule, bypasses would be eligible for 
royalty suspension volumes and RSS's [as adjuncts to original wells], 
but sidetracks would be eligible for neither.''
    According to the comment, operators might infer that ``* * * any 
well in which a plug or whipstock is set and the well subsequently 
drilled to a different bottom hole location with a target in the same 
original objective reservoir, would be classified as a bypass.'' The 
comment continues by presenting the sidetrack and bypass definitions 
given in NTL 2000-N07, and pointing out that there are inconsistencies 
between the definitions given on the slides and in NTL 2000-N07. The 
NTL definitions are repeated here for reference:
    ``Sidetrack--a drilling effort in which an additional hole is 
drilled by leaving a previously drilled hole at some depth below the 
surface and above the total depth. A whipstock or cement plug is set in 
the previously drilled hole, which is the starting point for the 
sidetracking operations. The drilling of a well after a slot 
reclamation (which previously had a well) is considered a sidetrack. 
This section of the hole is directionally drilled to a new objective 
bottom hole location (target). This is also called a geologic 
sidetrack.''
    ``Bypass--a remedial drilling effort in which portions of a hole 
are redrilled around junk (i.e., lost tools, pipe, or other material 
blocking the hole), ``lost holes'' are redrilled, or ``key seats'' or 
``crooked holes'' are straightened. This is also called a mechanical 
sidetrack.''
    The commenter is concerned that administration of the deep gas 
royalty relief program for sidetracks could become complicated if 
different representatives from MMS do not use the same definitions to 
classify sidetrack and bypass drilling operations. To prevent this 
problem from occurring, they suggest that MMS include sidetrack and 
bypass operations in the same category as that for original well 
operations, in consideration of royalty relief under this deep gas 
program (ChevronTexaco).
    Response: Defining sidetracks uniformly and precisely is important. 
MMS accomplishes this by including a reformatted version of the 
``sidetrack'' definition given in NTL 2000-N07 in 30 CFR 203.0 of this 
final rule. Further, the ``bypass'' definition from NTL 2000-N07 is 
incorporated in the definitions for ``original well'' and ``sidetrack'' 
in the final rule to recognize that bypass operations could occur while 
drilling either type of wellbore.
    Qualified original wells drilled with or without a bypass are 
already covered by the royalty relief provisions published in the 
proposed rule. Royalty relief is provided in the final rule for 
qualified sidetracks, which themselves may have a bypass. Bypass 
operations are defined as a remedial drilling effort, and as such do 
not require a special classification for royalty relief.
    Under regulations in the final rule at 30 CFR 203.43(b)(2), lessees 
are instructed to request confirmation of the RSV size that applies to 
the lease from the Regional Supervisor for Production and Development, 
within 30 days following the beginning of production that qualifies for 
royalty relief. The Regional Supervisor's response also will confirm 
how the deep well was classified for royalty relief purposes.

[[Page 3501]]

    Comment: Under the definition of sidetracks in NTL 2000-N07, a deep 
well drilled from a reclaimed surface slot could be disqualified from 
royalty relief because it would be classified as a sidetrack. Wells 
drilled from a reclaimed slot would exceed the cost of a new (original) 
well drilled from an open slot on a platform due to the added cost to 
reclaim the slot needed to drill the well. Accordingly, the commenter 
requested that holes drilled from reclaimed slots receive the same size 
RSV's as original wells (ChevronTexaco).
    Response: MMS uses a reformatted definition of sidetracks from NTL 
2000-N07 in the final rule without making a modification that would 
allow holes drilled from reclaimed slots to be classified as original 
wells for the purpose of royalty relief. Thus, the portion of a hole 
drilled from a reclaimed slot is classified as a sidetrack. MMS assumes 
that some operators include the expense to abandon the old well in 
calculating their sidetrack drilling cost. In virtually all cases, 
however, abandonment expenses for an old well will be incurred by the 
lessees regardless of whether a sidetrack is drilled from that slot. 
Hence, MMS views these abandonment expenses as sunk costs. In fact, 
when reclaiming a slot, lessees should be able to save the cost of 
drilling and casing the portion of the well that is reused.
    MMS recognizes that sidetracks drilled from reclaimed slots will be 
among the longest and most expensive of all sidetracks drilled because 
the kick-off point will be at a shallow depth. However, the variance in 
sidetrack costs with length has been taken into account in calculating 
the sidetrack RSV's. The final rule contains a variable RSV scale for 
sidetracks, that will be applied to typical sidetracks and to well 
bores drilled from reclaimed slots. A sidetrack theoretically could 
earn as much RSV as an original well that is drilled to the same depth, 
but it would have to be a very long sidetrack, e.g., over 18,350 feet 
of measured depth if drilled to 15,000-18,000 feet TVD SS, and 35,000 
feet of measured depth if drilled to 18,000 feet TVD SS or greater.
    Comment: Another comment refers to an MMS workshop presentation 
that suggested to some observers that a sidetrack will be classified as 
a bypass when the operator abandons a new well completion after testing 
and then sidetracks to obtain a greater gas recovery. The sidetrack 
target would be at a bottom hole location higher on the geologic 
structure, but in the same reservoir. An inequity could result from the 
situation described because bypasses are not eligible for relief under 
the proposed rule. Moreover, if sidetracks were eligible for relief in 
the final rule, the size of the RSV may not be as large as the RSV for 
original wells. The commenter suggests that MMS allow a sidetrack to 
receive the same size RSV as an original well if the sidetrack is 
drilled to replace that well (ChevronTexaco).
    Response: Inclusion of a ``sidetrack'' definition reformatted from 
NTL 2000-N07 and a definition for ``original well'' (replaces ``new 
well'' definition in the proposed rule) in the final regulations should 
clarify that all subsequent sidetracks would still be considered the 
original well, if the sidetracking operations were conducted prior to 
the rig moving off the well location. Also, bypasses from an original 
well or sidetrack are still considered the original well or sidetrack.
    Sidetracks do receive an RSV as specified in 30 CFR 203.41(a) of 
the final regulations. In cases where a sidetrack is drilled to the 
same depth interval as a qualified original well that produced more 
than test production (and the original well therefore already has 
earned the lease's RSV at that depth interval), the sidetrack may share 
in the relief previously granted. If the original well produces only 
test production, the sidetrack will earn its own RSV. If a sidetrack is 
drilled to a deeper depth interval than an original deep well, even 
after the original well produces more than test production, it earns a 
sidetrack RSV in addition to the RSV earned by the original well. In 
cases where an unsuccessful original well is drilled 18,000 feet TVD SS 
or deeper and then a deep sidetrack is drilled from the original well, 
an operator could receive an RSS for the original well in addition to 
earning a sidetrack RSV or even another RSS for that sidetrack if it is 
unsuccessful. Wells incapable of more than test production are not 
considered successful wells.

6. Sidetrack Relief Amounts for Successful Drilling

    Comment: Sidetrack RSVs should be 10 BCF in 15,000-18,000 feet and 
20 BCF for greater than 18,000 feet (Noble). A reduced sidetrack RSV of 
3-5 BCF would be enough to spur drilling of marginal prospects (Merit). 
Royalty relief for sidetracks should not be differentiated by the depth 
of the associated original well or by offset distances (El Paso, 
ChevronTexaco). Use smaller RSVs for sidetracks than for original 
wells, but don't limit assessment to a comparison of costs--risk 
matters too. Don't limit sidetrack relief to depths greater than 18,000 
feet, and apply the same RSS as in the proposed rule for deep original 
wells (ChevronTexaco).
    Response: Although sidetrack drilling to deep depths represents 
only a modest proportion of recent drilling and production activity, 
that relationship could change considerably depending on the 
configuration of the royalty relief program. Accordingly, MMS decided 
to add eligibility of sidetrack wells to our deep gas program.
    MMS's objective is to provide a proper incentive to encourage 
additional sidetrack drilling into deep depth targets whose potential 
reserve size would result in a marginally unprofitable development 
under existing royalty obligations. At the same time, MMS wanted to 
eliminate any potential for inefficient drilling decisions resulting 
from a distortion in the relative net costs of drilling vertical wells 
versus sidetracks.
    MMS conducted an analysis of the expected full-cycle cost of 
drilling sidetracks of different lengths versus the cost of drilling 
original wells, accounting for the chance of drilling success. MMS also 
reviewed a very preliminary API draft study that estimated the marginal 
cost of drilling per foot of measured depths (lengths) drilled for 
sidetracks. However, because of very different methodologies (e.g., the 
wells and sidetracks in the API study were drilled to all depths, and 
API used a statistical approach compared to the engineering model MMS 
used), the results are not directly comparable.
    MMS identified a mathematical function for a sidetrack RSV which 
would result in approximately equal value of the RSV relative to the 
cost of drilling sidetracks and original wells on a before- and after-
royalty relief basis. That is, the ratio of expected drilling costs net 
of royalty relief for both well types would be the same as the ratio 
based on drilling costs alone. This equivalence assures that drilling 
decisions are not distorted between well types by the royalty relief 
program.
    The functional form for sidetrack relief that MMS derived is this: 
the RSV is equal to 4 BCF plus 0.06 BCF per 100 feet of measured depth 
drilled, i.e., sidetrack length. The sidetrack relief is limited to the 
amount an original deep well could earn if produced in the same lease 
circumstances, i.e., up to 15 BCF for the first deep well produced 
between 15,000-18,000 feet TVD SS (the ``shallower depth category'') or 
up to 25 BCF for the first deep well produced 18,000 feet TVD SS or 
deeper (the ``deeper depth category''). In cases where deep production 
has already

[[Page 3502]]

occurred on the lease from the shallower depth category, drilling and 
producing a sidetrack in the deeper depth category can earn the full 
sidetrack RSV amount, but again, no more than an original well could 
earn in the same situation, equal to 10 BCF.
    As discussed further below, sidetrack drilling can also generate a 
royalty suspension supplement (RSS) for an unsuccessful well under the 
same circumstances as an original unsuccessful well that has a 
perforated interval in the 18,000 foot TVD SS or deeper interval, with 
one additional condition, namely the sidetrack length must be at least 
10,000 feet (measured depth). This requirement is imposed to preclude 
any incentive to drill short distances simply to earn an RSS. As with 
original wells, the sidetrack RSS is equal to 20 percent of the RSV 
that would have been earned by a successful sidetrack subject to a 
limit of 5 BCF, which is the RSS that would have been earned by an 
unsuccessful original well drilled to 18,000 feet TVD SS or deeper.

7. Production Start-Up Requirements

    Comments: Five years is too short a time to explore and produce 
deep gas reserves, especially if drilling to deep depths must be from 
means other than an existing platform or if there is a need to build a 
pipeline (BP, Noble). Five years is not long enough to conduct 
activities and start production given the existing technological 
challenges (API). Provide for an extension on a case-by-case basis, 
when additional time for activities is justified (NOIA). Revise the 
rule to allow royalty relief for any otherwise qualified deep well if 
that well subsequently produces. This would account for unavoidable 
delays for weather, rig installations, and other reasons largely beyond 
the fault of the operator (El Paso).
    Response: For leases issued beginning in 2001 with deep gas royalty 
relief provisions in the lease terms, the lessee must begin production 
from a deep well within 5 years of lease issuance. MMS believes it 
would be unfair to allow more than 5 years from the date of the final 
rule to begin production from a qualified well on leases many of which 
are further advanced in development than leases issued beginning in 
2001. MMS therefore is allowing 5 years from the effective date of the 
final rule. MMS believes it is important to strongly encourage 
accelerated production, not just drilling, given the current state of 
the domestic natural gas market.
    Nevertheless, in the interest of fairness, MMS has decided to allow 
some flexibility to extend this deadline for up to 1 year if MMS 
determines that the reasons for the delay are beyond the operator's 
control. For MMS to consider an extension, the operator has to 
demonstrate that he drilled to total depth within 5 years, that the 
delay through no fault of the operator occurred after reaching total 
depth, and that production otherwise could reasonably have been 
expected to commence within 5 years.

8. Unitization Comments and MMS Responses

    Comment: One comment indicated that the proposed rule offered 
``confusion and ambiguity'' about the treatment of unit and non-unit 
deep wells on the same lease. Specifically, it indicated that Sec. 
203.41(b)(3)(ii) is not only confusing but it seems ambiguous in that 
you could have a ``first successful qualified deep well on your lease'' 
when there is already another deep well ``on your lease'' (Noble).
    Response: The referenced Sec. deals with a lease that has both a 
unitized and non-unitized area within the lease. The language in the 
proposed rule stated that a lease, whether or not it is in a unit, 
earns an RSV only by drilling a qualified well, and that a subsequent 
deep well on that lease or any other leases in the unit does not earn 
an additional RSV for that lease. In other words, production is 
allocated among the leases in a unit; the royalty suspension volumes 
are not. This feature has not changed under the final rule. A related 
provision of the proposed rule--that the first qualified well on that 
lease determines that lease's final RSV--has been modified in the final 
rule.
    The final rule adds the proviso that if the first qualified well is 
drilled to the shallower drilling depth category (15,000-18,000 feet 
TVD SS) and a subsequent qualified well is drilled to the deeper 
drilling depth category (at least 18,000 feet TVD SS), then the RSV 
earned by the lease will be increased pursuant to Sec. 203.41(b).
    MMS has rewritten the parts of Sec.Sec. of 203.41 and 42 dealing 
with unitized and non-unitized wells on the same lease in two ways to 
clarify their meaning. A qualified well drilled in the unitized or non-
unitized portion of the lease, after the first qualified well on a 
lease, earns for the lease an increased RSV only if it is drilled to a 
deeper depth category. Further, both the production from any qualified 
well on the non-unitized portion of the lease and the production 
allocated to the lease from qualified unit wells, will share in that 
lease's RSV.
    Comment: The unitization proposal may actually provide a 
disincentive to drill wells on a unit basis. For example, if two leases 
are combined on a 50/50 basis to form a unit to test a prospect at 
17,000 feet and it is anticipated that only one well will be necessary, 
the unit owners could conclude that the discovered reserves would have 
to be at least 30 BCF to allow each to receive the full incentive 
versus 15 BCF if the prospect were on one lease only (Noble).
    Response: The rule provides an RSV as an incentive to drill a deep 
well. In the example, if the prospect was only on one lease, the 
owner(s) would get an RSV of 15 BCF for the deep well. If the prospect 
overlaps two unit leases, and one deep well is drilled, again the rule 
only provides one RSV of 15 BCF that goes to the lease with the deep 
well.
    MMS's customary unitization policy affects the use of lease-based 
deep gas royalty relief in two ways. First, when a deep well penetrates 
a new reservoir and proves to be commercially producible, unit co-
owners typically will revise the existing participating area for that 
reservoir based on available geological information. (The participating 
area percentages may be revised in light of the results of subsequent 
drilling activities.) Production from the reservoir will be allocated 
according to the participating area percentages. Because of this rule, 
MMS will require unit co-owners to establish a separate participating 
area for reservoirs produced by one or more qualified wells. The 
percentage allocated to a lease with a qualified well producing from 
that participating area will be subject to the RSV for that lease.
    Second, in the case where all the unitized leases have shallow 
wells but only one lease has a qualified well located in a reservoir 
that geological information indicates is common with all the leases, 
the unitized leases without a qualified well will receive allocated 
production from the qualified well and royalty will be due on this 
production. Only deep well production allocated to the unitized lease 
with the qualified well would be royalty-free. In the example described 
in the comment if the well qualifies for deep gas relief, then it is 
accurate to say that production from the well must be at least 30 BCF 
for the lease with the qualifying well to receive the entire 15 BCF of 
relief.
    To resolve the problem of not getting the relief as soon as 
possible in the above example, MMS stated at the Deep Gas Royalty 
Relief Workshop in Houston, Texas on April 30, 2003, that it would 
consider not allocating deep production for royalty purposes to a 
unitized lease without a qualifying well. Since this deep depth 
allocation would diverge from the way shallow depth production on the 
same unit is allocated

[[Page 3503]]

for royalty purposes and from the way production is allocated from both 
shallow and deep wells for units without deep gas relief, MMS discarded 
this idea as an unnecessary source of confusion and administrative 
complexity. Therefore, for the final rule, MMS has decided not to 
revise its customary unitization policy. The unit working interest 
owners could still allocate production and share benefits under 
separate agreements to offset any imbalances they perceive from royalty 
relief going only to the unit participant with the deep well.
    Comment: MMS is promoting the drilling of unnecessary wells in 
order for all leases in a unit to receive royalty relief. For example, 
suppose a four-lease unit exists, but only the lease with the 
completion receives the royalty suspension volume. The remaining three 
un-drilled leases do not share in the royalty suspension volume. The 
reservoir can be efficiently drained without drilling extra wells, but 
the un-drilled leases won't be entitled to any royalty free production 
on their allocated share of production unless they drill unnecessary 
wells. Allow the MMS the discretion to grant royalty suspensions for 
each lease in the unit after determining a successful well is not 
necessary to be drilled on each lease in the unit to develop 
efficiently the discovered reservoir (ChevronTexaco, Noble).
    Response: The rule provides an incentive to drill a deep well. The 
RSV was based on the cost of a single deep well. Under the approach 
suggested in the comment, the owners could receive four RSV's (60 to 
100 BCF) as an incentive for drilling one deep well, which is far more 
relief than the program intended.
    Also, the proposal in the comment would require a reservoir 
interpretation and analysis by MMS. To avoid differences of opinion in 
this area, MMS considered and rejected a potential requirement for new 
leases issued beginning in 2001 that the deep well must produce from a 
new reservoir, i.e., one that has not previously produced on any 
current lease. If MMS decided to utilize reservoir interpretations and 
analyses as proposed in the comment, then MMS would be inclined to 
include this ``new'' reservoir requirement in the regulation. In that 
event, the unitized leases in the example without a deep well would not 
be eligible for an RSV even with the drilling of a deep well into the 
reservoir. Furthermore, without subsurface well control on the three 
leases, MMS would not make a determination about whether or not 
additional deep wells are necessary for efficient development of the 
discovered reservoir.
    Finally, as in the previous unit comment and response, unit co-
owners may agree separately to adjustments to share the royalty relief 
benefits.
    Comment: Another comment recommended that in any unit the RSV 
should be allocated in proportion to the royalty obligations in the 
unit agreement (API).
    Response: MMS carefully considered and rejected this approach for 
several reasons. In some cases, the RSV cannot be allocated like 
production. A number of units contain State or Federal leases not 
eligible for deep gas royalty relief. Ineligible Federal leases in a 
unit might include those leases in water deeper than 200 meters or with 
deep well production from a well with a perforated interval the top of 
which is at least 18,000 feet TVD SS before March 26, 2003. Other units 
may contain leases issued after January 1, 2001, which have deep gas 
royalty relief with different magnitudes and lease provisions.
    Using the lease-based approach also results in significantly less 
administrative burden. If the RSV were allocated, several allocations 
beyond the initial allocation may be needed--for example, if a new well 
leads to a change in the acre-feet shares assigned to each 
participating lease. Also, if royalty relief were allocated, the 
drilling of the first qualified well on each unitized lease would 
require a separate calculation of the remaining RSV and a reallocation 
of the revised suspension volume. In addition, when production data is 
updated, ``look-backs'' would be needed to confirm the accuracy of the 
reallocation or make necessary adjustments.

9. Price Thresholds

    Comments: Raise the threshold or eliminate it to reduce or remove 
uncertainty about the availability of royalty relief. Don't count 
production against the RSV in periods when the price threshold is 
exceeded by actual prices (Noble). Price thresholds incur reporting and 
accounting difficulties and add complexity and uncertainty (Marathon). 
We believe price thresholds should be avoided. When prices are rising, 
lessees should be afforded the full suite of available incentives to 
meet demand. To eliminate the incentive in the face of tightening 
supplies is exactly the opposite of what should be done. Given the 
expectation of falling prices, lessees could time production and 
thereby delay drilling to periods of future royalty relief. With May 
2003 prices above the threshold, there is no incentive to drill deep 
gas this year (Pioneer). The price thresholds impose barriers to 
effectively stimulate deep gas exploration and development. Accounting 
rules preclude royalty relief that might have to be paid back from 
being included in company income statements. To reduce investor 
uncertainty, do not count production against the RSV when prices exceed 
the threshold. Allow royalty relief up to the threshold price, and pay 
royalties on the extra revenues generated above the threshold price (El 
Paso).
    Response: At the time MMS was preparing the proposed rule, natural 
gas prices were in the range of $3.50 per MMBtu. During the summer of 
2003, as MMS prepared the final rule, natural gas prices were in the 
range of $5.50 per MMBtu, i.e., above the threshold price levels 
expected for 2003. The price threshold level suggested in the proposed 
rule was based on price expectations that prevailed at that time, on 
historic price volatility, and on revenue considerations. That is, the 
level was set so that the loss of royalty relief occasioned by higher-
than-expected gas prices would be more than offset by the higher 
realized gas prices. Since that time, however, gas prices have surged 
and EIA projections for future average gas prices have risen as well. 
Moreover, we've noted a distinct pattern for gas prices to show 
considerably more volatility in recent years compared to historic 
trends. As a result, we conducted an in-depth analysis to determine 
whether the incremental production effects of the deep gas royalty 
relief program would be adversely influenced by retention of this 
earlier proposed price threshold formulation. This analysis 
incorporates the important influence that price volatility can have on 
the drilling incentive and on royalty collections. The results, 
provided in the economic analysis to this rulemaking, showed that there 
would be significant degradation in incremental program benefits from 
retention of the price threshold formulation offered in the proposed 
rule.
    The current expectations for the gas market are for higher, more 
volatile future prices compared to earlier expectations reflected in 
the proposed rule. The higher prices should lead to increased demand 
for drilling equipment and larger capital expenditures for exploration 
and production of additional gas supply. However, supply of capital 
equipment generally does not respond as quickly as demand, leading to 
increased prices for costs of acquiring the needed capital equipment to 
expand production. As a

[[Page 3504]]

result, OCS operators may not fully benefit from increased natural gas 
prices when such increases are rapid and may not be sustained.
    The incentive provided by this rule remains a significant tool to 
promote deep and costly drilling regardless of market prices. These 
revised base cases and incremental outcomes have been incorporated in 
the economic analysis and demonstrate the continued viability of relief 
and the need to adjust the price threshold formulation.
    In light of these observations, MMS concludes that (1) the previous 
revenue relationships may not apply in the current circumstances, and 
(2) the effect of the higher gas prices on drilling decisions may be 
dampened in the short term by the proposed price thresholds, and (3) 
despite added supplies offered at higher prices, program benefits from 
providing royalty relief in the amount, form, and time described in 
this rule remain substantial. Accordingly, MMS agrees with the comments 
that some response is needed to modify the price thresholds in light of 
the current and revised expectations about future gas market 
conditions.
    The final rule revises the original price threshold provision by 
raising the market price level which suspends royalty relief from $5 
per MMBtu (expressed in year 2000 dollars) to $9.34 per MMBtu 
(expressed in year 2004 dollars). When expressed in same year dollars, 
this represents a 70 percent increase in the price threshold. The 
threshold price rises at the full increase in inflation in subsequent 
years. MMS compared incremental production and forgone royalty 
estimates for a variety of price thresholds using a calculation that 
accounts for the effects price volatility can have on the incentive. 
The specific revised price threshold level now chosen poses a small 
risk that the price threshold will be exceeded. However, if this price 
threshold is violated, then the forgone royalty would be substantially 
less, in part because gas prices would be so high. Because the chance 
of violation is low, the chosen policy should have only a minor effect 
on drilling and discoveries compared to the absence of a threshold 
while adequately protecting taxpayers from lost revenue should gas 
prices escalate more than now expected. The economic analysis for this 
rulemaking examines a variety of different price threshold options.

10. Scope of Royalty Relief for Leases

    Comment: Allow royalty relief in the proposed amounts by block, not 
lease (McMoran, El Paso).
    Response: Please see responses to comment numbers seven and eight. 
The royalty relief program MMS designed is lease-based. Because the 
offshore oil and gas program is administered mostly by lease, the 
lease'based formulation of royalty relief allows for a convenient 
interface with the existing regulatory structure. Moreover, under this 
stipulation almost all shallow water leases are subject to similar 
provisions of deep drilling royalty relief.
    In contrast, there were only 72 leases (1 percent) having more than 
one block, and only 9 leases with more than 2 blocks in the summer of 
2003. In almost all cases, the extra blocks were only portions of 
normal size blocks where it was most practical to combine into one 
lease for bidding in a lease sale. Thus, the lease area for most 
multiple block leases is close to that for single block leases. In the 
unique case where a lease contains several blocks and is significantly 
larger than a normal lease, further relief may be appropriate under the 
special case royalty relief provision (30 CFR 203.80). Modification of 
the program to accommodate relief on a block basis is not appropriate.

11. Defining Drilling Depth Interval Requirements

    Comment: Utilize drilling depth to a pre-defined target instead of 
to the top of the perforated interval to define the classification of a 
deep well. Otherwise, the definition in the proposed rule may encourage 
poor decisions on completion activities in order to qualify for relief 
(Pioneer).
    Response: ``Drilling depth to a pre-defined target'' is an 
uncertain measure because seismic data are used to define the drilling 
objective. In contrast, the ``top of the perforated interval'' is an 
exact measurement of the location of productive hydrocarbons.
    Moreover, MMS believes that the differences between the proposed 
and suggested definitions will have significance for royalty relief in 
only a limited number of cases, for instance, where the reservoir 
target happens to straddle the 15,000 foot TVD SS or the 18,000 TVD SS 
depth. MMS further believes that in those few cases, operators will 
base their completion decisions on sound engineering practices and will 
be reluctant to qualify their wells by making poor completion 
decisions.
    To remove some uncertainty, the final rule is explicit about the 
treatment of the RSV in the situation where a single well involves 
multiple leases. Where a (directional or sidetrack) deep well begins on 
one lease but is completed on a second lease, then the production from, 
and any royalty relief earned by, the qualified well belongs to the 
second lease. If the qualified well has separate perforated intervals 
(either of which would qualify) on two leases, then the lease with the 
perforated interval that produces first earns the royalty suspension 
volume. Finally, if the perforated interval of the qualified well 
extends across two leases, then the lease where the surface of the well 
is located earns the RSV. These procedures avoid allocating or doubling 
up on RSV and are consistent with the treatment of royalty relief in a 
unit situation.

12. Ultra-Deep Depth Drilling Category

    Comment: The bulk of deep gas drilling opportunities is below 
20,000 feet TVD SS. MMS should provide at least an RSV of 45 BCF for 
successful drilling to this depth (BP). We would like to see a third 
tier of relief for ultra-deep drilling. Many companies believe the real 
targets of opportunity lie below 20,000 feet TVD SS. The difference in 
cost to drill 18,000 feet versus 20,000 feet TVD SS is dramatic. We 
think an RSV of 35 BCF is appropriate (NOIA). We support an RSV of 35 
BCF for drilling below 20,000 feet TVD SS (Noble, Rowan, Marathon).
    Response: The anticipated royalty savings associated with drilling 
a qualified very deep well successfully, i.e., to at least 18,000 feet 
TVD SS, is more than $20 million at gas prices in the summer of 2003. 
MMS believes an incentive of this size is appropriate at this time for 
accelerating drilling below 18,000 feet TVD SS, as well as below 20,000 
feet TVD SS. The fact is that very little drilling has taken place so 
far at either drilling depth in shallow water. Data since 1998 show 249 
deep wells were drilled. Of these, 17 percent were to at least 18,000 
feet and 7 percent to at least 20,000 feet. Overall the success rate 
was 8 percent, although it was higher at the ultra-deep interval. 
Because of the sparse data, it is difficult to predict accurately the 
true chances of drilling success, the potential size of discoveries, 
the cost of drilling in ultra-deep depths, and thus the additional 
production likely from an increment to the available RSV. Moreover, 
adding this third tier of relief will complicate the regulatory 
requirements and delay publication of the final rule. MMS will continue 
to consider the need for granting increased royalty relief for ultra-
deep wells, but it is premature to do so in this rule.

13. Auction Mechanism

    Comments: The industry was unanimous in its opposition to a bidding 
system offered for possible future use that would serve to distribute 
the rights to deep gas royalty relief.

[[Page 3505]]

These rights would have to be acquired before drilling of a designated 
nature, such as discussed in this final rule, could become eligible to 
earn royalty relief. Regardless of whether the bid variable was a cash 
bonus or the RSV (or RSS) amount itself, comments indicated that such a 
system could have perverse and unintended consequences.The system would 
appear to benefit primarily those wells that would be drilled anyway 
(BP). It would defeat the purpose of the rule by denying relief to 
those who need it most and it would delay drilling and reduce the 
number of total wells drilled (NOIA). Winning bidders would not 
necessarily use the property rights acquired to drill deep wells 
(Rowan). It introduces uncertainty that could inhibit planning 
activities necessary for deep drilling success (Exxon). The program has 
no benefit and numerous pitfalls that could undermine the deep drilling 
initiative (Marathon). The bidding system would not accelerate 
development of deep gas (El Paso). The system could eliminate certain 
lessees from competing for the incentives (ChevronTexaco).
    Response: MMS recognizes that adoption of a bidding system to 
distribute royalty relief is, at best, premature. Typically, an auction 
is an efficient mechanism to ensure that the item being sold goes to 
the party that values the item most highly, and in conjunction with 
enough competition, yields a fair return to the seller. As envisioned, 
the MMS proposed auction would result in the government forgoing the 
same total amount of royalty payments as expected for this rule, but 
may result in more drilling by awarding less royalty relief to those 
companies that need a smaller incentive, therefore freeing up a larger 
quantity of relief to be allocated to those companies that would 
require more relief than is granted in this rule to undertake deep 
drilling.
    Unlike this rule, which essentially allocates the same quantity of 
relief regardless of actual need, in theory there should be an auction 
framework capable of allocating variable amounts of royalty relief 
based on need. MMS recognizes that the ability of an auction mechanism 
to achieve this goal would depend on, among other considerations, a 
design framework that could discourage a bidding scenario in which 
relief is allocated to those who need it least, and awarded to those 
least likely to utilize it. An auction procedure with these 
characteristics has not yet been developed; hence more research is 
needed in this area. So, implementation of the deep gas royalty relief 
program will proceed without an auction feature.

Procedural Matters

Regulatory Planning and Review (Executive Order 12866)

    According to the criteria in Executive Order 12866, this rule is a 
significant regulatory action for which a Regulatory Analysis has been 
prepared. The Office of Management and Budget (OMB) has made that 
determination under Executive Order 12866.
    (1) The preferred alternative adopted in this rule will have an 
economic effect of $100 million or more by reducing consumer 
expenditures on natural gas by about $500 million each year and may 
have a slightly adverse effect on other units of government. An 
economic analysis of this regulatory action was prepared and will be 
available at http//www.mms.gov/econ. This rule reduces royalties for 
lessees that drill and produce natural gas from deep wells in shallow 
water areas of the GOM. The RSV's offered should increase deep drilling 
activity on existing leases over the period of the program and make 
additional resources economic. The deep gas royalty suspensions are 
likely to reduce net Federal royalty collections. MMS's best estimate 
of this reduction is from $150 to $220 million in net present value 
over a 16-year period, depending on gas price volatility.
    The royalty relief program for deep gas drilling will have two 
distinct effects: (1) recovery of some otherwise uneconomic gas 
resources, and (2) accelerated recovery of some marginally economic gas 
resources. MMS data indicate that about 10-20 percent of the 
undiscovered gas resources in the most prospective depths, i.e., 18,000 
TVD SS or deeper, could be converted from unprofitable to profitable by 
the incentives provided in this rule. MMS estimates that those 
resources are located in approximately 20-30 percent of undiscovered 
gas reservoirs.
    MMS estimates that about one-fourth of the economically explorable 
gas reservoirs at drilling depths 18,000 feet TVD SS or deeper would be 
drilled 1-5 years sooner if the proposed rule is implemented. These 
reservoirs are associated with less than 10 percent of the undiscovered 
resource. MMS estimates that application of the program to undiscovered 
gas resources at depths 18,000 feet TVD SS or deeper could increase 
production of gas by over two TCF. Application of MMS's proposed 
program to reservoirs in the 15,000 to less than 18,000-foot TVD SS 
range of drilling depth could affect another 1-2 TCF of gas. The deep 
drilling program will affect only a part of these resources in any one 
year.
    (2) This rule will not create any inconsistencies with actions by 
other agencies because royalty relief is confined to leasing in Federal 
offshore waters that lie outside the coastal jurisdiction of State and 
other local agencies. Careful review of the lease sale notices, along 
with stringent leasing policies now in force, ensures that the Federal 
OCS leasing program, of which royalty relief is only a component, does 
not conflict with the work of other Federal agencies.
    (3) This rule has no effect on entitlements, grants, user fees, 
loan programs, or their recipients. However, the rule does have the 
effect of postponing distributions of royalty revenue. MMS distributes 
about 1 percent ($40 million) of the OCS revenue it collects annually 
in the GOM to neighboring States under Section 8(g) of the OCSLA. 
Royalty suspensions from the deep gas program could affect up to 5 
percent of the total production from the GOM in any one year. If deep 
gas production occurs in the 8(g) zone at the same proportion as 
elsewhere in the GOM, these State distributions could be reduced by $1 
to $2 million per year for 5-10 years. However, extra production that 
occurs because of the incentive will also provide extra royalties, 
mostly after the RSVs have been produced. Given uncertainty about the 
number, location, and size of deep gas discoveries, it is even possible 
that the extra royalties could fully offset the initial drop in both 
Federal and State royalties. This would occur if our program generates 
25 percent more incremental gas resources than the most likely scenario 
evaluated in the Economic Analysis.
    (4) This rule raises a novel legal or policy issue. The RSS for an 
unsuccessful deep gas well expands the scope of royalty relief to 
reward efforts for exploration in frontier well depths whether or not 
they eventually produce. As explained in the preamble to the Proposed 
Rule (68 FR 14868), MMS believes this creates a more cost-effective 
royalty relief program compared to one that only rewards success in 
this very risky environment. Also as explained in the economic analysis 
accompanying the proposed rule, several features of the rule 
essentially eliminate any moral hazard potential of the RSS.
    In addition, RSV's have been used for several years as an incentive 
to accelerate exploration and production in deep-water. Application to 
deep gas is a logical extension of that policy. A well-defined program 
for deep gas drilling is more administratively efficient than the 
elaborate case-by-case

[[Page 3506]]

requirements of the application process for deep-water royalty relief. 
The focus here is on a straightforward definition of well depth and 
circumstances to qualify for royalty relief.
    MMS developed an economic analysis of this regulatory action in 
accordance with requirements for a major rule under OMB and statutory 
criteria. This analysis describes why market forces alone will not 
increase deep gas development in the short term, considers possible 
royalty relief alternatives to serve that need, and analyzes the social 
benefits and costs and related transfer payments associated with 
several royalty suspension alternatives. Two options provide the 
highest level of added production and net social benefits:
    A. The RSV in this final rule of 15 BCF for successful wells to 
15,000-18,000 feet TVD SS and 25 BCF for successful wells (or 5 BCF for 
unsuccessful wells) to 18,000 feet TVD SS or deeper depths, plus 
reduced amounts for deep sidetracks and for deeper wells on leases that 
have deep wells, and
    B. As in option A, but limiting RSV to 10 BCF for successful wells 
to 15,000-18,000 feet TVD SS and to 20 BCF for successful wells (or 5 
BCF for unsuccessful wells) to 18,000 feet TVD SS or deeper.
    These two options were selected over other alternatives considered 
in the proposed rule that included higher suspension levels as a 
substitute for royalty relief for unsuccessful drilling.
    MMS ranked alternatives based on estimates of their net social 
benefits. Net social benefits are the sum of the net gains to producers 
and consumers associated with the additional production attributable to 
this rule. These gains are measured as changes in consumer and producer 
surplus compared to a status quo or baseline amount that would occur in 
the absence of the incentive. Consumer surplus is the difference 
between the value consumers place on the additional production and its 
market value. Producer surplus is the difference between the market 
price and the cost of additional production (including the cost of 
drilling unsuccessful wells). Transfer payments, on the other hand, 
consist primarily of changes resulting from the rule in the amount of 
Federal royalty payments and domestic expenditures to purchase status 
quo quantities of gas. This summary reviews the performance of the 
superior options based on several criteria: added production, forgone 
royalty, and net social benefits from production that would not have 
occurred without an incentive for deep gas drilling. The comparison of 
alternative incentive levels reported below were made with updated EIA 
gas price forecasts but omit the dampening effects of a potentially 
binding price threshold. The relative effect of alternative price 
threshold options is largely independent of the RSV level and hence 
plays little, if any, role determining the choice between alternative 
levels of the RSV.
    MMS estimates that option A, the royalty suspension level adopted 
in the final rule, would generate a cumulative added production of 3.8 
TCF of gas and 0.81 TCFE of condensate over the next 16 years (before 
considering the slight dampening effect a potentially binding price 
threshold may have on incremental production). In contrast, option B 
would generate added production of 3.3 TCF of gas and 0.71 TCFE of 
condensate over the same time frame (again ignoring the price threshold 
effect). Added production consists of production from reservoirs 
unlikely to be drilled under normal conditions and from a portion of 
reservoirs only likely to be drilled in the future after information, 
technology, and costs improve, i.e., accelerated production.
    Using assumptions about prices, discount rates, and well flow 
rates, MMS estimated the net social benefits to society from increased 
deep gas production. As discussed above, this primary measure of social 
welfare effects eliminates the sizeable transfers from producers to 
consumers associated with reduced prices, and from government to 
producers in the form of reduced royalty payments. The incremental 
supply added to domestic stocks as a result of the incentive generates 
a net gain to society. Under option A, the adopted incentive, MMS 
estimates a net social gain of $290 million in present value versus 
$238 million under option B.
    Comparing increased production to forgone royalty-bearing 
production provides another perspective on the effects of the rule. MMS 
estimates that royalty would be forgone under option A on 2.8 TCFE of 
gas and oil production that would have occurred anyway. That implies a 
ratio of extra production to forgone royalty-bearing production of 1.64 
[(3.8 TCF + 0.8 TCFE)/2.8 TCF]. For option B, this ratio is also 1.74 
[(3.3 TCF + 0.7 TCFE)/2.3 TCF]. Hence, either of these deep gas 
incentive options is preferable to no such incentive.
    Some of the forgone royalty would be offset by royalty collections 
on the condensate and on added gas production after the royalty 
suspensions have been used. Taking those into account and distributing 
the production over the next 16 years, MMS estimates a net reduction in 
present value of royalty receipts of $227 million under the proposal 
versus $37 million for the second alternative. These results suggest 
that option B provides only about 85 percent of the production effects 
and the net social benefits of option A. Option B costs only about 20 
percent of the forgone royalty revenues as option A.

Regulatory Flexibility (RF) Act

    MMS chose the incentive form that combines an RSV for successful 
deep gas wells and an RSS for unsuccessful deep wells for three 
reasons:
    (1) It is large enough to generate substantial deep drilling 
activity;
    (2) It is the most cost-effective incentive structure for the 
Government because it does not waste as much relief as alternatives on 
prospects that will be drilled anyway; and
    (3) It concentrates most of the incentive on the very deep (18,000 
feet or deeper subsurface) zones where MMS believes most of the 
undiscovered potential is to be found.
    A detailed analysis of the small business impacts and alternatives 
considered can be found in the economic analysis of this regulation 
which is available at http://www.mms.gov/econ.
    Companies that extract oil, gas, or natural gas liquids, or are 
otherwise in oil and gas exploration and development activities and 
operate leases on the OCS, will be most affected by this rule. Of the 
approximately 130 such companies active offshore in the GOM, we 
estimate that as many as 91 (70 percent) companies qualify as small 
firms.
    Because this program is administered on a categorical rather than 
an application basis, minimal administrative time and cost is needed to 
qualify for royalty relief. Since no special analysis or independent 
review would be necessary to accomplish these compliance activities, 
MMS sees very little burden on normal operations of either small or 
large companies. For this rule, paperwork costs are only \1/10\ of 1 
percent of benefits and are the minimal cost necessary to allow for the 
monitoring essential to a consistent administration of this program 
across all participants. While administrative costs are the same for 
all the categorical incentive alternatives, the benefits are different. 
The alternative MMS chose results in the largest benefit to producers 
and to the small entity share of producers. Further, two reasons (risk 
sharing and location advantages) suggest that small OCS entities could 
get a

[[Page 3507]]

disproportionate share of the large benefits of this rule.
    The RSS feature improves the ability of small companies with 
limited drilling programs to spread their risk. Success on one or two 
of many deep wells that a large operator drills in a given period can 
pay the costs incurred for the unsuccessful wells. Small operators may 
be able to drill only one or two deep wells in a given period. The RSS 
can reduce the net cost of unsuccessful deep wells immediately, so the 
small operator does not necessarily have to wait for a deep well 
success in a later period to offset at least some unsuccessful 
exploration costs. This is a feature not found in any of the 
alternative categorical incentive structures which confer royalty 
relief only on successful wells.
    Because of the risk, high cost, and technical complexity, MMS 
expects most lessees/operators involved in exploration and development 
in deep drilling depths of the GOM to be large companies. However, the 
location eligible for deep gas royalty relief is in shallow water, 
where one expects to find relatively more small operators compared to 
those found in deep water. Thus, relatively more of those OCS operators 
who will benefit from the deep gas incentive in this rule may be in the 
small business category than those who benefit from deep-water royalty 
relief. For these reasons MMS believes this rule is likely to provide 
at least a proportionate share of its benefits to small businesses. 
Compliance guides to assist both small and large entities, including 
the presentation slides used in the industry workshop held in April, 
2003 and the summary Table 1 from this document, will be available on 
the MMS website for the duration of this program.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

    This rule is a major rule under 5 U.S.C. 804(2), the SBREFA. This 
rule:
    (1) Does have an annual effect on the economy of $100 million or 
more. This rule introduces a royalty relief program for deep gas that 
will save consumers $500 million annually for about a decade, of which 
about $19 million is a gain in consumer surplus attributed to 
additional gas consumption. Also, there is a gain in producer surplus 
of over $12 million annually that otherwise would not have occurred as 
well as additional industry employment. The change from the status quo 
in royalty collected by the Federal government under the revised 
rulemaking would exceed the $100 million per year threshold in 10 out 
of 16 years in which meaningful amounts of program-related production 
are generated. This incentive will cause Federal royalty to be reduced 
by more than $100 million during each of about 5 years early in the 
program and to be increased by more than $100 million during each of 
about 5 years late in the program. The benefits of the rule on the 
economy more than offset the net royalty losses. A comparison of two 
types of production provides a proxy measure of this net social 
benefit. MMS estimates the magnitude of new gas production that 
ultimately occurs because of the incentive in the rule is about 1.5 
times the size of gas production on which the government forgoes 
royalty. The government only forgoes royalty on that portion of 
production that would have occurred anyway without the incentive. 
Moreover, consumers of natural gas will benefit from additional 
domestic gas supplies and have lower market prices.
    More lessees may take advantage of the new deep gas royalty relief 
provisions over the next few years than have ever applied for end-of-
life or deep-water royalty relief. However, the incremental drilling 
and production induced by this royalty relief will be small relative to 
total gas drilling and production in the GOM. The main thrust of the 
initiative is to increase and help accelerate new gas production to 
promote timely production otherwise inhibited. Even a small moderation 
of prices due to added deep gas production would result in a 
significant savings in gas expenditures and dampen natural gas prices 
in the market. Further, the rule would impose no costs on any local or 
private entity, but may initially impose some small costs ($1 to $2 
million per year) on Gulf Coast States in the form of reduced payments 
under section 8(g) of the OCSLA. However, production that otherwise 
would not occur will result from these incentives. That production will 
produce extra royalty payments, mostly after the RSV has been produced. 
Participation in the program by lessees is voluntary.
    MMS considers the key adverse economic effect of this program, with 
regard to the $100 million dollar annual benchmark, to be forgone 
Federal royalties on deep gas production that would have been generated 
without this program. Lower royalties mean more taxable income to 
companies. However, the results cited in the discussion accompanying 
this rule measure the effect on forgone Federal revenues without 
consideration of tax receipt increases. Note that this is a transfer 
payment in that the government loss is also an operator gain from 
pursuing a socially desirable activity--deep gas production.
    MMS forecasts that without the deep gas royalty relief program, 53 
wells would be drilled annually to depths of 15,000-18,000 feet TVD SS 
and 24 wells to drilling depths below 18,000 feet TVD SS. Based on 
trends in drilling deep depths during the past 10 years in shallow 
water, MMS would expect 18 successful wells in the 15,000-18,000 feet 
TVD SS drilling depth and five successful wells at deep drilling depths 
18,000 feet TVD SS or deeper without the incentive. With the incentive, 
MMS estimates there would be 62 wells drilled to depths 18,000 feet TVD 
SS or deeper, of which 49 would be unsuccessful, and 33 of them on 
leases having other production to which the RSS could be applied. In 
both drilling depths, some of these wells will be sidetracks or deeper 
wells on leases with deep production that qualifies them for a reduced 
royalty suspension.
    Over the 2003-2009 period, the absence of this deep gas royalty 
relief program would save the government about 470 BCF in new RSV and 
RSS awarded for drilling activities that would have occurred anyway. 
These savings may decline before the program ends in about 2009 because 
of the availability of less prospective reservoirs in later years of 
the program. Further, in any one year, only about 20-25 percent of the 
accrued amount of RSV and RSS could actually be used.
    Offsetting most of these initial royalty losses are the extra 
royalties from two sources: (a) the condensate portion of production 
from the added deep gas wells and (b) gas production in later years 
beyond the RSV from additional reserves discovered because of the 
incentive. Along with the additional 38 new wells (62-24) drilled 
annually to depths 18,000 feet TVD SS or deeper, MMS expects an 
additional 18 new wells (71-53) would be drilled annually to depths of 
15,000-18,000 feet TVD SS. MMS estimates that these incremental wells 
ultimately would lead to gas production of about 3.8 TCF, of which 1.4 
TCF would be royalty-free and 2.3 TCF would be royalty-bearing. MMS 
anticipates that the royalties on this 2.3 TCF of gas production would 
begin in 2008 and continue until about 2020. A further offsetting 
benefit also comes from extra private profits from production that 
would otherwise not occur. A detailed economic analysis of this 
regulatory action was prepared and will be available at www.mms.gov/econ. This economic analysis explains our monetary calculations.
    (2) Will not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, or local government 
agencies, or

[[Page 3508]]

geographic regions. The deep gas incentive should materially moderate 
expected gas prices by adding to the overall supply.
    (3) Does not have significant adverse effects on competition, 
employment, investment, innovation, or the ability of U.S.-based 
enterprises to compete with foreign-based enterprises. Companies 
eligible for the deep gas royalty relief should produce more natural 
gas and earn more income, while encountering no negative effects.

Paperwork Reduction Act (PRA) of 1995

    MMS examined the proposed rule and these final regulations under 
section 3507(d) of the PRA. Because of the changes to the current 30 
CFR part 203 regulations, MMS submitted the information collection (IC) 
requirements of this rule to OMB for approval as part of the proposed 
rulemaking process. The IC requirements in the final regulations remain 
unchanged from the proposed rule, and a new submission to OMB is not 
required.
    The PRA provides that an agency may not conduct or sponsor, and a 
person is not required to respond to, a collection of information 
unless it displays a currently valid control number. OMB approved the 
additional requirements to collect information under revisions to 30 
CFR part 203 under OMB control number 1010-0153, current expiration 
date of April 30, 2006. When this final rule becomes effective, MMS 
plans to roll these IC requirements into those already approved for 30 
CFR part 203 (OMB control number 1010-0071).
    MMS uses the information collected in this final rule, 30 CFR 
203.40 through 203.48, to determine whether a lessee has fulfilled the 
drilling and production requirements or exercised an option to earn the 
royalty relief offered to deep gas wells under this part. These 
decisions have enormous monetary impacts to both the lessee and the 
Federal Government. Royalty relief can lead to increased production of 
natural gas and oil, creating profits for lessees and possible royalty 
and tax revenues for the government that they might not otherwise 
receive. MMS uses industry notification of drilling intent and 
production to determine eligibility of the lease to receive royalty 
relief. The well data collected enables MMS to confirm that a well was 
an unsuccessful well and that the lessee is eligible for the RSS 
offered in the program.
    The title of this collection of information is ``30 CFR Part 203, 
Deep Gas Provisions.'' The frequency of response is occasional. 
Respondents include approximately 130 Federal OCS oil and gas lessees 
and operating rights holders. Responses are required to obtain or 
retain a benefit. The IC does not include questions of a sensitive 
nature. MMS protects information considered proprietary under 
applicable law and 30 CFR 250.196.
    The following table lists the new IC requirements and respective 
burdens for this rule. The approved annual burden of this collection of 
information is 361 hours. Based on a cost factor of $50 per hour, the 
hour cost burden of the new paperwork requirements would be $18,050. 
There are no non-hour cost burdens in the final regulations.

                                           Table 3.--Burden Breakdown
----------------------------------------------------------------------------------------------------------------
                                                                                                         Annual
 30 CFR 203  section       Reporting requirement           Hour burden             Annual number         burden
                                                                                                         hours
----------------------------------------------------------------------------------------------------------------
43(a) 46(a)..........  Notify MMS of intent to       1 hour.................  89 notices.............         89
                        begin drilling.
43(b)(1)(2)..........  Notify MMS that production    2 hours................  25 notices.............         50
                        has begun and request
                        confirmation of the size of
                        RSV.
46(b)(1)(2)..........  Provide data from well to     8 hours................  19 submissions.........        152
                        confirm and attest well
                        drilled was an unsuccessful
                        certified well and request
                        supplement.
48(b)................  Notify MMS of decision to     2 hours................  35 notices.............         70
                        exercise option to replace
                        one set of deep gas royalty
                        suspension terms for
                        another set of such terms.
 
----------------------------------------------------------------------------------------------------------------

    You may 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, Minerals 
Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 
20240.

Federalism (Executive Order 13132)

    According to Executive Order 13132, this rule does not have 
meaningful Federalism implications. As noted above, it may initially 
have some small consequences ($1 to $2 million a year) on Gulf Coast 
States in the form of reduced payments under section 8(g) of the OCSLA. 
However, additional resources discovered under this incentive will make 
up for these initial reductions from production that otherwise would 
not occur. Largely after the RSV's have been produced, extra royalties 
and payments for Federal and Gulf Coast States will result from this 
extra production. Also, the added economic activity in those States 
associated with new deep drilling will generate new tax revenues. 
Therefore, a Federalism assessment is not required because the rule 
would not have a direct or substantive effect on the relationship 
between the Federal and State Governments, nor does it impose 
responsibilities or costs on States or localities.

Takings Implication Assessment (Executive Order 12630)

    According to Executive Order 12630, the rule does not have 
significant takings implications; therefore a Takings Implication 
Assessment is not required. This rule has no takings effect because it 
only specifies circumstances under which royalty payments to the 
Federal Government by OCS lessees might be reduced. MMS believes that 
the lessee of such a lease would be better off financially under this 
rule than in the absence of it.

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

    This rule is a significant rule and is subject to review by OMB 
under Executive Order 12866. This rule does not have a significant 
adverse effect on energy supply, distribution, or use. This rule 
increases and accelerates the production of gas from deep wells in 
shallow waters of the GOM by providing for an RSV for successful deep 
production and an RSS for unsuccessful deep drilling efforts, so it has 
a positive

[[Page 3509]]

effect on energy supply based on our regulatory analysis.

Unfunded Mandates Reform Act (UMRA) of 1995

    This rule does not impose an unfunded mandate on State, local, or 
tribal governments or the private sector of more than $100 million per 
year. The rule does not have any Federal mandates nor does the rule 
have a significant or unique effect on State, local, or tribal 
governments or the private sector. A statement containing the 
information required by the UMRA (2 U.S.C. 1531 et seq.) is not 
required.

Civil Justice Reform (Executive Order 12988)

    According to Executive Order 12988, the Office of the Solicitor has 
determined that the rule does not unduly burden the judicial system and 
meets the requirements of Sections 3(a) and 3(b)(2) of the Order.

National Environmental Policy Act (NEPA) of 1969

    This rule does not constitute a major Federal action significantly 
affecting the quality of the human environment. A detailed statement 
under the NEPA is not required.

Consultation and Coordination With Indian Tribal Governments (Executive 
Order 13175)

    In accordance with Executive Order 13175, this rule does not have 
tribal implications that impose substantial direct compliance costs on 
Indian tribal governments.

List of Subjects in 30 CFR Part 203

    Continental shelf, Government contracts, Indian lands, Minerals 
royalties, Oil and gas exploration, Public lands-mineral resources, 
Reporting and recordkeeping requirements, Sulphur.

    Dated: October 7, 2003.
Rebecca W. Watson,
Assistant Secretary--Land and Minerals Management.

0
For the reasons stated in the preamble, the Minerals Management Service 
(MMS) amends 30 CFR part 203 as follows:

PART 203--RELIEF OR REDUCTION IN ROYALTY RATES

0
1. The authority citation for part 203 continues to read as follows:

    Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 
U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 
30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701 et 
seq.; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 
1801 et seq.


0
2. The definitions for certified unsuccessful well, deep well, original 
well, participating area, qualified well, reservoir, royalty suspension 
supplement, royalty suspension volume, sidetrack, and sidetrack 
measured depth are added alphabetically to Sec. 203.0 as follows:


Sec. 203.0  What definitions apply to this part?

* * * * *
    Certified unsuccessful well means an original well, or a sidetrack 
with a sidetrack measured depth of at least 10,000 feet, on your lease 
that--
    (1) You begin drilling on or after March 26, 2003, and before March 
1, 2009, and before your lease produces gas or oil from a deep well 
with a perforated interval the top of which is at least 18,000 feet 
true vertical depth below the datum at mean sea level (TVD SS);
    (2) 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;
    (3) Fails to meet the producibility requirements of 30 CFR part 
250, subpart A, and does not produce gas or oil, or the MMS agrees is 
not commercially producible; and
    (4) For which you have provided the notices and information in Sec. 
203.46.
* * * * *
    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. A 
deep well subsequently re-perforated less than 15,000 feet TVD SS in 
the same reservoir is still a deep well.
* * * * *
    Original well means a well that is drilled without utilizing an 
existing wellbore. An original well includes all sidetracks drilled 
from the original wellbore before the drilling rig moves off the well 
location. 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 MMS 
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.
* * * * *
    Qualified well means a deep well:
    (1) For which drilling begins on or after March 26, 2003;
    (2) That produces natural gas (other than test production), 
including gas associated with oil production, before March 1, 2009; and
    (3) For which you have met the requirements prescribed in Sec. 
203.43.
* * * * *
    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 supplement means a royalty suspension volume 
resulting from drilling a certified unsuccessful well that is applied 
to future natural gas and oil production generated at any drilling 
depth on, or allocated under an MMS-approved unit agreement to, the 
same lease.
    Royalty suspension volume 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.
* * * * *

0
3. In Sec. 203.4, the introductory paragraph is revised to read as 
follows:


Sec. 203.4  How do the provisions in this part apply to differnt 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 Sec.Sec. 203.50 to 203.91. Because royalty 
relief for deep gas on leases not subject to deep water royalty relief, 
as provided for under Sec.Sec. 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.
* * * * *

0
4. A new Sec. 203.5 is added to subpart A to read as follows:


Sec. 203.5  What is MMS's authority to collect information?

    The Paperwork Reduction Act of 1995 (PRA) requires us to inform you 
that MMS may not conduct or sponsor and

[[Page 3510]]

you are not required to respond to a collection of information unless 
it displays a currently valid OMB control number. OMB approved the 
information collection requirements in this part 203 under 44 U.S.C. 
3501 et seq. in two actions. The information collection requirements in 
Sec.Sec. 203.50 through 203.91 are approved under OMB control number 
1010-0071, and those in Sec.Sec. 203.40 through 203.48 are approved 
under 1010-0153.

0
5. A new undesignated heading and new Sec.Sec. 203.40 through 203.48 
are added to subpart B to read as follows:

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


Sec. 203.40  Which leases are eligible for royalty relief as a result 
of drilling deep wells?

    Your lease may receive a royalty suspension volume under Sec.Sec. 
203.41 through 203.43, and may receive a royalty suspension supplement 
under Sec.Sec. 203.44 through 203.46, if it:
    (a) Was:
    (1) In existence on January 1, 2001;
    (2) Issued in a lease sale held after January 1, 2001 and before 
April 1, 2004 and the lessee has exercised the option provided for in 
Sec. 203.48; or
    (3) Issued in a lease sale held on or after April 1, 2004 and the 
lease terms provide for royalty relief under Sec.Sec. 203.41 through 
203.47;
    (b) Is located:
    (1) In the GOM, wholly west of 87 degrees, 30 minutes West 
longitude;
    (2) Entirely in water less than 200 meters deep, or partly in water 
less than 200 meters deep and no deep-water royalty relief provisions 
in statutes or lease terms apply to the lease; and
    (c) Has not produced gas or oil from a deep well with a perforated 
interval the top of which is 18,000 feet TVD SS or deeper that 
commenced drilling before March 26, 2003.


Sec. 203.41  If I have a qualified well, what royalty relief will my 
lease earn?

    (a) This paragraph and paragraph (b) of this section apply if your 
lease has not produced gas or oil from a deep well that commenced 
drilling before March 26, 2003. Subject to the administrative 
requirements of Sec. 203.43, the provisions of Sec. 203.44(d), and the 
price conditions in Sec. 203.47, you earn a royalty suspension volume 
shown in the following table in billions of cubic feet (BCF) or in 
thousands of cubic feet (MCF) applicable to gas production as 
prescribed in Sec. 203.42:

------------------------------------------------------------------------
                                             Then you earn a royalty
                                            suspension volume on this
 If you have a qualified well that is .    amount of gas production, as
                  . .                     prescribed in this section and
                                                   Sec. 203.42:
------------------------------------------------------------------------
(1) An original well with a perforated   15 BCF.
 interval the top of which is from
 15,000 to less than 18,000 feet TVD SS.
(2) A sidetrack with a perforated        4 BCF plus 600 MCF times
 interval the top of which is from        sidetrack measured depth
 15,000 to less than 18,000 feet TVD SS.  (rounded to the nearest 100
                                          feet) but no more than 15 BCF.
(3) An original well with a perforated   25 BCF.
 interval the top of which is 18,000
 feet TVD SS or deeper.
(4) A sidetrack with a perforated        4 BCF plus 600 MCF times
 interval the top of which is 18,000      sidetrack measured depth
 feet TVD SS or deeper.                   (rounded to the nearest 100
                                          feet) but no more than 25 BCF.
------------------------------------------------------------------------

    (b) We will suspend royalties on gas volumes produced on or after 
March 1, 2004 reported on the Oil and Gas Operations Report, Part A 
(OGOR-A) for your lease under 30 CFR 216.53, as and to the extent 
prescribed in Sec. 203.42. All gas production from qualified wells 
reported on the OGOR-A, including production that is not subject to 
royalty (except for production to which a royalty suspension supplement 
under Sec.Sec. 203.44 and 203.45 applies), counts toward the lease 
royalty suspension volume.
    Example 1. If you have a qualified well that is an original well 
with a perforated interval the top of which is 16,000 feet TVD SS, you 
earn a royalty suspension volume of 15 BCF of gas production from 
qualified wells on your lease, as prescribed in Sec. 203.42. However, 
if the top of the perforated interval is 18,500 feet TVD SS, the 
royalty suspension volume is 25 BCF.
    Example 2. If you have a qualified well that is a sidetrack with a 
perforated interval the top of which is 16,000 feet TVD SS, that has a 
sidetrack measured depth of 6,789 feet, we round the distance to 6,800 
feet and you earn a royalty suspension volume of 8.08 BCF of gas 
production from qualified wells on your lease, as prescribed in Sec. 
203.42.
    Example 3. If you have a qualified well that is a sidetrack with a 
perforated interval the top of which is 16,000 feet TVD SS, that has a 
sidetrack measured depth of 19,500 feet, you earn a royalty suspension 
volume of 15 BCF of gas production from qualified wells on your lease, 
as prescribed in Sec. 203.42, even though 4 BCF plus 600 MCF per foot 
of sidetrack measured depth equals 15.7 BCF.
    (c) This paragraph and paragraph (d) of this section apply if 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 (regardless of whether drilling began before or after March 26, 
2003), and you subsequently have a qualified well on your lease with a 
perforated interval the top of which is 18,000 feet TVD or deeper. 
Subject to the administrative requirements of Sec. 203.43, the 
provisions of Sec. 203.44(d), and the price conditions in Sec. 203.47, 
you earn a royalty suspension volume specified in the following table, 
applicable to gas production as prescribed in Sec. 203.42. This royalty 
suspension volume is in addition to any royalty suspension volume your 
lease already may have earned, if any, as a result of a qualified well 
with a perforated interval the top of which is from 15,000 to less than 
18,000 feet TVD SS.

------------------------------------------------------------------------
 If your lease has produced gas or oil
   from a deep well with a perforated        Then, you earn a royalty
   interval the top of which is from        suspension volume on this
15,000 to less than 18,000 feet TVD SS,    amount of gas production, as
 and you subsequently have a qualified    prescribed in this section and
           well that is . . .                      Sec. 203.42
------------------------------------------------------------------------
(1) An original well or a sidetrack      0 BCF.
 with a perforated interval the top of
 which is from 15,000 to less than
 18,000 feet TVD SS.

[[Page 3511]]

 
(2) An original well with a perforated   10 BCF.
 interval the top of which is 18,000
 feet TVD SS or deeper.
(3) A sidetrack with a perforated        4 BCF plus 600 MCF times
 interval the top of which is 18,000      sidetrack measured depth
 feet TVD SS or deeper.                   (rounded to the nearest 100
                                          feet) but no more than 10 BCF.
------------------------------------------------------------------------

    (d) We will suspend royalties on gas volumes produced on or after 
March 1, 2004 reported on the Oil and Gas Operations Report, Part A 
(OGOR-A) for your lease under 30 CFR 216.53, as and to the extent 
prescribed in Sec. 203.42. All gas production from qualified wells 
reported on the OGOR-A, including production that is not subject to 
royalty (except for production to which a royalty suspension supplement 
under Sec.Sec. 203.44 and 203.45 applies), counts toward the lease 
royalty suspension volume.
    Example 1. If you have drilled and produced a well with a 
perforated interval the top of which is 16,000 feet TVD SS before March 
26, 2003 (and therefore, it is not a qualified well and has earned no 
royalty suspension volume) and later drill:
    (i) A well with a perforated interval the top of which is 17,000 
feet TVD SS, you earn no royalty suspension volume.
    (ii) A qualified well that is an original well with a perforated 
interval the top of which is 19,000 feet TVD SS, you earn a royalty 
suspension volume of 10 BCF of gas production from qualified wells on 
your lease, as prescribed in Sec. 203.42.
    (iii) A qualified 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, you earn a royalty suspension volume of 
8.2 BCF of gas production from qualified wells on your lease, as 
prescribed in Sec. 203.42.
    Example 2. If you have a qualified well (i.e., drilled after March 
26, 2003) 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 royalty suspension volume for 
your lease from 15 BCF to 25 BCF, as prescribed in Sec. 203.42.
    Example 3. If you have a qualified well (i.e., drilled after March 
26, 2003) that is a sidetrack with a perforated interval the top of 
which is 16,000 feet TVD SS, that has 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, that 
has a sidetrack measured depth of 8,000 feet, we increase the total 
royalty suspension volume for your lease from 6.4 BCF to 15.2 BCF, as 
prescribed in Sec. 203.42. The difference of 8.8 BCF represents the 
royalty suspension volume earned by the second sidetrack.
    (e) After your lease has produced gas or oil from a deep well with 
a perforated interval the top of which is 18,000 feet TVD SS or deeper, 
your lease cannot earn a royalty suspension volume as a result of 
drilling any subsequent qualified wells.
    (f) The royalty suspension volume determined under this section for 
the first qualified well on your lease (whether an original well or a 
sidetrack) establishes the total royalty suspension volume available 
for that drilling depth interval on your lease, regardless of the 
number of subsequent qualified wells you drill to that depth interval.
    Example to paragraph (f): If your first qualified well is a 
sidetrack with a perforated interval the top of which is 16,000 feet 
TVD SS and earns a royalty suspension volume of 12.5 BCF, and you later 
drill a qualified original well to 17,000 feet TVD SS, the royalty 
suspension volume for your lease remains at 12.5 BCF and does not 
increase to 15 BCF. However, under paragraph (b) of this section, if 
you subsequently drill a qualified well to another depth interval 
18,000 feet or greater TVD SS, you may earn an additional royalty 
suspension volume.
    (g) If a qualified well on your lease is within a unitized portion 
of your lease, the royalty suspension volume earned by that well under 
this section applies only to your lease and not to other leases within 
the unit.
    (h) If your qualified 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 royalty 
suspension volume. However, if the perforated interval crosses a lease 
line, the lease where the surface of the well is located earns the 
royalty suspension volume.
    (i) Any royalty suspension volume earned under this section is in 
addition to any royalty suspension supplement for your lease under Sec. 
203.44 that results from a different wellbore.
    (j) If your lease earns a royalty suspension volume under this 
section and later produces from a deep well that is not a qualified 
well, the royalty suspension volume is not forfeited or terminated. 
However, you may not apply the royalty suspension volume under this 
section to production from the deep well that is not a qualified well, 
even if it begins producing after your first qualified well.
    (k) You owe minimum royalties or rentals in accordance with your 
lease terms notwithstanding any royalty suspension volumes allowed 
under paragraphs (a) and (b) of this section.


Sec. 203.42  To which production do I apply the royalty suspension 
volume earned from qualified wells on my lease?

    (a) This paragraph applies to any lease that is not within an MMS-
approved unit. Subject to the requirements of Sec.Sec. 203.40, 203.41, 
203.43, 203.44, and 203.47, you must apply the royalty suspension 
volumes prescribed in Sec. 203.41 to the earliest gas production:
    (1) Occurring on and after the later of March 1, 2004 or the date 
that the first qualified well that earns your lease the royalty 
suspension volume begins production (other than test production);
    (2) From all qualified wells, regardless of their depth, on your 
lease for which you have met the requirements in Sec. 203.43, up to the 
aggregate royalty suspension volume earned by your lease.
    Example to paragraph (a): You began drilling an original well that 
was a qualified well with a perforated interval the top of which is 
18,200 feet TVD SS on May 1, 2003 and it began producing on September 
1, 2003. You subsequently drilled two more original wells that are 
qualified wells with a perforated interval the tops of which are 16,600 
feet TVD SS. The first well earned a royalty suspension volume of 25 
BCF. You must apply the royalty suspension volume each month beginning 
on March 1, 2004 to production from all three wells until the 25 BCF 
royalty suspension volume is fully utilized.
    (b) This paragraph applies to any lease all or part of which is 
within an MMS-approved unit. If your lease has a qualified well, a 
share of the production from all the qualified wells in the unit 
participating area will be allocated to

[[Page 3512]]

your lease each month according to the participating area percentages. 
Subject to the requirements of Sec.Sec. 203.40, 203.41, 203.43, 203.44, 
and 203.47, you must apply the royalty suspension volume to the 
earliest gas production occurring on and after the later of March 1, 
2004 or the date that the first qualified well that earns your lease 
the royalty suspension volume begins production (other than test 
production):
    (1) From all qualified wells on the non-unitized area of your lease 
and
    (2) Allocated to your lease from qualified wells on unitized areas 
of your lease and other leases in the unit under an MMS-approved unit 
agreement. That allocated share does not increase the royalty 
suspension volume 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 to paragraph (b): The east half of your lease A is unitized 
with all of lease B. There is one qualified well on the non-unitized 
portion of lease A, one qualified well on the unitized portion of lease 
A and a qualified well on lease B. The participating area percentages 
allocate 32 percent of production from both of the unit qualified wells 
to lease A and 68 percent to lease B. If the non-unitized qualified 
well on lease A produces 12,000 MCF and the unitized qualified well on 
lease A produces 15,000 MCF, and the qualified well on lease B produces 
10,000 MCF, then the production volume from and allocated to lease A to 
which the lease A royalty suspension volume applies is 20,000 MCF 
[12,000 + (15,000 + 10,000)(32 percent)]. The production volume 
allocated to lease B to which the lease B royalty suspension volume 
applies is 17,000 MCF [(15,000 + 10,000)(68 percent)].
    (c) Unused royalty suspension volume transfers to a successor 
lessee and expires with the lease.
    (d) You may not apply the royalty suspension volume allowed under 
Sec. 203.41:
    (1) 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;
    (2) To production from a deep well that commenced drilling before 
March 26, 2003; or
    (3) To production from a deep well on any other lease, except as 
provided in paragraph (b) of this section.
    (e) 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 
royalty suspension volume allowed under Sec. 203.41. For the month in 
which cumulative production reaches this royalty suspension volume, you 
owe royalties on the portion of gas production that exceeds the royalty 
suspension volume remaining at the beginning of that month.
    (f) No royalty suspension volume may be applied to any liquid 
hydrocarbon (oil and condensate) volumes.


Sec. 203.43  What administrative steps must I take to use the royalty 
suspension volume?

    (a) You must notify, in writing, the MMS Regional Supervisor for 
Production and Development of your intent to begin drilling operations 
on all 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 MMS 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 MMS Regional Supervisor for 
Production and Development has determined are necessary under 30 CFR 
part 250, subpart L.
    (d) If you produced from a qualified well before March 1, 2004, you 
must provide the information in paragraph (b) of this section no later 
than June 1, 2004.
    (e) If you cannot produce from a well that otherwise meets the 
criteria for a qualified well before March 1, 2009, the MMS Regional 
Supervisor for Production and Development may extend the deadline for 
beginning production for up to 1 year, based on the circumstances of 
the particular well involved, provided you demonstrate that:
    (1) The delay occurred after reaching total depth in your well;
    (2) Production (other than test production) was expected to begin 
before March 1, 2009; and
    (3) The delay in beginning production is for reasons beyond your 
control, including but not limited to adverse weather and unavoidable 
accidents.


Sec. 203.44  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 
Sec. 203.41.
    (a) If you drill a certified unsuccessful well and you satisfy the 
administrative requirements of Sec. 203.46 and subject to the price 
conditions in Sec. 203.47, you earn a royalty suspension supplement 
shown in the following table (in billions of cubic feet of gas 
equivalent (BCFE) or in thousands of cubic feet of gas equivalent 
(MCFE)) applicable to oil and gas production as prescribed in Sec. 
204.45:

------------------------------------------------------------------------
                                             Then, you earn a royalty
                                          suspension supplement on this
  If you have a certified unsuccessful        volume of oil and gas
           well that is . . .              production as prescribed in
                                          this section and Sec. 203.45:
------------------------------------------------------------------------
(1) An original well and your lease has  5 BCFE.
 not produced gas or oil from a deep
 well.
(2) A sidetrack (with a sidetrack        0.8 BCFE plus 120 MCFE times
 measured depth of at least 10,000        sidetrack measured depth
 feet) and your lease has not produced    (rounded to the nearest 100
 gas or oil from a deep well.             feet) but no more than 5 BCFE.
(3) An original well or a sidetrack      2 BCFE.
 (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.
------------------------------------------------------------------------

    (b) We will suspend royalties on oil and gas volumes produced on or 
after March 1, 2004 reported on the Oil and Gas Operations Report, Part 
A (OGOR-A) for your lease under 30 CFR 216.53, as and to the extent 
prescribed in Sec. 203.45. All oil and gas production reported on the 
OGOR-A, including production that is not subject to royalty (except for 
production to which a royalty suspension volume under Sec.Sec. 203.41 
and 203.42 applies), counts

[[Page 3513]]

toward the lease royalty suspension supplement.
    Example 1. If you drill a certified unsuccessful well that is an 
original well to a target 19,000 feet TVD SS, you earn a royalty 
suspension supplement of 5 BCFE of gas and oil production if your lease 
has not previously produced from a deep well, or you earn a royalty 
suspension supplement of 2 BCFE of gas and oil production if your lease 
has previously produced from a deep well with a perforated interval 
from 15,000 to less than 18,000 feet TVD SS, as prescribed in Sec. 
203.45.
    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, we round the distance to 12,500 
feet and you earn a royalty suspension supplement of 2.3 BCFE of gas 
and oil production as prescribed in Sec. 203.45.
    (c) The conversion from oil to gas for using the royalty suspension 
supplement is specified in Sec. 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 a royalty suspension supplement 
as a certified unsuccessful well later produces from a perforated 
interval the top of which is 15,000 feet TVD SS or deeper before March 
1, 2009, it will become a qualified well subject to the following 
conditions:
    (1) Beginning on the date production starts, you must stop applying 
the royalty suspension supplement earned by that wellbore to your lease 
production.
    (2) If the completion of this qualified well is on your lease or, 
in the case of a directional well, is on another lease, then you must 
subtract from the royalty suspension volume earned by that qualified 
well the royalty suspension supplement amounts earned by that wellbore 
that have already been applied either on your lease or any other lease. 
The difference represents the royalty suspension volume earned by the 
qualified well.
    (f) If the same wellbore that earned a royalty suspension 
supplement later has a sidetrack drilled from that wellbore, you are 
not required to subtract any royalty suspension supplement earned by 
that wellbore from the royalty suspension volume that may be earned by 
the sidetrack.
    (g) You owe minimum royalties or rentals in accordance with your 
lease terms notwithstanding any royalty suspension supplements under 
this section.


Sec. 203.45  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 Sec.Sec. 203.40, 203.42, 203.44, 
203.46 and 203.47, you must apply royalty suspension supplements in 
Sec. 203.44 to the earliest oil and gas production:
    (1) Occurring on and after the day you file the information under 
Sec. 203.46(b),
    (2) From, or allocated under an MMS-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 
Sec. 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 royalty 
suspension supplement allowed under Sec. 203.44, your royalty 
suspension supplement applies to the earliest subsequent production of 
gas and oil from, or allocated under an MMS-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 royalty suspension supplement allowed 
under Sec. 203.44 to production from any other lease, except for 
production allocated to your lease from an MMS-approved unit agreement. 
If your certified unsuccessful well is on a lease subject to an MMS-
approved unit agreement, the lessees of other leases in the unit may 
not apply any portion of the royalty suspension supplement 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 an MMS-approved unit 
agreement to, your lease (excluding any gas produced from qualified 
wells subject to a royalty suspension volume allowed under Sec. 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.


Sec. 203.46  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 
MMS 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 MMS Regional 
Supervisor for Production and Development within 60 days after reaching 
the total depth in your well:
    (1) Information that allows MMS to confirm that you drilled a 
certified unsuccessful well as defined under Sec. 203.0, including:
    (i) Well log data, if your original well or sidetrack does not meet 
the producibility requirements of 30 CFR part 250, subpart A; or
    (ii) Well log, well test, seismic, and economic data, if your well 
does meet the producibility requirements of 30 CFR part 250, subpart A; 
and
    (2) Information that allows MMS 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 or after March 26, 2003, 
and finished it before March 1, 2004, provide the information in 
paragraph (b) of this section no later than June 1, 2004.

[[Page 3514]]

Sec. 203.47  Do I keep royalty relief if prices rise significantly?

    (a) You must pay royalties on all gas and oil production for which 
royalty suspension volume or royalty suspension supplement otherwise 
would be allowed under Sec.Sec. 203.40 through 203.46 for any calendar 
year when the average daily closing NYMEX natural gas price exceeds the 
threshold of $9.34 per MMBtu, adjusted annually after year 2004 for 
inflation. The threshold price for any calendar year after 2004 is 
found 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.
    (b) You must pay any royalty due under this paragraph, plus late 
payment interest from the end of the month after the month of 
production until the date of payment under 30 CFR 218.54, no later than 
90 days after the end of the calendar year for which you owe royalty.
    (c) Production volumes on which you must pay royalty under this 
section count as part of your royalty suspension volumes and royalty 
suspension supplements.


Sec. 203.48  May I substitute the deep gas drilling provisions in Sec. 
203.0 and Sec.Sec. 203.40 through 203.47 for the deep gas royalty 
relief provided in my lease terms?

    (a) You may exercise an option to replace the applicable lease 
terms for royalty relief related to deep-well drilling with those in 
Sec. 203.0 and Sec.Sec. 203.40 through 203.47 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 MMS 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 Sec.Sec. 203.40 through 203.47.
    (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.

[FR Doc. 04-1299 Filed 1-23-04; 8:45 am]
BILLING CODE 4310-MR-P