Federal Energy Development: Challenges to Ensuring a Fair Return for Federal Energy Resources

Interior oversees energy production on federal lands and waters and is responsible for ensuring taxpayers receive a fair return for access to federal energy resources. Oil, gas, and coal on federal lands provide an important source of energy for the United States; they create jobs; and they generate billions of dollars in revenues that are shared between federal, state, and tribal governments. However, when not managed properly, energy production on federal lands can create risks to public health and the environment, such as contaminated surface water. In February 2011, GAO designated Interior's management of federal oil and gas resources as a program at high risk for fraud, waste, abuse, and mismanagement or the need for transformation. This testimony discusses GAO's work related to ensuring a fair return on resources from federal lands. To do this work, GAO drew on reports issued from May 2007 through September 2019 and preliminary observations from ongoing work. GAO reviewed relevant federal and state laws, regulations, and policies; analyzed federal data; and interviewed federal, state, and industry officials, among others.

GAO's prior and ongoing work found challenges related to ensuring a fair return for oil, gas, and coal developed on federal lands in areas, including the following:

Oil, Gas, and Coal Lease Terms and Conditions. Key federal lease terms are the same as they were decades ago, and Interior has not adjusted them for inflation or other factors that may affect the federal government's fair return. In June 2017, GAO reported that raising federal royalty rates—a lease term that defines a percentage of the value of production paid to the government—for onshore oil, gas, and coal resources could decrease production on federal lands by a small amount or not at all but could increase overall federal revenue. Also, preliminary observations from GAO's ongoing work indicate that selected states charge royalty rates for oil and gas produced on state lands at a higher rate than the federal government charges for production on federal lands.

Oil, Gas, and Coal Bonding. GAO found in September 2019 that oil and gas bonds do not provide sufficient financial assurance because, among other things, most individual, statewide, and nationwide lease bonds are set at regulatory minimum values that have not been adjusted for inflation since the 1950s and 1960s (see figure). Further, GAO reported in March 2018 that coal self-bonding (where an operator promises to pay reclamation costs without providing collateral) poses financial risks to the federal government. Bonds provide funds that can be used to reclaim lands—restore them as close to their original natural states as possible—if an operator or other liable party does not do so.

Natural Gas Emissions. In October 2010, GAO reported that data collected by Interior likely underestimated venting and flaring because they did not account for all sources of lost gas. GAO reported that economically capturing vented and flared natural gas could increase federal royalty payments by $23 million annually and made recommendations to help Interior better account for and manage emissions. In November 2016, Interior issued regulations consistent with GAO's recommendations, but Interior has since issued revised regulations, which are inconsistent with GAO's recommendations.

For the reports discussed in this testimony, GAO has made 20 recommendations and three matters for congressional consideration. Interior has taken steps to implement a number of these recommendations, but 10 recommendations and two matters for congressional consideration remain unimplemented, presenting opportunities to continue to improve management of energy resources on federal lands.

I am pleased to be here today to discuss our work related to Interior  ensuring a fair return for oil, gas, and coal development on federal lands.

The Department of the Interior (Interior) oversees energy production on  federal lands and waters, is responsible for ensuring taxpayers receive a  fair return for access to federal energy resources, and is responsible for  ensuring those resources are safely and responsibly developed. Federal  oil, gas, and coal are an important source of revenues that are shared  among federal, state, and tribal governments. These revenues consist of,  among other things, a percentage of the value of production paid to the  federal government, or royalties. Based on Interior data, for fiscal year  2018 Interior collected about $4.2 billion associated with onshore oil, gas,  and coal production on federal and Indian lands. Federal lands also  provide an important source of energy for the United States and create  jobs in the oil and gas industry. According to Interior’s Bureau of Land  Management (BLM), in fiscal year 2018, production on federal lands was  responsible for 9 percent of the natural gas, 8 percent of the oil, and  nearly 40 percent of the coal produced in the United States. However,  when not managed properly, energy production on federal lands can  create risks to public health and the environment, such as contaminated  surface water and groundwater and methane leaks into the atmosphere.

In February 2011, we designated Interior’s management of federal oil and  gas resources as a program at high risk for fraud, waste, abuse, and  mismanagement or the need for transformation. This designation was  based on challenges we identified with several aspects of Interior’s  oversight responsibilities, including that Interior lacked reasonable  assurance that it was collecting a fair return from oil and gas produced on  federal lands. Since our 2011 designation, we have made numerous  recommendations to improve Interior’s management of federal oil and gas  resources. Interior has taken some actions to strengthen how it manages  federal oil and gas resources, but it has not met the criteria for removal  from our high-risk list. For example, in December 2013, we  recommended that Interior revise BLM’s regulations to provide flexibility  for the bureau to make changes to onshore oil and gas royalty rates.  Interior agreed with our recommendation and adopted regulations in  November 2016 that provided royalty rate flexibility.

In addition to reporting in February 2011 on challenges with Interior  collecting a fair return from oil and gas produced on federal lands, we  have recently reported on challenges in several other areas related to  Interior ensuring a fair return, including managing bonds for oil, gas, and coal development to ensure  taxpayers do not have to pay to reclaim lands affected by energy  development; ensuring royalty compliance (Interior’s ability to determine moneys  owed and to collect and account for such amounts); and accounting for and managing natural gas emissions in determining  royalties owed.

In these reports, we made 20 recommendations and three matters for  congressional consideration. Interior has taken steps to implement a  number of these recommendations, but 10 of our recommendations and  two matters for congressional consideration remain unimplemented,  presenting opportunities to continue to improve management of energy  resources on federal lands.

My testimony today discusses challenges we have identified related to  Interior ensuring a fair return for oil, gas, and coal development on federal  lands in four areas: (1) lease terms and conditions, (2) bonds, (3) royalty  compliance, and (4) natural gas emissions.

The information in this testimony is based primarily on reports we issued  from May 2007 through September 2019. In conducting that work, we  reviewed relevant federal laws, regulations, and policies; analyzed federal  data; and interviewed federal, state, and industry officials, among others.  More detailed information on our objectives, scope, and methodology for  that work can be found in the issued reports. In addition, this testimony  includes preliminary observations from our ongoing work examining  federal and selected states’ oil and gas lease practices. We shared the  preliminary observations that we are presenting in this testimony with  Interior and selected states for comment. Interior and selected states  provided technical comments, which we have addressed as appropriate.

We conducted, or are conducting, the work on which this testimony is  based 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 provides a reasonable basis for our findings  and conclusions based on our audit objectives.

Federal Onshore Oil, Gas, and Coal Lease Terms and Conditions

BLM leases federal lands to private entities for oil and gas development  generally through auctions. In the auctions, if BLM receives any bids that  are at or above the minimum acceptable bid amount of $2 an acre— called bonus bids—the lease is awarded to the highest bidder (leases  obtained in this way are called competitive leases). Tracts of land that do  not receive a bid at the auction are made available noncompetitively for a  period of 2 years on a first-come, first-served basis (leases obtained in  this way are called noncompetitive leases).

The government collects revenues from oil and gas leases under terms  and conditions that are specified in the lease, including rental fees and  royalties. Annual rental fees are fixed fees paid by lessees until  production begins on the leased land or, when no production occurs, until  the end of the period specified in the lease. For federal oil and gas  leases, generally the rental rate is $1.50 per acre for the first 5 years, and  $2 per acre each year thereafter. Once production of the resource  starts, the lessees pay the federal government royalties of at least 12.5  percent of the value of production. Oil and gas parcels are generally  leased for a primary term of 10 years, but lease terms may be extended  if, for example, oil or gas is produced in paying quantities. A productive  lease remains in effect until the lease is no longer capable of producing in  paying quantities. The fiscal system refers to the terms and conditions  under which the federal government collects revenues from production on  leases, including from payments specified in the lease (e.g., royalties and  rental payments).

We reported in December 2013 that, since 1990, all federal coal leasing  has taken place through a lease-by-application process, where coal  companies propose tracts of federal lands to be put up for lease by BLM.  BLM is required to announce forthcoming lease sales, and the  announcement notes where interested stakeholders can view lease sale  details, including bidding instructions and the terms and conditions of the  lease. BLM leases a tract to the highest qualified bidder, as long as its  bonus bid meets or exceeds $100 per acre and BLM’s confidential  estimate of fair market value. Annual rental fees are at least $3 an acre,  and royalties are 8 percent of the sale price for coal produced from  underground mines and at least 12.5 percent of the sale price for coal  produced from surface mines. Tracts are leased for an initial 20-year  period, as long as the lessee produces coal in commercial quantities  within a 10-year period and meets the condition of continued operations.

Bonds can help ensure lands affected by energy development are  properly reclaimed, that is, according to BLM, restored to as close to their  original natural states as possible. Bonds provide funds that can be used  by the relevant regulatory authority to reclaim such lands if the operator or  other liable party does not do so. For oil and gas developed on federal  lands, BLM requires operators to provide a bond before certain drilling  operations begin. Wells are considered orphaned and fall to BLM to  reclaim if they are not reclaimed by their operators, there are no other  responsible or liable parties to do so, and their bonds are too low to cover  reclamation costs.

For surface coal mining, the Surface Mining Control and Reclamation Act  of 1977 (SMCRA) requires operators to submit a bond to either Interior’s  Office of Surface Mining Reclamation and Enforcement (OSMRE) or an  approved state regulatory authority before mining operations begin for  development on federal or nonfederal lands. Among other bonding  options, coal operators may choose to self-bond, whereby the operator  promises to pay reclamation costs.

Royalties that companies pay on the sale of oil and natural gas extracted  from leased federal lands and waters constitute a significant source of  revenue for the federal government. The Federal Oil and Gas Royalty  Management Act of 1982 requires, among other things, that Interior  establish a comprehensive inspection, collection, and fiscal and  production accounting and auditing system for these revenues. In  particular, the act requires Interior to establish such a system to provide  the capability of accurately determining oil and gas royalties, among other  moneys owed, and to collect and account for such amounts in a timely  manner.

To accomplish this, Interior tasks its Office of Natural Resources Revenue  (ONRR) with collecting and verifying the accuracy of royalties paid by  companies that produce oil and gas from over 26,000 federal leases.  Each month, these oil and gas companies are to self-report data to  ONRR on the amount of oil and gas they produced and sold, the value of  this production, and the amount of royalties that they owe to the federal  government. To ensure that the data provided to ONRR are accurate and  all royalties are being paid, ONRR relies on its compliance program.  Under this program, ONRR initiates compliance activities by selecting  companies and properties for review to assess the accuracy of their  royalty data and their compliance with all relevant laws and regulations.

Under the Minerals Leasing Act of 1920, Interior is authorized to collect  royalties on oil and gas produced on federal lands, and BLM is required to  ensure that operators producing oil and gas take all reasonable  precautions to prevent the waste of oil or gas developed on these lands.  While most of the natural gas produced on leased federal lands and  waters is sold and therefore royalties are paid on it, some is lost during  production for various reasons, such as leaks or intentional releases for  ongoing operational or safety procedures. Natural gas that is released for  operational or safety procedures is released directly into the atmosphere  (vented) or burned (flared). In addition to gas that is lost during  production, some natural gas may be used to operate equipment on the  lease (lease use). We use the term natural gas emissions to refer to  vented, flared, and lease use gas collectively. Interior has generally  exempted operators from paying royalties on reported natural gas  emissions, and so such emissions represent a loss of royalty revenues for  the federal government.

Venting and flaring natural gas also has environmental implications as it  adds greenhouse gases to the atmosphere—primarily methane and  carbon dioxide. Natural gas consists primarily of methane, and methane  (which is released through venting) is 34 times more potent by weight  than carbon dioxide (which is released through flaring) in its ability to  warm the atmosphere over a 100-year period, and 86 times more potent  over a 20-year period, according to the Intergovernmental Panel on  Climate Change.

Key Terms and Conditions for Federal Oil, Gas, and Coal Leases Are the Same as They Were Decades Ago, though Market Conditions Have Changed

Key federal lease terms are the same as they were decades ago, and  Interior has not adjusted lease terms for inflation or other factors, such as  changes in market conditions, which may affect the government’s fair  return. In addition, preliminary observations from our ongoing work  indicate that federal oil and gas lease terms and practices differ from  those of selected states, with selected state governments generally  charging higher royalty rates on production on state lands than the federal  government charges for production on federal lands. We have previously  recommended that Interior should establish procedures for determining  when to conduct periodic assessments of the oil and gas fiscal system,  including how the federal government’s share of revenues compares with  those of other resource owners. Interior has established procedures for  determining when to conduct periodic assessments of the oil and gas  fiscal system, and according to its policy, BLM plans to complete the next  assessment in late 2019.

Key Federal Lease Terms Are the Same as They Were Decades Ago though Market Conditions Have Changed

Key federal lease terms are the same as statutory minimums established  decades ago. For onshore oil and gas leases, the minimum royalty rate of  12.5 percent has been in place since 1920, and minimum bonus bids and  rental rates are currently set at the statutory minimums established in  1987. For coal, the royalty rate for surface mining is set at the statutory  minimum set in the Mineral Leasing Act.

We previously found that royalty rates for oil and gas leases have not  been adjusted to account for changes in market conditions, and our  preliminary analysis for our ongoing work suggests that adjusting rental  rates for inflation could generate increased federal revenues. We reported  in December 2013 that Interior offers onshore leases with lease terms— terms lasting the life of the lease—that have not been adjusted in  response to changing market conditions, potentially foregoing a  considerable amount of revenue. Energy markets have also changed  since federal oil and gas lease terms were established. For example, we  reported in June 2017 that, according to the U.S. Energy Information  Administration, almost all of the recent increase in overall oil and gas  production had centered on oil and gas located in shale and other tight  rock geologic formations, spurred by advances in production technologies  such as horizontal drilling and hydraulic fracturing. In addition, we  estimate that, based on preliminary observations, the rental rate would be  $2.91 per acre if it were adjusted for inflation, which would have  generated about $3.6 million for the first year for new leases issued in  fiscal year 2018, or an additional $1.8 million.

In June 2017, we reported that raising federal royalty rates for onshore  oil, gas, and coal resources could decrease oil and gas production on  federal lands by either a small amount or not at all but could increase  overall federal revenue, according to studies we reviewed and  stakeholders we interviewed. The two oil and gas studies we reviewed  for that report modeled the effects of different policy scenarios on oil and  gas production on federal lands and estimated that raising the federal  royalty rate could increase net federal revenue from $5 million to $38  million per year. One of the studies stated that net federal revenue would  increase under three scenarios that modeled raising the royalty rate from  the current 12.5 percent to 16.67 percent, 18.75 percent, or 22.5 percent.  The other study noted that the effect on federal revenue would initially be  small but would increase over time.

The two coal studies we reviewed for our June 2017 report analyzed the  effects of different policy scenarios on coal production on federal lands,  and both studies suggested that a higher royalty rate could lead to an  increase in federal revenues. Specifically, one study suggested that  raising the royalty rate to 17 percent or 29 percent might increase federal  revenue by up to $365 million per year after 2025. The other study  suggested that increasing the effective rate could bring in an additional  $141 million per year in royalty revenue. However, we reported that the  extent of these effects was uncertain and depended, according to  stakeholders, on several other factors, such as market conditions and  prices.

Federal Onshore Lease Terms Differ from Those of Selected States

Based on preliminary observations from our ongoing work, federal  onshore lease terms and practices for oil and gas development differ from  those of selected states (see table 1). For example, selected state  governments tend to charge higher royalty rates for oil and gas  development on state lands than the federal government charges for  production on federal lands.

For coal production, we reported in June 2017 that royalty rates charged  by selected states were generally the same as federal rates. Royalty  rates for the six states representing over 90 percent of total federal oil,  gas, and coal production in fiscal year 2015 ranged from 8 to 12.5 percent  for surface coal and from 8 to 10 percent for underground coal.

Other factors influence the competitiveness of the development of oil and  gas resources on federal land versus nonfederal land. We also reported  in June 2017 that some stakeholders we spoke with stated that there was  already a higher regulatory burden for oil and gas companies to develop  resources on federal lands than on nonfederal lands. For coal, BLM  officials stated that—assuming the royalty rate was the same—the main  difference between federal and nonfederal coal was the additional  regulatory burden of producing on federal lands.

In our ongoing work examining the oil and gas lease permitting process,  our preliminary interviews indicate that drilling permit fees are higher for  federal lands than for the states we reviewed. However, operators we  interviewed said that the filing fee was not an important or major factor in  their decisions to apply for federal drilling permits.

In addition to regulatory differences, in June 2017 we reported that a few  stakeholders told us that competitiveness of federal lands for  development depends on the location of the best resources—such as  areas with low exploration and production costs. We also reported in June  2017 that most areas with major U.S. tight oil and shale gas plays—areas  of known oil and gas sharing similar properties—and major U.S. coal  basins do not overlap with federal lands.

Interior Has Taken Steps to Assess Its Oil and Gas Lease Terms and Conditions

We have reported on steps Interior has taken to assess its oil and gas  fiscal system—the terms and conditions under which the federal  government collects revenues from production on leases—and have  made recommendations intended to help ensure that the federal  government receives a fair return on its oil and gas resources. For  example, in September 2008, we found that Interior had not evaluated the  federal oil and gas fiscal system for over 25 years and recommended that  a periodic assessment was needed. In response to our September 2008  report, Interior contracted for a study that was completed in October 2011  and compared the federal oil and gas fiscal systems of selected federal  oil and gas regions to that of other resource owners. However, in  December 2013, we reported that Interior officials said that the study was  not adequate to determine next steps for onshore lease terms.

Interior has considered making changes to improve its management of  federal oil and gas resources. For example, in April 2015, BLM sought  comments on a number of potential reforms to the oil and gas leasing  process, including changing royalty rates, but took no further action. In  November 2016, BLM did issue the Methane and Waste Prevention Rule,  which incorporated flexibility for the bureau to make changes to onshore  royalty rates, as we recommended in December 2013. Officials told us  in October 2018 that they were not aware of BLM issuing any recent  competitive leases with a royalty rate higher than 12.5 percent.

In addition, in March 2017, the Secretary of the Interior established the  Royalty Policy Committee (committee), which was to be comprised of  stakeholders representing federal agencies, states, Indian tribes, mining  and energy, academia, and public interest groups. The purpose of the  committee was to advise the Secretary on the fair market value of mineral  resources developed on federal lands, among other issues. The  committee met four times over the 2 years it was in effect and approved  recommendations related to Interior’s oversight of its oil and gas  programs. This included two recommendations to conduct studies that  compare the U.S. oil and gas fiscal system to certain other countries’  fiscal systems. However, a U.S. District Court found that the  establishment of the committee violated the law and prohibited Interior  from relying on any of the committee’s recommendations.

Interior has established procedures for assessing the oil and gas fiscal  system. In December 2013, we found that Interior did not have  documented procedures for determining when to conduct additional  periodic assessments of the oil and gas fiscal system, and we  recommended that Interior put such procedures in place. Further, we  reported that documented procedures could help Interior ensure that its  evaluations take relevant factors into consideration. These factors may  change over time as the market for oil and gas, the technologies used to  explore and produce oil and gas, or the broader economic climate  changes. In August 2016, in response to our recommendation, Interior  reported that it had developed documented procedures for conducting  assessments of the oil and gas fiscal system, fully implementing our  recommendation. To meet this recommendation, BLM established a fiscal  assessment policy that describes actions it will take every 3 years and  every 10 years. Based on this policy, the next assessment is expected to  be completed in late 2019. According to the policy, every 3 years BLM  plans to conduct a review of the oil and gas fiscal systems of the states  with significant oil and gas leasing activity where there is also significant  federal onshore leasing activity. The policy states that every 10 years— depending on available appropriations—Interior plans to co-sponsor with  the Bureau of Ocean Energy Management an independent study of  government take from lease and development of federal oil and gas  resources. In February 2019, as part of our ongoing work examining oil  and gas leases, BLM officials told us that the bureau had contracted for  an external fiscal assessment in 2018 and that the report would be  completed in mid-2019. According to Interior officials, the study is  undergoing final review.

Weaknesses in Coal, Oil, and Gas Bonding Present Financial Risks to the Federal Government

We have reported that weaknesses with bonds for coal mining and for oil  and gas development pose a financial risk to the federal government as  laws, regulations, or agency practices have not been adjusted to reflect  current economic circumstances. We have also reported that BLM has no  mechanism to pay for reclaiming well sites that operators have not  reclaimed.

Coal Self-Bonding Presents a Financial Risk to the Government

We reported in March 2018 that self-bonding for coal mining creates a  financial risk for the federal government. If specific conditions are met,  SMCRA allows states to let an operator guarantee the cost for reclaiming  a mine on the basis of its own finances—a practice known as self- bonding—rather than by securing a bond through another company or  providing collateral, such as cash, letters of credit, or real property. We  reported that as of 2017, eight states held coal self-bonds worth over $1.1  billion. In the event a self-bonded operator becomes bankrupt and the  regulatory authority is not able to collect sufficient funds to complete the  reclamation plan, the burden could fall on taxpayers to fund reclamation.

According to stakeholders we interviewed for our March 2018 report, self- bonding for coal mining presents a financial risk to the federal  government for several reasons. It is difficult to (1) ascertain the financial  health of an operator, in part, because greater financial expertise is often  now needed to evaluate the complex financial structures of large coal  companies as compared to when self-bonding regulations were first  approved in 1983; (2) determine whether an operator qualifies for self- bonding; and (3) secure a replacement for existing self-bonds when an  operator no longer qualifies.

For example, some stakeholders we interviewed told us that the risk from  self-bonding is greater now than when OSMRE first approved its self- bonding regulations in 1983; at that time, the office noted there were  companies financially sound enough that the probability of bankruptcy  was small. However, according to an August 2016 OSMRE policy  advisory, three of the largest coal companies in the United States  declared bankruptcy in 2015 and 2016, and these companies held  approximately $2 billion in self-bonds at the time. Because SMCRA  explicitly allows states to decide whether to accept self-bonds, eliminating  the risk that self-bonds pose to the federal government and states would  require SMCRA to be amended. In our March 2018 report, we  recommended that Congress consider amending SMCRA to eliminate  self-bonding. Interior did not provide written comments on the report.

Oil and Gas Bonds Do Not Provide Sufficient Financial Assurance to Prevent Orphaned Wells

We reported in September 2019 that bonds held by BLM have not  provided sufficient financial assurance to prevent orphaned oil and gas  wells on federal lands. Specifically, we reported that BLM identified 89  new orphaned wells from July 2017 through April 2019, and 13 BLM field  offices identified about $46 million in estimated potential reclamation  costs associated with orphaned wells and inactive wells that officials  deemed to be at risk of becoming orphaned in 2018. Although BLM does  not estimate reclamation costs for all wells, it has estimated reclamation  costs for thousands of wells whose operators have filed for bankruptcy.  Based on our analysis of these estimates, we identified two cost  scenarios: low-cost wells typically cost about $20,000 to reclaim, and  high-cost wells typically cost about $145,000 to reclaim.

In our September 2019 report, based on our cost scenarios described  above, we found that most bonds (84 percent) that we were able to link to  wells in BLM data are likely too low to fund reclamation costs for all the  wells they cover. Bonds generally do not reflect reclamation costs  because most bonds are set at regulatory minimum values, and these  minimums have not been adjusted to account for inflation since they were  first set in the 1950s and 1960s, as shown in figure 1. In addition, these  minimums do not account for variables, such as the number of wells they  cover, or other characteristics that affect reclamation costs, such as  increasing well depth.

In addition to the wells identified by BLM as orphaned over the last  decade, in our September 2019 report we identified inactive wells at  increased risk of becoming orphaned and found their bonds are often not  sufficient to reclaim the wells. Our analysis of BLM bond value data as of  May 2018 and ONRR production data as of June 2017 revealed that a  significant number of inactive wells remain unplugged and could be at  increased risk of becoming orphaned. Specifically, we identified 2,294  wells that may be at increased risk of becoming orphaned because they  have not produced since June 2008 and have not been reclaimed.

Since these at-risk wells are unlikely to produce again, an operator  bankruptcy could lead to orphaned wells unless bonds are adequate to  reclaim them. In our September 2019 report, we stated that if the number  of at-risk wells is multiplied by our low-cost reclamation scenario of  $20,000, it implies a cost of about $46 million to reclaim these wells. If the  number of these wells is multiplied by our high-cost reclamation scenario  of $145,000, it implies a cost of about $333 million. When we further  analyzed the available bonds for these at-risk wells, we found that most of  these wells (about 77 percent) had bonds that would be too low to fully  reclaim the at-risk wells under our low-cost scenario. More than 97  percent of these at-risk wells have bonds that would not fully reclaim the  wells under our high-cost scenario. Without taking steps to adjust bond  levels to more closely reflect expected reclamation costs, BLM faces  ongoing risks that not all wells will be completely and timely reclaimed, as  required by law. We recommended in our September 2019 report that  BLM take steps to adjust bond levels to more closely reflect expected  reclamation costs. BLM concurred with our recommendation. However,  while BLM stated it had updated its bond review policy, it is unclear  whether the updated policy will improve BLM’s ability to secure bond  increases.

BLM Does Not Currently Assess User Fees to Fund Orphaned Well Reclamation

In addition to fulfilling its responsibility to prevent new orphaned wells, it  falls to BLM to reclaim wells that are currently orphaned, and BLM has  not always been able to do so quickly. For example, we reported in  September 2019 that there were 51 wells that BLM identified as orphaned  in 2009, and that they had not been reclaimed as of April 2019. As noted  above, BLM faces significant estimated potential reclamation costs  associated with orphaned wells and inactive wells.

The Energy Policy Act of 2005 directs Interior to establish a program that,  among other things, provides for the identification and recovery of  reclamation costs from persons or other entities currently providing a  bond or other financial assurance for an oil or gas well that is orphaned,  abandoned, or idled. In our September 2019 report we described one  way in which BLM may be able to accomplish this is through the  imposition of user fees, such as at the time an operator submits an  application for permit to drill or as an annual fee for inactive wells. Some  states, such as Wyoming, have dedicated funds for reclaiming orphaned  wells. According to one official we interviewed with the Wyoming Oil and  Gas Conservation Commission, the Commission has reclaimed  approximately 2,215 wells since 2014 under its Orphan Well Program,  which is funded through a conservation tax assessed on the sale of oil  and natural gas produced in the state. Developing a mechanism to obtain  funds from operators for such costs could help ensure that BLM can  reclaim wells completely and timely. In commenting on a draft of our  September 2019 report, BLM stated that it does not have the authority to  seek or collect fees from lease operators to reclaim orphaned wells. We  continue to believe a mechanism for BLM to obtain funds from oil and gas  operators to cover the costs of reclamation of orphaned wells could help  ensure BLM can completely and timely reclaim these wells, some of  which have been orphaned for at least 10 years. Accordingly, in our  September 2019 report, we recommended that Congress consider giving  BLM the authority to obtain funds from operators to reclaim orphaned  wells and requiring BLM to implement a mechanism to obtain sufficient  funds from operators for reclaiming orphaned wells.

ONRR Compliance Goals May Not Align with the Agency Mission to Account for Royalty Payments, Despite Agency Efforts to Improve Operations

In May 2019, we found that ONRR had begun implementing several  initiatives to help the agency operate more effectively, according to  ONRR officials. For example, in March 2017, ONRR initiated Boldly Go,  an effort to assess its organizational structure and identify and implement  potential improvements. ONRR was also in the process of implementing  a new electronic compliance case management and work paper tool  referred to as the Operations and Management Tool. According to ONRR  documents, this tool was to combine multiple systems into one and was  intended to serve a variety of functions. ONRR documents stated that the  tool is designed to be a single, standardized system that reduces manual  data entry, creates a single system of record for ONRR case data, offers  checks to eliminate data entry errors, and provides greater transparency  for outside auditors. The agency also introduced a new auditor training  curriculum in April 2018.

In our May 2019 report, we also found that ONRR reported generally  meeting its annual royalty compliance goals for fiscal years 2010 through  2017. However, we found that while ONRR’s fiscal year 2017  compliance goals could be useful for assessing certain aspects of  ONRR’s performance, they may not have been effectively aligned with  the agency’s statutory requirements or its mission to account for all  royalty payments. For example, ONRR’s fiscal year 2017 compliance  goals did not sufficiently address its mission to collect, account for, and  verify revenues, in part, because its goals did not address accuracy, such  as a coverage goal (e.g., identifying the number of companies or  percentage of royalties subject to compliance activities over a set period).

We stated that by establishing a coverage goal that aligns with the  agency’s mission, ONRR could have additional assurance that its  compliance program was assessing the extent to which oil and gas  royalty payments were accurate. Overall, we made seven  recommendations, including that ONRR establish an accuracy goal that  addresses coverage that aligns with its mission. Interior concurred with  our recommendations.

Limitations Exist in Interior’s Accounting and Management of Natural Gas Emissions

We issued reports in October 2010 and July 2016 that included several  recommendations regarding steps Interior should take to better account  for and manage natural gas emissions associated with oil and gas  development. In October 2010, we reported that data collected by  Interior to track venting and flaring on federal leases likely underestimated  venting and flaring because they do not account for all sources of lost  gas. For onshore federal leases, operators reported to Interior that about  0.13 percent of produced gas was vented or flared. Estimates from the  Environmental Protection Agency and the Western Regional Air  Partnership showed volumes as high as 30 times higher. We reported  that economically capturing onshore vented and flared natural gas with  then-available control technologies could increase federal royalty  payments by $23 million annually. We also found limitations in how  Interior was overseeing venting and flaring on federal leases, and made  five recommendations geared toward ensuring that Interior had a  complete picture of venting and flaring and took steps to reduce this lost  gas where economic to do so. Interior generally concurred with our  recommendations.

In July 2016, we found that limitations in Interior’s guidance for oil and  gas operators regarding their reporting requirements could hinder the  extent to which the agency can account for natural gas emissions on  federal lands. Without such data, Interior could not ensure that operators  were minimizing waste and that BLM was collecting all royalties that were  owed to the federal government. We recommended, among other things,  that BLM provide additional guidance for operators on how to estimate  natural gas emissions from oil and gas produced on federal leases. BLM  concurred with the recommendation.

Interior has taken steps to implement our past recommendations  regarding the control of natural gas. Accounting for natural gas is  important for ensuring that the federal government receives all royalties it  is due and because methane—which comprises approximately 80  percent of natural gas emissions—is a potent greenhouse gas that has  the ability to warm the atmosphere. In addition, we reported in July 2016  that increased oil production in recent years has resulted in an increase in  flared gas in certain regions where there is limited infrastructure to  transport or process gas associated with oil production. In November  2016, Interior issued regulations intended to reduce wasteful emissions  from onshore oil and gas production that were consistent with our  recommendations. In June 2017, however, Interior postponed the  compliance dates for relevant sections of the new regulations and then  suspended certain requirements in December 2017. Interior subsequently  issued revised regulations in September 2018 that are not consistent with  the findings and recommendations in our prior work.

In our prior work and preliminary observations in our ongoing work, we  have found that some states have requirements that are more stringent  than BLM’s regarding accounting for and managing natural gas  emissions. For example, we reported in July 2016 that North Dakota  targeted the amount of gas flared from two geologic formations in the  state by imposing restrictions on the amount of gas operators may flare  from existing and new sources. We also reported that North Dakota  requires operators to include a gas capture plan when they apply to drill a  new oil well. According to state officials we interviewed for our report, gas  capture plans help facilitate discussions between oil producers and firms  that process and transport gas and have improved the speed at which  new wells are connected to gas gathering infrastructure. In the course of  our ongoing work, we obtained documents indicating that per its  regulations, North Dakota requires all gas produced and used on a lease  for fuel purposes or that is flared must be measured or estimated and  reported monthly, and that all vented gas be burned and the volume  reported.

In addition, based on preliminary observations in our ongoing work,  Colorado and Texas both charge royalties on vented and flared gas  volumes. In the course of our ongoing work, we obtained documents  indicating that the Colorado Oil and Gas Conservation Commission,  which regulates oil and gas activity in the state, addresses both venting  and flaring as well as leaks. Colorado officials we interviewed with the  State Land Board told us in September 2019 that, since 2018, the state  charges royalties on all vented and flared gas volumes, with certain  exceptions. These officials told us that prior to 2018, vented and flared  gas could be exempt from royalties, but that it was uncommon. In  addition, in Texas, a state official we interviewed told us that vented or  flared volumes must be reported monthly and that charging royalties on  these volumes increases revenues.

Chairman Lowenthal, Ranking Member Gosar, and Members of the  Subcommittee, this completes my prepared testimony. I would be pleased  to respond to any questions you may have at this time.

If you or your staff have any questions about this testimony, please  contact Frank Rusco, Director, Natural Resources and Environment at  (202) 512-3841 or RuscoF@gao.gov. Contact points for our Offices of  Congressional Relations and Public Affairs may be found on the last page  of this testimony. GAO staff who made key contributions to this testimony  are Quindi Franco (Assistant Director), Marie Bancroft (Analyst-In- Charge), Antoinette Capaccio, John Delicath, Jonathan Dent, Elizabeth  Erdmann, Glenn C. Fischer, Emily Gamelin, William Gerard, Cindy  Gilbert, Holly Halifax, Richard P. Johnson, Christine Kehr, Michael  Kendix, Greg Marchand, Jon Muchin, Marietta Mayfield Revesz, Dan  Royer, and Kiki Theodoropoulos.

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The Department of the Interior oversees energy production on federal lands, and is responsible for ensuring that companies pay a fair return for accessing federal energy resources.

We testified on many ways that Interior could better manage these resources. (In fact, we put Interior’s management of federal oil and gas resources on our High Risk List in 2011.)

For example, in the past we recommended controlling natural gas emissions on federal lands to ensure positive monetary and environmental effects. Although Interior issued regulations in 2016 to reduce wasteful emissions, by 2018 they were revised, inconsistent with our recommendations.