United States Government Accountability Office

GAO Testimony 

Before the Committee on Energy and 

Natural Resources, United States Senate

OIL AND GAS ROYALTIES

Royalty Relief Will Likely 

Cost the Government 

Billions, but the Final Costs 

Have Yet to Be Determined 

Statement of Mark E. Gaffigan, Acting Director 

Natural Resources and Environment 

For Release on Delivery

Expected at 9:30 a.m. EST 

Thursday, January 18, 2007 

 

GAO-07-369T 
What GAO Found

United States Government Accountability Office

Why GAO Did This Study

Highlights

Accountability Integrity Reliability

January 18, 2007

OIL AND GAS ROYALTIES 

Royalty Relief Will Likely Cost the 

Government Billions, but the Final Costs 

Have Yet to Be Determined 

Highlights of GAO-07-369T, a testimony 

before the Committee on Energy and 

Natural Resources, United States Senate 

Oil and gas production from federal 

lands and waters is vital to meeting

the nation’s energy needs. As such, 

oil and gas companies lease federal 

lands and waters and pay royalties 

to the federal government based on

a percentage of the oil and gas that

they produce. The Minerals 

Management Service (MMS), an 

agency in the Department of the

Interior, is responsible for 

collecting royalties from these 

leases. In order to promote oil and 

gas production, the federal 

government at times and in specific

cases has provided “royalty relief,”

waiving or reducing the royalties 

that companies must pay. However, 

as production from these leases

grows and oil and gas prices have

risen since a major 1995 royalty 

relief act, questions have emerged 

about the financial impacts of 

royalty relief. 

Based on our work to date, GAO’s 

statement addresses (1) the likely 

fiscal impacts of royalty relief on

leases issued under the Outer 

Continental Shelf Deep Water

Royalty Relief Act of 1995 and (2) 

other authority for granting royalty 

relief that could further impact

future royalty revenue. 

To address these issues our 

ongoing work has included, among 

other things, analyses of key

production data maintained by

MMS; and reviews of appropriate 

portions of the Outer Continental 

Shelf Deep Water Royalty Relief 

Act of 1995, the Energy Policy Act 

of 2005, and Interior’s regulations 

on royalty relief. 

While precise estimates remain elusive at this time, our work to date shows 

that royalty relief under the Outer Continental Shelf Deep Water Royalty

Relief Act of 1995 will likely cost billions of dollars in forgone royalty

revenue—at least $1 billion of which has already been lost. In October 2004, 

MMS estimated that forgone royalties on deep water leases issued under the 

act from 1996 through 2000 could be as high as $80 billion. However, there is

much uncertainty in these estimates. This uncertainty stems from ongoing 

legal challenges and other factors that make it unclear how many leases will

ultimately receive royalty relief and the inherent complexity in forecasting 

future royalties. We are currently assessing MMS’s estimate in light of 

changing oil and gas prices, revised estimates of future oil and gas 

production, and other factors. 

Additional royalty relief that can further impact future royalty revenues is

currently provided under the Secretary of the Interior’s discretionary 

authority and the Energy Policy Act of 2005. Discretionary programs include 

royalty relief for certain deep water leases issued after 2000, certain deep gas 

wells drilled in shallow waters, and wells nearing the end of their productive 

lives. The Energy Policy Act of 2005 mandates relief for leases issued in the

Gulf of Mexico during the five years following the act’s passage, provides 

relief for some gas wells that would not have previously qualified for royalty 

relief, and addresses relief in certain areas of Alaska. 

Royalty Relief Zones in the Gulf of Mexico 

Source: Minerals Management Service, the Department of the Interior.

www.gao.gov/cgi-bin/getrpt?GAO-07-369T.

To view the full product, including the scope 

and methodology, click on the link above. 

For more information, contact Mark Gaffigan 

at 202-512-3841 or gaffiganm@gao.gov. 
Mr. Chairman and Members of the Committee: 

We appreciate the opportunity to participate in the Committee’s hearing 

on federal royalties obtained from the sale of oil and natural gas produced 

from federal lands and waters. Oil and gas production from federal lands 

and waters is vital to meeting the nation’s energy needs, supplying about 

35 percent of all the oil and about 25 percent of all the natural gas 

produced in the United States in fiscal year 2005. Oil and gas companies 

that lease federal lands and waters agree to pay the federal government 

royalties on the resources extracted and produced from the lease. In fiscal 

year 2006, oil and gas companies received over $77 billion from the sale of

oil and gas produced from federal lands and waters, and the Minerals 

Management Service (MMS), the Department of the Interior’s (Interior) 

agency responsible for collecting royalties, reported that these companies

paid the federal government about $10 billion in oil and gas royalties. 

Clearly, such large and financially significant resources must be carefully

developed and managed so that our nation’s rising energy needs are met 

while at the same time the American people are ensured of receiving a fair 

rate of return on publicly owned resources, especially in light of the 

nation’s current and long-range fiscal challenges. 

In order to promote oil and gas production, the federal government has at 

times and in specific cases provided “royalty relief”—the waiver or 

reduction of royalties that companies would otherwise be obligated to pay. 

When the government grants royalty relief, it typically specifies the 

amounts of oil and gas production that will be exempt from royalties and 

may also specify that royalty relief is applicable only if oil and gas prices 

remain below certain levels, known as “price thresholds.” For example, 

the Outer Continental Shelf Deep Water Royalty Relief Act of 1995, also 

known as the Deep Water Royalty Relief Act (DWRRA), mandated royalty

relief for oil and gas leases issued in the deep waters of the Gulf of Mexico

from 1996 to 2000. These deep water regions are particularly costly to 

explore and develop. However, as production from these leases has 

grown, and as oil and gas prices have risen far above 1995 levels, serious 

questions have been raised about the extent to which taxpayer interests 

have been protected. These concerns were brought into stark relief when

it was learned that MMS issued leases in 1998 and 1999 that failed to 

include in the lease contracts the price thresholds above which royalty 

relief would no longer be applicable, making large volumes of oil and 

natural gas exempt from royalties and significantly affecting the amount of

royalty revenues collected by the federal government. Although leases are 

no longer issued under DWRRA, further royalty relief is currently available 

Page 1 GAO-07-369T 
under other legislation and programs, raising the prospect that the federal

government may be forgoing additional royalty revenues. 

Recently, congressional committees, the Department of the Interior’s 

Office of the Inspector General,1

 public interest groups, and the press have 

questioned whether our nation’s oil and gas royalties are being properly 

managed. Many of these entities have also amplified questions about 

whether the oil and gas industry is paying its fair share of royalties, 

especially in light of rapidly rising oil and gas prices, record industry 

profits, and a highly constrained federal budgetary environment. GAO has 

expressed similar concerns, and the U.S. Comptroller General has 

highlighted royalty relief as an area needing additional oversight by the

110th Congress.2

You asked us today to address royalty relief issues based on our ongoing 

work for this Committee. Specifically, my testimony (1) discusses the 

likely fiscal impacts of royalty relief for leases issued under the Deep 

Water Royalty Relief Act of 1995 and (2) describes other authorities for 

granting royalty relief that could further impact future royalty collections. 

To address these issues, our ongoing work has included interviews of 

MMS personnel in the Economics Division in Herndon, Virginia and the 

Gulf of Mexico OCS Region in New Orleans, Louisiana. We have collected 

and are analyzing key production data maintained by MMS and are 

examining numerous documents and studies. We are also reviewing 

appropriate portions of the Deep Water Royalty Relief Act of 1995, the 

Energy Policy Act of 2005, and Interior’s royalty relief regulations. Our 

work follows the issuance of our report last year explaining why oil and 

gas royalties have not risen at the same pace as rising oil and gas prices.3

In addition, we are conducting other work for your Committee on federal 

oil and gas royalty rates and the diligent development of federal oil and gas 

resources. Our work is being done in accordance with generally accepted 

government auditing standards. 

 1

Minerals Management Service’s Compliance Review Process, Department of the Interior

Office of the Inspector General, Report No. C-IN-MMS-0006-2006 (Washington, D.C.: 

December, 2006). 

2

Suggested Areas for Oversight for the 110th Congress, GAO-07-235R (Washington, D.C.: 

November 17, 2006). 

3

Royalty Revenues: Total Revenues Have Not Increased at the Same Pace as Rising 

Natural Gas Prices due to Decreasing Production Sold, GAO-06-786BR (Washington, D.C.:

June 21, 2006). 

Page 2 GAO-07-369T 
In summary, we have found the following: 

• Our work to date shows that the likely fiscal impact of leases issued under 

the Deep Water Royalty Relief Act of 1995 is in the billions of dollars in 

lost royalty revenues, but precise estimates of the costs are not possible at 

this time for several reasons. First, MMS’s failure to include price 

thresholds for leases issued in 1998 and 1999 along with current attempts 

to renegotiate these leases have created uncertainty about which leases 

will ultimately receive relief. MMS estimates that the failure to include 

these price thresholds during a period of higher oil and gas prices could 

cost up to $10 billion in forgone royalty revenue. To date, about $1 billion 

has already been lost. In addition, a recent lawsuit questions whether MMS 

has the authority to set price thresholds for the leases issued from 1996 

through 2000. Depending on the outcome of this litigation, MMS 

preliminary estimates indicate that this could result in up to $60 billion in 

additional forgone royalty revenue. Beyond the problematic 

implementation of the royalty relief provisions, assessing the ultimate 

fiscal impact of royalty relief is a complex task, involving inherent 

uncertainty about future production and prices. We are currently assessing 

MMS’s estimates of royalty relief costs in light of two years worth of 

additional production data and several other variables, including changing 

oil and gas prices, revised estimates of the amount of oil and gas that these 

leases are expected to produce, the availability of deep water rigs to drill 

untested leases, and the present value of these royalty payments. In 

addition, any loss in royalty revenues may be partially mitigated by the 

potential benefits of royalty relief, such as increased production or 

increased fees that companies are willing to pay the federal government to 

acquire these leases. 

• Additional royalty relief, potentially affecting future federal royalty 

collection, is offered under other programs and legislation. More 

specifically, royalty relief can be provided under two existing authorities: 

(1) the Secretary of the Interior’s discretionary authority and (2) the 

Energy Policy Act of 2005. MMS currently administers several royalty 

relief programs in the Gulf of Mexico under discretionary authority 

provided by the 1978 amendments to the Outer Continental Shelf Lands 

Act of 1953. These programs largely address royalty relief for certain 

leases issued in deep waters after 2000, certain deep gas wells drilled in 

shallow waters, and wells nearing the end of their productive lives. In 

addition, the Congress authorized additional royalty relief under 

provisions of the Energy Policy Act of 2005. Certain provisions in the 

Energy Policy Act of 2005 are similar to those in DWRRA in that they 

mandate royalty relief for leases issued in the Gulf of Mexico during the 

five years following the act’s passage. The Energy Policy Act of 2005 also 

Page 3 GAO-07-369T 
extends royalty relief to gas produced in the Gulf of Mexico from certain 

new wells that previously would not have qualified for royalty relief. Other

provisions in the act address royalty relief in areas of Alaska where there 

currently is little or no production. 

The Department of the Interior (Interior), created by the Congress in 1849, 

oversees and manages the nation’s publicly owned natural resources, 

including parks, wildlife habitat, and crude oil and natural gas resources 

on over 500 million acres onshore and in the waters of the Outer 

Continental Shelf. In this capacity, Interior is authorized to lease federal 

oil and gas resources and to collect the royalties associated with their 

production. Onshore, Interior’s Bureau of Land Management is responsible 

for leasing federal oil and natural gas resources, whereas offshore, MMS 

has leasing authority. To lease lands or waters for oil and gas exploration, 

companies generally must first pay the federal government a sum of 

money that is determined through a competitive auction. This money is 

called a bonus bid. After the lease is awarded and production begins, the 

companies must also pay royalties to MMS based on a percentage of the 

cash value of the oil and natural gas produced and sold.4

 Royalty rates for 

onshore leases are generally 12 and a half percent whereas offshore, they 

range from 12 and a half percent for water depths greater than 400 meters

to 16 and two-thirds percent for water depths less than 400 meters. 

However, the Secretary of the Interior recently announced plans to raise 

the royalty rate to 16 and two-thirds percent for most future leases issued 

in waters deeper than 400 meters. MMS also has the option of taking a

percentage of the actual oil and natural gas produced, referred to as 

“taking royalties in kind,” and selling it themselves or using it for other 

purposes, such as filling the nation’s Strategic Petroleum Reserve. 

Background 

 4

Specifically, royalties are computed as a percentage of the monies received from the sale 

of oil and gas, with the total federal royalty revenue equal to the volume sold multiplied by 

the sales price multiplied by the royalty rate. 

Page 4 GAO-07-369T 
Based on our work to date, the Deep Water Royalty Relief Act (DWRRA) 

will likely cost the federal government billions of dollars in forgone 

royalties, but precise estimates of the costs are not possible at this time for 

several reasons. First, the failure of MMS to include price thresholds in the 

1998 and 1999 leases and current attempts to renegotiate these leases has 

created uncertainty about which leases will ultimately receive relief.

Second, a recent lawsuit is questioning whether MMS has the authority to 

set price thresholds for the leases issue from 1996 through 2000. The

outcome of this litigation could dramatically affect the amount of forgone 

revenues. Finally, assessing the ultimate fiscal impact of royalty relief is an

inherently complex task, involving uncertainty about future production 

and prices. In October 2004, MMS preliminarily estimated that the total 

costs of royalty relief for deep water leases issued under the act could be 

as high as $80 billion, depending on which leases ultimately received relief. 

MMS made assumptions about several conditions when generating this 

estimate and these assumptions need to be updated in 2007 to more 

accurately portray potential losses. In addition, the costs of forgone 

royalties need to be measured against any potential benefits of royalty 

relief, including accelerated drilling and production of oil and gas 

resources, increased oil and gas production, and increased fees that 

companies are willing to pay through bonus bids for these leases. 

The Congress passed DWRRA in 1995, when oil and gas prices were low 

and production was declining both onshore and in the shallow waters of 

the Gulf of Mexico. The act contains provisions to encourage the 

exploration and development of oil and gas resources in waters deeper 

than 200 meters lying largely in the western and central planning areas of 

the Gulf of Mexico. The act mandates that royalty relief apply to leases 

issued in these waters during the five years following the act’s passage—

from November 28, 1995 through November 28, 2000. 

As a safeguard against giving away all royalties, two mechanisms are 

commonly used to ensure that royalty relief is limited and available only

under certain conditions. The first mechanism limits royalty relief to 

specified volumes of oil and gas production called “royalty suspension 

volumes,” which are dependent upon water depth. Royalty suspension 

volumes establish production thresholds above which royalty relief no 

longer applies. That is, once total production for a lease reaches the 

suspension volume, the lessee must begin paying royalties. Royalty 

suspension volumes are expressed in barrels of oil equivalent, which is a 

term that allows oil and gas companies to combine oil and gas volumes 

into a single measure, based on the relative amounts of energy they 

The Deep Water 

Royalty Relief Act Will 

Likely Cost the 

Federal Government 

Billions of Dollars in 

Forgone Royalty 

Revenues, but Precise 

Estimates Remain 

Elusive 

Implementing Royalty 

Relief Has Been 

Problematic and Resulted 

In Unanticipated Costs 

Page 5 GAO-07-369T 
contain.5

 The royalty suspension volumes applicable under DWRRA are as 

follows: (1) not less than 17.5 million barrels of oil equivalent for leases in 

waters of 200 to 400 meters, (2) not less than 52.5 million barrels of oil 

equivalent for leases in waters of 400 to 800 meters, and (3) not less than 

87.5 million barrels of oil equivalent for leases in waters greater than 800 

meters. Hence, there are incentives to drill in increasingly deeper waters. 

Before 1994, companies drilled few wells in waters deeper than 500 

meters. MMS attributes additional leasing and drilling in deep waters to 

the passage of these incentives but also cites other factors for increased 

activity, including improved three-dimensional seismic surveys, some key

deep water discoveries, high deep water production rates, and the 

evolution of deep water development technology. 

After the passage of DWRRA, uncertainty existed as to how royalty 

suspension volumes would apply. Interior officials employed with the 

department when DWRRA was passed said that they recommended to the 

Congress that the act should state that royalty suspension volumes apply 

to the production volume from an entire field. However, oil and gas 

companies paying royalties under the act interpreted the royalty 

suspension volumes as applying to individual leases within a field. This is 

important because an oil and gas field commonly consists of more than 

one lease, meaning that if royalty suspension volumes are set for each 

lease within a field rather than for the entire field, companies are likely to 

owe fewer royalties. For example, if a royalty suspension volume is based 

on an entire field composed of three leases, a company producing oil and 

gas from a 210 million barrel-oil field—-where the royalty suspension 

volume is set at 100 million—-would be obligated to pay royalties on 110 

million barrels (210 minus 100). However, if the same 210-million barrel 

field had the same suspension volume of 100 million barrels applied to 

each of the three leases, and 70 million barrels were produced from each 

of the three leases, no royalties would be due because no lease would have 

exceeded its royalty suspension volume. After passage of the act, MMS 

implemented royalty relief on a field-basis and was sued by the industry. 

Interior lost the case in the Fifth Circuit Court of Appeals.6

 In October 

2004, MMS estimated that this decision will cost the federal government up 

to $10 billion in forgone future royalty revenues. 

 5

One barrel of oil equals one barrel of oil equivalent. One thousand cubic feet of gas (mcf)

is converted to barrels of oil equivalent by dividing it by 5.62.

6

Santa Fe Snyder Corp. v. Norton, 385 F.3d 884 (5th Cir. 2004). 

Page 6 GAO-07-369T 
A second mechanism that can be used to limit royalty relief and safeguard 

against giving away all royalties is the price threshold. A price threshold is 

the price of oil or gas above which royalty relief no longer applies. Hence,

royalty relief is allowed only so long as oil and gas prices remain below a 

certain specified price. At the time of the passage of DWRRA, oil and gas 

prices were low—West Texas Intermediate, a key benchmark for domestic 

oil, was about $18 per barrel, and the average U.S. wellhead price for 

natural gas was about $1.60 per million British thermal units. In an attempt 

to balance the desire to encourage production and ensure a fair return to 

the American people, MMS relied on a provision in the act which states 

that royalties may be suspended based on the price of production from the 

lease. MMS then established price thresholds of $28 per barrel for oil and

$3.50 per million British thermal units for gas, with adjustments each year 

since 1994 for inflation, that were to be applied to leases issued under 

DWRRA. 

As with the application of royalty suspension volumes, problems arose 

with the application of these price thresholds. From 1996 through 2000—

the five years after passage of DWRRA—MMS issued 3,401 leases under 

authority of the act. MMS included price thresholds in 2,370 leases issued 

in 1996, 1997, and 2000 but did not include price thresholds in 1,031 leases 

issued in 1998 and 1999. This failure to include price thresholds has been 

the subject of congressional hearings and investigations by Interior’s 

Office of the Inspector General. In October 2004, MMS estimated that the 

cost of not including price thresholds on the 1998 and 1999 leases could be 

as high as $10 billion. MMS also estimated that through 2006, about $1 

billion had already been lost. To stem further losses, MMS is currently 

attempting to renegotiate the leases issued in 1998 and 1999 with the oil 

and gas companies that hold them. To date, MMS has announced 

successful negotiations with five of the companies holding these leases 

and has either not negotiated or not successfully negotiated with 50 other 

companies. 

In addition to forgone royalty revenues from leases issued in 1998 and 

1999, leases issued under DWRRA in the other three years—1996, 1997, 

and 2000—are subject to losing royalty revenues due to legal challenges 

regarding price thresholds. In 2006, Kerr McGee Corporation sued MMS 

over the application of price thresholds to leases issued between 

November 28, 1995 and November 28, 2000, claiming that the act did not

authorize Interior to apply price thresholds to those leases. 7

 MMS 

 7

Kerr-McGee (Andarko) suit 3/17/06, W.Dist. LA, CV06-0439LC

Page 7 GAO-07-369T 
estimated in October 2004 that if price thresholds are disallowed for the 

leases it issued in 1996, 1997, and 2000, an additional $60 billion in royalty 

revenue could be lost. 

Trying to predict the fiscal impacts of royalty relief is a complex and timeconsuming task involving considerable uncertainty. We reviewed MMS’s 

2004 estimates and concluded that they had followed standard engineering 

and financial practices and had generated the estimates in good faith. 

However, any analysis of forgone royalties involves estimating how much 

oil and gas will be produced in the future, when it will be produced, and at 

what prices. While there are standard engineering techniques for 

predicting oil and gas volumes that will eventually be recovered from a 

lease that is already producing, there is always some level of uncertainty 

involved. Predicting how much oil and gas will be recovered from leases 

that are capable of producing but not yet connected to production 

infrastructure is more challenging but certainly possible. Predicting 

production from leases not yet drilled is the most challenging aspect of 

such an analysis, but there are standard geological, engineering, and 

statistical methods that can shed light on what reasonably could be 

expected from the inventory of 1996 through 2000 leases. Overall, the 

volume of oil and gas that will ultimately be produced is highly dependent 

upon price and technology, with higher prices and better technology 

inducing greater exploration, and ultimately production, from the 

remaining leases. Future oil prices, however, are highly uncertain, as 

witnessed by the rapidly increasing oil and gas prices over the past several

years. It is therefore prudent to assess anticipated royalty losses using a 

range of oil and gas prices rather than a single assumed price, as was used 

in the MMS estimate. 

Given the degree of uncertainty in predicting future royalty revenues from 

deepwater oil and gas leases, we are using current data to carefully 

examine MMS’s 2004 estimate that up to $80 billion in future royalty 

revenues could be lost. There are now two additional years of production

data for these leases, which will greatly improve the accuracy of 

estimating future production and its timing. We are also examining the 

impact of several variables, including changing oil and gas prices, revised 

estimates of the amount of oil and gas that these leases were originally 

expected to produce, the availability of deep water rigs to drill untested 

leases, and the present value of royalty payments.

To fully evaluate the impacts of royalty relief, one must consider the 

potential benefits in addition to the costs of lost royalty revenue. For 

Assessing the Fiscal 

Impact of Royalty Relief Is 

Inherently Complex 

Page 8 GAO-07-369T 
example, a potential benefit of royalty relief is that it may encourage oil 

and gas exploration that might not otherwise occur. Successful 

exploration could result in the production of additional oil and gas, which

would benefit the country by increasing domestic supplies and creating 

employment. While GAO has not assessed the potential benefits of royalty 

relief, others have, including the Congressional Budget Office (CBO) in 

1994, and consultants under contract with MMS in 2004.8

 The CBO 

analysis was theoretical and forward-looking and concluded that the likely 

impact of royalty relief on new production would be very small and that 

the overall impact on federal royalty revenues was also likely to be small.

However, CBO cautioned that the government could experience 

significant net losses if royalty relief was granted on leases that would 

have produced without the relief. The consultant’s 2004 study stated that 

potential benefits could include increases in the number of leases sold, 

increases in the number of wells drilled and fields discovered, and 

increases in bonus bids—the amount of money that companies are willing 

to pay the federal government for acquiring leases. However, questions 

remain about the extent to which such benefits would offset the cost of 

lost royalty revenues. 

Although leases are no longer issued under the Deep Water Royalty Relief

Act of 1995, royalty relief can be provided under two existing authorities: 

(1) the Secretary of the Interior’s discretionary authority and (2) the 

Energy Policy Act of 2005. The Outer Continental Shelf Lands Act of 1953,

as amended, granted the Secretary of the Interior the discretionary 

authority to reduce or eliminate royalties for leases issued in the Gulf of 

Mexico in order to promote increased production. The Secretary’s 

exercising of this authority can effectively relieve the oil and gas producer 

from paying royalties. MMS administers several royalty relief programs in 

the Gulf of Mexico under this discretionary authority. MMS intends for 

these discretionary programs to provide royalty relief for leases in deep 

waters that were issued after 2000, deep gas wells located in shallow 

waters, wells nearing the end of their productive lives, and special cases 

not covered by other programs. The Congress also authorized additional 

royalty relief under the Energy Policy Act of 2005, which mandates relief 

Additional Programs 

and Legislation 

Authorize Royalty 

Relief, Potentially 

Affecting Future 

Federal Royalty 

Collection 

 8 Waiving Royalties for Producers of Oil and Gas from Deep Waters, Congressional 

Budget Office, May 1994. Effects of Royalty Incentives for Gulf of Mexico Oil and Gas 

Leases, P.K. Ashton, L.O. Upton III, and M.H. Rothkopf, under Contract No. 0103CT71722, 

U.S. Department of the Interior, Minerals Management Service, Economics Division, 

Herndon, VA, OCS Study 2004-077. 

Page 9 GAO-07-369T 
for leases issued in the Gulf of Mexico during the five years following the

act’s passage, provides relief for some wells that would not have 

previously qualified for royalty relief, and addresses relief in certain areas 

of Alaska. 

Under discretionary authority, MMS administers a deep-water royalty 

relief program for leases that it issued after 2000. This program is similar 

to the program that DWRRA mandated for leases issued during the five 

years following its passage (1996 through 2000) in that royalty relief is 

dependent upon water depth and applicable royalty suspension volumes. 

However, this current program is implemented solely under the discretion

of MMS on a sale-by-sale basis. Unlike under DWRRA, the price thresholds 

and the water depths to which royalty relief applies vary somewhat by 

lease sale. For example, price thresholds for leases issued in 2001 were 

$28 per barrel for oil and $3.50 per million British thermal units for natural 

gas, with adjustments for inflation since 2000. As of March 2006, MMS 

reported that it issued 1,897 leases with royalty relief under this 

discretionary authority, but only 9 of these leases were producing. 

To encourage the drilling of deep gas wells in the shallow waters of the 

Gulf of Mexico, MMS implements another program, the “deep gas in 

shallow water” program, under final regulations it promulgated in January

2004. MMS initiated this program to encourage additional production after 

noting that gas production had been steadily declining since 1997. To

qualify for royalty relief, wells must be drilled in less than 200 meters of 

water and must produce gas from intervals below 15,000 feet. The program 

exempts from royalties from 15 to 25 billion cubic feet of gas per well. 

According to MMS’s analysis, these gas volumes approximate the smallest 

reservoirs that could be economically developed without the benefit of an

existing platform and under full royalty rates. In 2001, MMS reported that

the average size of 95 percent of the gas reservoirs below 15,000 feet was 

15.7 billion cubic feet, effectively making nearly all of this production 

exempt from royalties had it been eligible for royalty relief at that time.9

This program also specifies a price threshold for natural gas of $9.91 per 

million British thermal units in 2006, substantially exceeding the average 

NYMEX futures price of $6.98 for 2006, and ensuring that all gas 

production is exempt from royalties in 2006. 

MMS Currently 

Administers Royalty Relief 

Using Discretionary 

Authority 

 9

The average of the other 5 percent was 105 billion cubic feet, and these reservoirs are

within the highly productive Norphlet Trend.

Page 10 GAO-07-369T 
Finally, MMS administers two additional royalty relief programs in the 

Gulf of Mexico under its discretionary authority. One program applies to 

leases nearing the end of their productive lives. MMS intends that its 

provisions will encourage the production of low volumes of oil and gas 

that would not be economical without royalty relief. Lessees must apply 

for this program under existing regulations. MMS administers another 

program for special situations not covered by the other programs. Lessees 

who believe that other more formal programs do not provide adequate 

encouragement to increase production or development can request royalty

relief by making their case and submitting the appropriate data. As of 

March 2006, no leases were receiving royalty relief under the “end of 

productive life,” and only three leases were receiving royalty relief under 

the “special situations” programs. 

The Congress authorized additional royalty relief under the Energy Policy 

Act of 2005. Royalty relief provisions are contained in three specific 

sections of the act, which in effect: (1) mandate royalty relief for deep 

water leases sold in the Gulf of Mexico during the five years following 

passage of the act, (2) extend royalty relief in the Gulf of Mexico to deep

gas produced in waters of more than 200 meters and less than 400 meters, 

and (3) specify that royalty relief also applies to certain areas off the shore 

of Alaska. In the first two situations, the act specifies the amount of oil 

and/or gas production that would qualify for royalty relief and provides 

that the Secretary may make royalty relief dependent upon market prices. 

Section 345 of the Energy Policy Act of 2005 mandates royalty relief for 

leases located in deep waters in the central and western Gulf of Mexico 

sold during the five years after the act’s passage. Similar to provisions in 

DWRRA, specific amounts of oil and gas are exempt from royalties due to 

royalty suspension volumes corresponding to the depth of water in which 

the leases are located. However, production volumes are smaller than 

those authorized under DWRRA, and this specific section of the Energy 

Policy Act clearly states that the Secretary may place limitations on 

royalty relief based on market prices. For the three sales that MMS 

conducted since the passage of the act, MMS included prices thresholds 

establishing the prices above which royalty relief would no longer apply.

These price thresholds were $39 per barrel for oil and $6.50 per million 

British thermal units for gas, adjusted upward for inflation that has 

occurred since 2004. The royalty-free amounts, referred to as royalty 

suspension volumes, are as follows: 5 million barrels of oil equivalent per 

lease between 400 and 800 meters; 9 million barrels of oil equivalent per 

lease between 800 and 1,600 meters; 12 million barrels of oil equivalent per 

The Energy Policy Act of 

2005 Authorizes Additional 

Royalty Relief 

Page 11 GAO-07-369T 
lease between 1,600 and 2,000 meters; and 16 million barrels of oil 

equivalent per lease in water greater than 2,000 meters. MMS has already 

issued 1,105 leases under this section of the act. 

Section 344 of the Energy Policy Act of 2005 contains provisions that 

authorize royalty relief for deep gas wells in additional waters of the Gulf 

of Mexico that effectively expands the existing royalty-relief program for 

“deep gas in shallow water” that MMS administers under pre-existing 

regulations. The existing program has now expanded from waters less 

than 200 meters to waters less than 400 meters. A provision within the act 

exempts from royalties gas that is produced from intervals in a well below 

15,000 feet so long as the well is located in waters of the specified depth. 

Although the act does not specifically cite the amount of gas to be exempt 

from royalties, it provides that this amount should not be less than the 

existing program, which currently ranges from 15 to 25 billion cubic feet. 

The act also contains an additional incentive that could encourage deeper 

drilling—royalty relief is authorized on not less than 35 billion cubic feet 

of gas produced from intervals in wells greater than 20,000 feet deep. The

act also states that the Secretary may place limitations on royalty relief 

based on market prices. 

Finally, the Energy Policy Act of 2005 contains provisions addressing 

royalty relief in Alaska that MMS is already providing. Section 346 of the 

act amends the Outer Continental Shelf Lands Act of 1953 by authorizing 

royalty relief for oil and gas produced off the shore of Alaska. MMS has 

previously included royalty relief provisions within notices for sales in the 

Beaufort Sea of Alaska in 2003 and 2005. All of these sales offered royalty

relief for anywhere from 10 million to 45 million barrels of oil, depending 

on the size of the lease and the depth of water. Whether leases will be 

eligible for royalty relief and the amount of this royalty relief is also 

dependent on the price of oil. There currently is no production in the 

Beaufort Sea. Although there have been no sales to date under this 

provision of the act, MMS is proposing royalty relief for a sale in the 

Beaufort Sea in 2007. Section 347 of the Energy Policy Act also states that 

the Secretary may reduce the royalty on leases within the Naval Petroleum 

Reserve of Alaska in order to encourage the greatest ultimate recovery of 

oil or gas or in the interest of conservation. Although this authority already 

exists under the Naval Petroleum Reserves Production Act of 1976, as 

amended, the Secretary must now consult with the State of Alaska, the 

North Slope Borough, and any Regional Corporation whose lands may be 

affected. 

Page 12 GAO-07-369T 
In order to meet U.S. energy demands, environmentally responsible 

development of our nation’s oil and gas resources should be part of any 

national energy plan. Development, however, should not mean that the 

American people forgo a reasonable rate of return for the extraction and

sale of these resources, especially in light of the current and long-range 

fiscal challenges facing our nation, high oil and gas prices, and record 

industry profits. Striking a balance between encouraging domestic 

production in order to meet the nation’s increasing energy needs and 

ensuring a fair rate of return for the American people will be challenging. 

Given the record of legal challenges and mistakes made in implementing 

royalty relief to date, we believe this balance must be struck in careful 

consideration of both the costs and benefits of all royalty relief. As the 

Congress continues its oversight of these important issues, GAO looks 

forward to supporting its efforts with additional information and analysis 

on royalty relief and related issues. 

Mr. Chairman, this concludes my prepared statement. I would be pleased

to respond to any questions that you or other Members of the Committee 

may have at this time. 

For further information about this testimony, please contact me, Mark 

Gaffigan, at 202-512-3841 or gaffiganm@gao.gov. Contact points for our 

Offices of Congressional Relations and Public Affairs may be found on the 

last page of this statement. Contributors to this testimony include Dan 

Haas, Assistant Director; Ron Belak; John Delicath; Glenn Fischer; Frank 

Rusco; and Barbara Timmerman. 

Conclusions 

GAO Contact and 

Staff 

Acknowledgments 

Page 13 GAO-07-369T (360789) 
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