Federal Energy Development: Challenges to Ensuring a Fair Return for Federal Energy Resources
Released: 2019-09-24T00:00:00

Letter

Background

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.

Oil, Gas, and Coal Bonding

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.

Federal Oil and Gas Royalty Compliance

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.

Natural Gas Emissions on Federal Lands

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.

GAO Contacts and Staff Acknowledgments

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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