Federal Oil And Gas Management: Opportunities Exist to Improve Oversight
Published: 2009-09-16T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: In fiscal year 2008, the Department of the Interior collected over $22 billion in royalties and other fees related to oil and gas. Within Interior, the Bureau of Land Management (BLM) manages onshore federal oil and gas leases, and the Minerals Management Service's (MMS) Offshore Energy and Minerals Management (OEMM) manages offshore leases. A federal lease gives the lessee rights to explore for and develop the lease's oil and gas resources. MMS is responsible for collecting royalties for oil and gas produced from both onshore and offshore leases. GAO has reviewed federal oil and gas management and revenue collection and found many material weaknesses. This testimony is based primarily on key findings from past GAO reports and some preliminary findings from ongoing work. These findings focus on Interior's: (1) policies for oil and gas leasing, (2) oversight of oil and gas production, (3) royalty regime and policies to boost oil and gas development, (4) oil and gas information technology (IT) systems, and (5) royalty-in-kind program. GAO's past reports provided recommendations that Interior officials report that they are working to implement.
section_title: What GAO Found
paragraphs: GAO's numerous evaluations of federal oil and gas management have identified five key areas where Interior could provide greater oversight: Interior's policies for leasing offshore and onshore oil and gas differed in key ways. Specifically, MMS sets out a 5-year strategic plan identifying both a leasing schedule and the areas it would lease. In contrast, BLM relies on industry and others to nominate areas for leasing, then selected lands to lease from these nominations, as well as areas it had identified. Additionally, MMS independently assessed the value of the lease and reserves the right to reject low bids, whereas BLM relied exclusively on the results of its bid auctions to determine the lease's market value. Oil and gas activity has generally increased in recent years, and Interior has, at times, been unable to meet its legal and agency mandated oversight obligations for (1) completing required environmental inspections, (2) verifying oil and gas production, (3) using categorical exclusions to streamline environmental analyses required for certain oil and gas activities, and (4) performing environmental monitoring in accordance with land use plans. Interior may be missing opportunities to fundamentally shift the terms of federal oil and gas leases and increase revenues. Compared to other countries, the United States receives one of the lowest shares of revenue for oil and gas. In addition, Interior's royalty rate, which does not change to reflect changing prices and market conditions, has at times, led to pressure on Interior and Congress to periodically change royalty rates in response to market conditions. Interior also has done less than some states and private landowners to encourage lease development and may be missing opportunities to increase production and, subsequently, revenues. Interior's oil and gas IT systems lack key functionalities. GAO's past work found that MMS's ability to maintain the accuracy of oil and gas production and royalty data was hampered by two key limitations in its IT system (1) it did not limit companies' ability to adjust self-reported data after MMS had audited them, and (2) it did not identify missing royalty reports. Preliminary GAO findings have also identified technical problems within BLM's IT systems and their compatibility with MMS's IT systems. Interior's royalty-in-kind program, in which oil and gas producers submit royalties in oil and gas rather than cash, continues to face challenges. GAO found problems with MMS's analysis of program benefits that were reported to Congress, and that MMS failed to use third party data to verify companies' self-reported data. Meanwhile, Interior's Inspector General identified major ethical lapses, including inappropriate relationships between MMS royalty-in-kind program officials and industry representatives.

section_title: Letter
paragraphs: We appreciate the opportunity to participate in this hearing to discuss the  Department of the Interior’s management of federal oil and gas leases and  the proposed Consolidated Land, Energy, and Aquatic Resources Act of  2009. Effective management and oversight of our nation’s oil and gas  resources, and the royalties paid on their production, is increasingly  critical as our country faces both serious fiscal challenges and long-term  projected growth in energy demand.
Interior plays an important role in managing federal oil and gas resources.  In fiscal year 2008, Interior reported that private companies extracted  approximately 467 million barrels of oil and 4.7 trillion cubic feet of  natural gas from federal lands and waters. This production provided  significant revenue to the federal government. Specifically, Interior  collected more than $22 billion in royalties for oil and gas produced from  federal lands and waters, purchase bids for new oil and gas leases, and  annual rents on existing leases, making revenues from federal oil and gas  one of the largest nontax sources of federal government funds. Within  Interior, the Bureau of Land Management (BLM) manages onshore federal  oil and gas leases and the Minerals Management Service’s (MMS) Offshore  Energy and Minerals Management (OEMM) manages offshore leases. MMS  is responsible for collecting royalties for both onshore and offshore leases.
In recent years, GAO and others, including Interior’s Inspector General  have conducted numerous evaluations of federal oil and gas management  and revenue collection processes and practices and have found many  material weaknesses in this management. These weaknesses place an  unknown but significant proportion of royalties and other oil and gas  revenues at risk and raise questions about whether the federal government  is collecting an appropriate amount of revenue for the rights to explore  for, develop, and produce oil and gas from federal lands and waters.
In this context, my testimony today addresses (1) Interior’s policies and  practices for oil and gas leasing, (2) Interior’s oversight of oil and gas  production, (3) the existing royalty fiscal regime and Interior’s policies to  encourage oil and gas development, (4) inefficiencies within Interior’s oil  and gas information technology (IT) systems, and (5) the ongoing  challenges with Interior’s Royalty-in-Kind (RIK) program. Across several  of these areas, our past work has led us to make a number of  recommendations to the Secretary of the Interior. Officials at Interior have  reported that they are working to implement many of these  recommendations. This statement is primarily based on our extensive  body of work on Interior’s oil and gas leasing and royalty collection  programs, including one report being issued today, as well as some  preliminary ongoing work on Interior’s procedures for ensuring oil and gas  produced from federal leases is properly accounted for. This body of work  was conducted in accordance with generally accepted government  auditing standards. Those standards require that we plan and perform the  audit to obtain sufficient, appropriate evidence to provide a reasonable  basis for our findings and conclusions based on our audit objectives. We  believe that the evidence obtained during these reviews provides a  reasonable basis for our findings and conclusions based on our audit  objectives.
subsections: section_title: Interior’s Policies for Offshore and Onshore Oil and Gas Leases Differ in Key Ways
paragraphs: In October 2008, we reported that Interior’s policies for identifying and  evaluating lease parcels and bids differ in key ways depending on whether  the lease is located offshore—and therefore overseen by OEMM—or  onshore—and therefore overseen by BLM. These differences follow.
Identifying lease parcels. OEMM’s and BLM’s methods for identifying  areas to lease vary significantly.  Specifically:    For offshore leases, OEMM—as prescribed by the Outer Continental Lands  Act—lays out 5-year strategic plans for the areas it plans to lease and  establishes a schedule for offering leases. OEMM offers leases for  competitive bidding, and all eligible companies may submit written sealed  bids, referred to as bonus bids, for the rights to explore, develop, and  produce oil and gas resources on these leases, including drilling test wells.
For onshore leases, BLM—which must follow the Federal Onshore Oil and  Gas Leasing Reform Act of 1987—is not required to develop a long-term  leasing plan and instead relies on the industry and the public to nominate  areas for leasing. BLM selects lands to lease from these nominations, as  well as some parcels it has identified on its own. In some cases, BLM, like  MMS, offers leases through a competitive bidding process, but with bonus  bids received in an oral auction rather than in a sealed written form.
Evaluating bids. OEMM and BLM differ in their regulations and policies  for evaluating whether the bids received for areas offered for lease are  sufficient. Specifically:    For offshore leases, OEMM compares sealed bids with its own  independent assessment of the value of the potential oil and gas in each  lease. After the bids are received, OEMM—using a team of geologists,  geophysicists, and petroleum engineers assisted by a software program— conducts a technical assessment of the potential oil and gas resources  associated with the lease and other factors to develop an estimate of their  fair market value. This estimate becomes the minimally acceptable bid and  is used to evaluate the bids received. The bidder that submits the highest  bonus bid that meets or exceeds MMS’s estimate of the fair market value  of a lease is awarded the lease. These rights last for a set period of time,  referred to as the primary term of the lease, which may be 5, 8, or 10 years,  depending on the water depth. If no bids equal or exceed the minimally  acceptable bid, the lease is not awarded but is offered at a subsequent  sale. According to OEMM, since 1995, the practice of rejecting bids that  fall below the minimally acceptable bid and re-offering these leases at a  later sale has resulted in an overall increase in bonus receipts of  $373 million between 1997 and 2006.
For onshore leases, BLM relies exclusively on competitors, participating in  an oral auction, to determine the lease’s market value. Furthermore, BLM,  unlike OEMM, does not currently employ a multidisciplinary team with the  appropriate range of skills or appropriate software to develop estimates of  the oil and gas reserves for each lease parcel, and thus, establish a market  and resource-based minimum acceptable bid. Instead, BLM has  established a uniform national minimum acceptable bid of at least $2 per  acre and has taken the position that as long as at least one bid meets this  $2 per acre threshold, the lease will be awarded to the highest bidder.  Importantly, onshore leases that do not receive any bids in the initial offer  are available noncompetitively the day after the lease sale and remain  available for leasing for a period of 2 years after the competitive lease sale.  Any of these available leases may be acquired on a first-come, first-served  basis subject to payment of an administrative fee. Prior to 1992, BLM  offered primary terms of 5 years for competitively sold leases and 10 years  for leases issued noncompetitively. Since 1992, BLM has been required by  law to only offer leases with 10-year primary terms whether leases are sold  competitively or issued noncompetitively.
section_title: Interior’s Oversight of Federal Oil and Gas Production Has Not Kept Pace with Increased Activity
paragraphs: Oil and gas activity has generally increased over the past 20 years, and our  reviews have found that Interior has—at times—been unable to meet its  oversight obligations for (1) completing environmental inspections,  (2) verifying oil and gas production, (3) performing environmental  monitoring in accordance with land use plans, and (4) using categorical  exclusions to streamline environmental analyses required for certain oil  and gas activities. Specifically:    Completing environmental inspections. In June 2005, we reported that,  with the increase in oil and gas activity, BLM had not consistently been  able to complete its required environmental inspections—the primary  mechanism to ensure that companies are complying with various  environmental laws and lease stipulations. At the time of our review, BLM  officials explained that because staff were spending increasing amounts of  time processing drilling permits, they had less time to conduct  environmental inspections.
Verifying oil and gas production. In September 2008, we reported that  neither BLM nor OEMM was meeting its statutory obligations or agency  targets for inspecting certain leases and metering equipment used to  measure oil and gas production, raising uncertainty about the accuracy of  oil and gas measurement. For onshore leases, BLM had completed only a  portion of its production verification inspections—with some BLM offices  completing all of their required inspections and others completing  portions as small as one quarter of their required inspections––because its  workload has substantially grown in response to increases in onshore  drilling. For offshore leases, OEMM had completed about half of its  required production inspections in 2007 because of ongoing cleanup work  related to Hurricanes Katrina and Rita. Additionally, in our ongoing work,  we have found that Interior has not consistently updated its oil and gas  measurement regulations. Specifically, OEMM has routinely reviewed and  updated its measurement regulations, whereas BLM has not. Accordingly,  OEMM has updated its measurement regulations six times since 1998,  whereas BLM has not updated its measurement regulations since 1989.
Performing environmental monitoring. In June 2005, we reported that  four of the eight BLM field offices we visited had not developed any  resource monitoring plans to help track management decisions and  determine if desired outcomes had been achieved, including those related  to mitigating the environmental impacts of oil and gas development. We  concluded that without these plans, land managers may be unable to  determine the effectiveness of various mitigation measures attached to  drilling permits and decide whether these measures need to be modified,  strengthened, or eliminated. Officials offered several reasons for not  having these plans, including that staff that could have been used to  develop such plans had been busy with processing an increased number of  drilling permits, as well as budget constraints.
Using categorical exclusions. Our report issued today on BLM’s use of  categorical exclusions—authorized under section 390 of the Energy  Policy Act of 2005 to streamline the environmental analysis required under  the National Environmental Policy Act (NEPA) when approving certain oil  and gas activities—identifies some benefits but raises numerous questions  about how and when BLM should use these categorical exclusions. First,  our analysis found that BLM used section 390 categorical exclusions to  approve over one-quarter of its applications for drilling permits from fiscal  years 2006 to 2008. While these categorical exclusions generally increased  the efficiency of operations, some BLM field offices, such as those with  recent environmental analyses already completed, were able to benefit  more than others. Second, we found that BLM’s use of section 390  categorical exclusions was frequently out of compliance with both the law  and agency guidance and that a lack of clear guidance and oversight by  BLM were contributing factors. We found several types of violations of the  law, such as BLM offices approving more than one oil or gas well under a  single decision document and drilling a new well after statutory time  frames had lapsed. We also found examples, in 85 percent of field offices  reviewed, where officials did not comply with agency guidance, most often  by failing to adequately justify the use of a categorical exclusion. While  many of these violations and noncompliance were technical in nature,  others were more significant and may have thwarted NEPA’s twin aims of  ensuring that BLM and the public are fully informed of environmental  consequences of BLM’s actions. Third, we found that a lack of clarity in  both section 390 of the act and BLM’s guidance has raised serious  concerns. Specifically:   (1) Fundamental questions about what section 390 categorical exclusions  are and how they should be used have led to concerns that BLM may be  using these categorical exclusions in too many—or too few—instances; for  example, there is disagreement as to whether BLM must screen section  390 categorical exclusions for circumstances that would preclude their use  or whether their use is mandatory;  (2) Concerns about key concepts underlying the law’s description of these  categorical exclusions have arisen—specifically, whether section 390  categorical exclusions allow BLM to exceed development levels, such as  number of wells to be drilled, analyzed in supporting NEPA documents  without conducting further analysis; and  (3) Vague or nonexistent definitions of key criteria in the law and BLM  guidance have led to varied interpretations among field offices and  concerns about misuse and a lack of transparency.
In light of our findings from this report, we recommended that BLM take  steps to improve the implementation of section 390 of the act by clarifying  agency guidance, standardizing decision documentation, and ensuring  compliance through more oversight. We also suggested that Congress  may wish to consider amending the Energy Policy Act of 2005 to clarify  and resolve some of the key issues identified in our report.
section_title: Interior May be Missing Opportunities to Fundamentally Shift the Terms of Federal Oil and Gas Leases to Increase Revenues
paragraphs: In our past work, we have identified several areas where Interior may be  missing opportunities to increase revenue by fundamentally shifting the  terms of federal oil and gas leases. As we reported in September 2008,  (1) federal oil and gas leasing terms result in the U.S. government  receiving one of the smallest shares of oil and gas revenue when compared  to other countries and (2) Interior’s royalty rate, which does not change to  reflect changing prices and market conditions, led to pressure on Interior  and Congress to periodically change royalty rates. We also reported that  Interior was doing far less than some states to encourage development of  leases. Specifically:    The U.S. government receives one of the lowest shares of revenue for oil  and gas resources compared with other countries and resource owners.  For example, we reported the results of a private study in 2007 showing  that the revenue share the U.S. government collects on oil and gas  produced in the Gulf of Mexico ranked 93rd lowest of the 104 revenue  collection regimes around the world covered by the study. Further, the  study showed that some countries had increased their shares of revenues  as oil and gas prices rose and, as a result, could collect between an  estimated $118 billion and $400 billion, depending on future oil and gas  prices. However, despite significant changes in the oil and gas industry  over the past several decades, we found that Interior had not  systematically re-examined how the U.S. government is compensated for  extraction of oil and gas for over 25 years.
Since 1980, in part due to Interior’s inflexible royalty rate structure,  Congress and Interior have been pressured—with varying success—to  periodically adjust royalty rates to respond to current market conditions.  For example, in 1980, a time when oil prices were high compared to  today’s prices, in inflation-adjusted terms, Congress passed a windfall  profit tax, which it later repealed in 1988 after oil prices had fallen  significantly from their 1980 level. Later, in November 1995—during a  period with relatively low oil and gas prices—the federal government  enacted the Outer Continental Shelf Deep Water Royalty Relief Act  (DWRRA) which provided for “royalty relief,” the suspension of royalties  on certain volumes of initial production, for certain leases in the Gulf of  Mexico in depths greater than 200 meters during the 5 years after passage  of the act—1996 through 2000. For leases issued during these 5 years,  litigation established that MMS lacked the authority under the act to  impose thresholds. As a result, companies are now receiving royalty  relief even though prices are much higher than at the time the DWRRAwas enacted. In June 2008, we estimated that future foregone royalties  from all the DWRRA leases issued from 1996 through 2000 could range  widely—from a low of about $21 billion to a high of $53 billion. Finally, in  2007, the Secretary of the Interior twice increased the royalty rate for  future Gulf of Mexico leases. In January, the rate for deep water leases  was raised to 16.66 percent. Later, in October, the rate for all future lease in the Gulf, including those issued in 2008, was raised to 18.75 perce Interior estimated these actions would increase federal oil and gas  revenues by $8.8 billion over the next 30 years. The January 2007 increase  nt.  applied only to deep water Gulf of Mexico leases; the October 2007  increase applied to all water depths in the Gulf of Mexico.
We concluded that these royalty rate increases appeared to be a response  by Interior to the high prices of oil and gas that have led to record industry  profits and raised questions about whether the existing federal oil and gas  fiscal system gives the public an appropriate share of revenues from oil  and gas produced on federal lands and waters. Further, the royalty rate  increases did not address industry profits from existing leases. Existing  leases, with lower royalty rates, would likely remain highly profitable as  long as they produced oil and gas or until oil and gas prices fell  significantly. In addition, in choosing to increase royalty rates, Interior did  not evaluate the entire oil and gas fiscal system to determine whether or  not these increases were sufficient to balance investment attractiveness  and appropriate returns to the federal government for oil and gas  resources. On the other hand, according to Interior, it did consider factors  such as industry costs for outer continental shelf exploration and  development, tax rates, rental rates, and expected bonus bids. Further,  because the increased royalty rates are not flexible with respect to oil and  gas prices, Interior and Congress could again be under pressure from  industry or the public to further change the royalty rates if and when oil  and gas prices either fall or rise. Finally, these past royalty changes only  affected Gulf of Mexico leases and did not address onshore leases.
Interior’s OEMM and BLM varied in the extent to which they encouraged  development of federal leases, and both agencies did less than some states  and private landowners to encourage lease development. As a result, we  concluded that Interior may be missing opportunities to increase domestic  oil and gas production and revenues. Specifically, in the Gulf of Mexico,  OEMM varied the lease length in accordance with the depth of water over  which the lease is situated. For example, leases issued in shallow water  depths typically have lease terms of 5 years, whereas leases in the deepest  areas of the Gulf of Mexico have 10 year primary terms; shallower water  tends to be nearer to shore and to be adjacent to already developed areas  with pipeline infrastructure in place, while deeper water tends to be  further out, have less available infrastructure to link up with, and generally  present greater challenges associated with the depth of the wells  themselves. In contrast, BLM issues leases with 10 year primary terms,  regardless of whether the lease happens to lie adjacent to a fully  developed field with the necessary pipeline infrastructure to carry the  product to market, or whether it is in a remote location with no  surrounding infrastructure. Furthermore, BLM also uses 10 year primary  terms in the National Petroleum Reserve-Alaska, where it is significantly  more difficult to develop oil fields because of factors including the harsh  environment. We also examined selected states and private landowners  that lease land for oil and gas development and found that some did more  than Interior to encourage lease development. For example, to provide a  greater financial incentive to develop leased land, the state of Texas  allowed lessees to pay a 20 percent royalty rate for the life of the lease if  production occurred in the first 2 years of the lease, as compared to  25 percent if production occurred after the fourth year. In addition, we  found that some states and private landowners also did more to structure  leases to reflect the likelihood of finding oil and gas. For example, New  Mexico issued shorter leases and could require lessees to pay higher  royalties for properties in or near known producing areas and allowed  longer leases and lower royalty rates in areas believed to be more  speculative. Officials from one private landowners’ association told us that  they too were using shorter lease terms, ranging from as little as 6 months  to 3 years, to ensure that lessees were diligent in developing any potential  oil and gas resources on their land. Louisiana and Texas also issued 3-year  onshore leases. While the existence of lease terms that appear to  encourage faster development of some oil and gas leases suggest a  potential for the federal government to also do more in this regard, it is  important to note that it can take several years to complete the required  environmental analyses needed for lessees to receive approval to begin  drilling on federal lands.
To address what we believed were key weaknesses in this program, while  acknowledging potential differences between federal, state, and private  leases, we recommended that the Secretary of the Interior develop a  strategy to evaluate options to encourage faster development of oil and  gas leases on federal lands, including determining whether methods to  differentiate between leases according to the likelihood of finding  economic quantities of oil or gas and whether some of the other methods  states use could effectively be employed, either across all federal leases or  in a targeted fashion. In so doing, we recommended that Interior identify  any statutory or other obstacles to using such methods and report the  findings to Congress.
We also noted that Congress may wish to consider directing the Secretary  of the Interior to:    convene an independent panel to perform a comprehensive review of the  federal oil and gas fiscal system, and   direct MMS and other relevant agencies within Interior to establish  procedures for periodically collecting data and information and  conducting analyses to determine how the federal government take and  the attractiveness for oil and gas investors in each federal oil and gas  region compare to those of other resource owners and report this  information to Congress.
section_title: Interior’s Oil and Gas IT Systems Lack Key Functionalities
paragraphs: Our past work and preliminary findings have identified shortcomings in  Interior’s IT systems for managing oil and gas royalty and production  information. In September 2008, we reported that Interior’s oil and gas IT  systems did not include several key functionalities, including (1) limiting a  company’s ability to make adjustments to self-reported data after an audit  had occurred and (2) identifying missing royalty reports. Since  September 2008, MMS has made improvements in identifying missing  royalty reports, but it is too early to assess their effectiveness, and we  remain concerned with the following issues:    MMS’s ability to maintain the accuracy of production and royalty data has  been hampered because companies can make adjustments to their  previously entered data without prior MMS approval. Companies may  legally make changes to both royalty and production data in MMS’s royalty  IT system for up to 6 years after the initial reporting month, and these  changes may necessitate changes in the royalty payment. However, MMS’s  royalty IT system currently allows companies to make adjustments to their  data beyond the allowed 6-year time frame. As a result of the companies’  ability to make these retroactive changes, within or outside of the 6-year  time frame, the production data and required royalty payments can change  over time—even after MMS completes an audit—complicating efforts by  agency officials to reconcile production data and ensure that the proper  royalties were paid.
MMS’s royalty IT system is also unable to automatically detect instances  when a royalty payor fails to submit the required royalty report in a timely  manner. As a result, cases in which a company stops filing royalty reports  and stops paying royalties may not be detected until more than 2 years  after the initial reporting date, when MMS’s royalty IT system completes a  reconciliation of volumes reported on the production reports with the  volumes on their associated royalty reports. Therefore, it remains possible  under MMS’s current strategy that the royalty IT system may not identify  instances in which a payor stops reporting until several years after the  report is due. This creates an unnecessary risk that MMS may not be  collecting accurate royalties in a timely manner.
Additionally, in July 2009, we reported that MMS’s IT system lacked  sufficient controls to ensure that royalty payment data were accurate.   While many of the royalty data we examined from fiscal years 2006 and  2007 were reasonable, we found significant instances where data were  missing or appeared erroneous. For example, we examined gas leases in  the Gulf of Mexico and found that, about 5.5 percent of the time, lease  operators reported production, but royalty payors did not submit the  corresponding royalty reports, potentially resulting in $117 million in  uncollected royalties. We also found that a small percentage of royalty  payors reported negative royalty values, which cannot happen, potentially  costing $41 million in uncollected royalties. In addition, royalty payors  claimed gas processing allowances 2.3 percent of the time for unprocessed  gas, potentially resulting in $2 million in uncollected royalties.  Furthermore, we found significant instances where royalty payor-provided  data on royalties paid and the volume and or the value of the oil and gas  produced appeared erroneous because they were outside the expected  ranges.
Moreover, in preliminary findings on Interior’s procedures for ensuring oil  and gas produced from federal leases is properly accounted, we found  that:    The IT systems employed by both BLM and MMS fail to communicate  effectively with one another resulting in cumbersome data transfers and  data errors. For example, in order to complete the weekly transfer of oil  and gas production data between MMS and BLM, MMS staff must copy all  production data onto a disk, which then must be sent to BLM’s building  where it is subsequently uploaded into BLM’s IT system. Furthermore,  according to BLM staff, the production uploads are currently not working  as intended. Frequently, an operator may make adjustments to production  records, which results in the creation of a new record. When these new  records are uploaded into BLM’s IT system, they should replace—or  overlay—the prior record. However, due to technical problems, new  reports are not correctly overlaying the previously uploaded production  reports; instead they are creating duplicate or triplicate production reports  for the same operator and month. According to BLM’s IT system  coordinator, this will likely complicate BLM’s production accountability  work.
BLM’s efforts to use gas production data acquired remotely from gas wells  through its Remote Data Acquisition for Well Production program to  facilitate production inspections have shown few results after 5 years of  funding and at least $1.5 million spent. Currently, BLM is only receiving  production data from approximately 50 wells via this program, and it has  yet to use the data to complete a production inspection, making it difficult  to assess its utility.
To address weaknesses we identified in our September 2008 report, we  recommended that the Secretary of the Interior, among other things:  finalize the adjustment line monitoring specifications for modifying its  royalty IT system and fully implement the IT system so that MMS can  monitor adjustments made outside the 6-year time frame, and ensure that  any adjustments made to production and royalty data after compliance  work has been completed are reviewed by appropriate staff, and   develop processes and procedures by which MMS can automatically  identify when an expected royalty report has not been filed in a timely  manner and contact the company to ensure it is complying with both  applicable laws and agency policies.
In addition, to address weaknesses identified in our July 2009 report,  we  made a number of recommendations to MMS intended to improve the  quality of royalty data by improving its IT systems’ edit checks, among  other things.
section_title: Interior’s RIK Program Continues to Face Challenges
paragraphs: Interior’s management and oversight of its RIK program has raised  concerns as to whether Interior is receiving the correct royalty volumes of  oil and gas. Both we and Interior’s Inspector General have issued reports  detailing deficiencies in both program management and management  ethics, including (1) problems with reporting the benefits of the RIK  program to Congress, (2) Interior’s failure to use available third-party data  to confirm gas production volumes, (3) inappropriate relationships  between RIK staff and industry representatives, and (4) insufficient  controls for monitoring natural gas imbalances, among others.  Specifically:  In September, 2008, we reported that MMS’s annual reports to Congress  did not fully describe the performance of the RIK program and, in some  instances, may have overstated the benefits of the program. For example,  MMS’s calculation that from fiscal years 2004 to 2006, MMS sold royalty oil  and gas for $74 million more than it would have received in cash was  based on assumptions, not actual sales data, about the prices at which  royalty payors would have sold their oil or gas had they sold it on the open  market. MMS did not report to Congress that even small changes in these  assumptions could result in very different estimates. Also, MMS’s  calculation that the RIK program cost about $8 million less to administer  than the royalty-in-value program over the same period did not include  certain costs, such as IT costs shared with the royalty-in-value program  that would likely have changed the results of MMS’s administrative cost  analysis. In addition, MMS’s annual reports to Congress lacked important  information on the financial results of individual oil sales that Congress  could use to more broadly assess the performance of the RIK program.
In 2008, we also reported that MMS’s oversight of its natural gas  production volumes was less robust than its oversight of oil production  volumes. As a result, MMS did not have the same level of assurance that it  is collecting the gas royalties it is owed. For instance, for oil, MMS  compared companies’ self-reported oil production data with third-party  pipeline meter data from OEMM’s liquid verification system, which  records oil volumes flowing through pipeline metering points. Using these  third-party pipeline statements to verify production volumes reported by  companies would have provided a check against companies’ self-reported  statement of royalty payments owed to the federal government. While  analogous data were available from OEMM’s gas verification system, MMS  did not use these third-party data to verify the company-reported  production numbers. As of February 2009, MMS had begun to use the gas  verification system.
Interior’s Inspector General also issued a report in September 2008 which  found that the program had suffered from ethical shortcomings. In  particular, the Inspector General found that a program manager had been  paid for consulting by an oil and gas company in violation of agency rules  and that up to one-third of all RIK staff had inappropriately socialized and  received gifts from oil and gas companies.
Most recently, in August 2009, we found that MMS risks losing millions of  dollars in revenue from the RIK natural gas program due to inadequate  oversight. Specifically:    MMS lacks the necessary information to quantify revenues resulting from  imbalances—instances when MMS receives a percentage of total  production other than its entitled royalty percentage. MMS does not know  the exact amount it is owed as a result of natural gas imbalances because  it lacks at least three types of information. First, it does not verify all gas  production data to ensure it receives its entitled percentage of RIK gas.  Second, MMS lacks information on how to price gas imbalances and when  interest will begin accruing on imbalances for leases that have terminated  from the program or those leases where production has ceased. Finally,  MMS could be forgoing revenue because it lacks information on daily gas  imbalances.
MMS also may be forgoing revenue because it does not audit operator data  to ensure it has received its entitled royalty percentage. Although MMS has  procedures for reconciling imbalances and uses OEMM’s gas verification  system data where available, we found that it has not assessed the risk of  forgoing audits at those measurement points where it does not have  complete data with which to verify that it has been allocated its entitled  percentage of gas. Although the RIK guidance letter to operators states  MMS’s right to audit operator information related to RIK gas produced and  delivered, MMS has not done so because it has considered its verification  of operator-generated data to be sufficient. MMS has also claimed that it  has saved money as a result of not auditing and that this is a benefit of the  RIK program. However, other royalty owners and members of the oil and  gas industry regularly audit operator-reported data to ensure that they  have received the gas they are entitled to.
To address weaknesses we identified in our September 2008 and August  2009 reports, we recommended that the Director of MMS, among other  things:  improve calculations of the benefits and costs of the RIK program and the  information presented to Congress by (1) calculating and presenting a  range of the possible performances of the RIK sales in accordance with  Office of Management and Budget guidelines; (2) reevaluating the process  by which it calculates the early payment savings; (3) disclosing the costs  to acquire, develop, operate, and maintain RIK-specific IT systems; and (4)  disaggregating the oil sales data to show the variation in the performances  of individual sales.  improve MMS’s oversight of the RIK gas program and help ensure that the  nation receives its fair share of RIK gas by (1) establishing policies and  procedures to ensure outstanding imbalances are valued appropriately and  that the correct amount of interest is charged; (2) monitoring daily gas  imbalances and determining whether legislative changes are needed to  require operators to deliver the royalty percentage on a daily basis;  (3) auditing the operators and imbalance data; (4) promulgating RIK  program regulations; and (5) establishing procedures, with reasonable  deadlines, for resolving and collecting all RIK gas imbalances in a timely  manner.
In conclusion, over the past several years, we and others have examined  oil and gas leasing at the Department of the Interior many times and  determined such leasing to be in need of fundamental reform across a  wide range of Interior’s functions. As Congress considers what  fundamental changes are needed in how Interior structures its oversight of  oil and gas leasing, we believe that our and others’ past work provides a  road map for successful reform of the agency’s oversight functions. If  steps are not taken to effectively manage these challenges, we remain  concerned about the agency’s ability to manage the nation’s oil and gas  and provide reasonable assurance that the U.S. government is collecting  an appropriate amount of revenue for the extraction and use of these  scarce resources.
Mr. Chairman, this completes my prepared statement. I would be happy to  respond to any questions that you or other Members of the Committee  may have at this time.
section_title: GAO Contact and Staff Acknowledgments
paragraphs: For further information on this statement, please contact Frank Rusco at  (202) 512-3841 or ruscof@gao.gov. Contact points for our Congressional  Relations and Public Affairs offices may be found on the last page of this  statement. Other staff that made key contributions to this testimony  include Ron Belak, Ben Bolitzer, Melinda Cordero, Nancy Crothers,  Heather Dowey, Glenn C. Fischer, Cindy Gilbert, Richard Johnson, Mike  Krafve, Jon Ludwigson, Jeff Malcolm, Alison O’Neill, Justin Reed, Holly  Sasso, Dawn Shorey, Karla Springer, Barbara Timmerman, Maria Vargas,  Tama Weinberg, and Mary Welch.
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