Oil and Gas: Interior Could Do More to Account for and Manage Natural Gas Emissions
Released: 2016-07-21T00:00:00

Letter

Background

This section provides an overview of (1) the oil and gas production process and release of natural gas emissions, (2) the recent oil production boom and associated natural gas, and (3) Interior’s reporting requirements on natural gas emissions.

The Oil and Gas Production Process and Release of Natural Gas Emissions

The oil and gas production process on federal leases involves several stages, including the drilling, development, and initial production of these hydrocarbons along with routine operation and maintenance activities throughout the life of a field. Throughout these stages, operators typically vent or flare some natural gas, often intermittently (see fig. 1). Venting is the direct release of natural gas into the atmosphere, and flaring is the release of natural gas to a flare stack where it can be safely combusted. Although gas may be vented or flared throughout these stages, where feasible, flaring is generally preferable to venting because it can prevent accidental fires or explosions and it reduces the climate impact of oil and gas production. Leaks, or “fugitive” emissions, may occur at any stage of the production process.

The Recent Oil Production Boom and Associated Natural Gas

The combination of advances in horizontal drilling techniques and hydraulic fracturing along with relatively high oil prices in the past few years have allowed the development of oil and natural gas from unconventional reservoirs, such as shale formations that were previously uneconomical to develop, and have led to historically high production levels. In a September 2012 report, we found that from 2007 to 2011 shale oil production increased more than fivefold, and shale gas production increased more than fourfold—driving increases in U.S. oil and gas production. Oil and natural gas are often found together in the same reservoir but may vary in relative amounts. In areas where the primary purpose of drilling is to produce oil, operators may flare associated natural gas because no local market exists for the gas and transporting it to a distant market may not be economically feasible. For onshore oil and gas production on federal lands, rapid development occurred in states such as New Mexico and North Dakota, and the bulk of the flaring took place in areas overseen by a handful of BLM offices in those two states. As shown in figure 2, of the 33 BLM field offices that manage oil and gas production, most of the flaring reported on federal lands that occurred in calendar year 2013 occurred in North Dakota, New Mexico, and South Dakota, managed primarily by BLM field offices in Carlsbad, New Mexico, and Dickinson, North Dakota.

Interior’s Reporting Requirements on Natural Gas Emissions

Several federal regulations apply to Interior’s management of natural gas emissions and operators’ responsibilities to report these emissions.

First, federal regulations require an authorizing officer at Interior to oversee and enforce regulations related to the development of and operations on federal oil and gas leases (see fig. 3). Authorizing officers or “supervisors” are typically BLM field office officials who approve venting or flaring requests. Venting, flaring, and other royalty-free uses of oil and natural gas on BLM-administered leases are currently governed by BLM guidance known as Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases (NTL-4A), which the U.S. Geological Survey issued in 1979, before BLM assumed oversight responsibility for onshore oil and gas development and production. NTL- 4A generally prohibits venting or flaring of gas, but provides for a number of exemptions to this prohibition, both for short-term or emergency venting or flaring and for venting or flaring for longer periods (i.e., long- term), if operators obtain supervisory approval in advance.

Second, federal regulations call for royalties to be computed based on the quantity and quality of produced, unprocessed gas at a measurement point approved by BLM. Losses of gas (i.e., those from natural gas emissions) are generally not subject to royalties provided that such losses meet BLM requirements. However, BLM field office supervisors apply criteria set in NTL-4A to determine whether approved gas lost through venting or flaring is “unavoidably lost,” and therefore royalty-free, or “avoidably lost,” and therefore subject to royalties. For example, under NTL-4A, venting or flaring gas vapors released from storage tanks or low pressure production vessels is generally considered to be unavoidably lost, and no royalties are due. However, BLM supervisors may determine that vented or flared gas is avoidably lost if (1) the losses are due to negligence on the part of the lessee or operator; (2) the losses are due to the failure of the lessee or operator to take all reasonable measures to prevent or to control the losses; or (3) the losses are due to the failure of the lessee or operator to comply fully with the applicable lease terms and regulations, appropriate provisions of the approved operating plan, or the prior written orders of the supervisor. Generally, operators are to submit venting or flaring requests to a supervisor at their local BLM field office in advance to obtain an approval and determination of whether losses are unavoidable or avoidable. BLM field office officials we spoke with told us, however, that because of backlogs in the venting or flaring requests submitted to BLM, operators may sometimes seek and obtain verbal approval to vent or flare, and then later submit a written request once venting or flaring is under way. In addition, NTL-4A provides that no royalty obligation shall accrue on any produced gas that is used on the same lease for beneficial purposes (i.e., lease use). This royalty exception is sometimes referred to as the beneficial use or lease use exception.

Third, federal regulations require operators to report monthly oil and gas production to Interior on the OGOR. Moreover, NTL-4A provides that the volume of oil or gas produced, whether sold, avoidably or unavoidably lost, vented or flared, or used on lease, must be reported. To assist operators in fulfilling Interior’s reporting requirements for oil and gas produced on federal leases, ONRR’s Minerals Production Reporter Handbook provides instructions on how to complete the OGOR, including a description of various reporting categories. The handbook includes several categories for natural gas emissions that are royalty-free, including categories for vented gas associated with oil wells, vented gas associated with gas wells, flared gas associated with oil wells, flared gas associated with gas wells, lease use gas, gas that is “spilled and/or lost” unavoidably, and gas lost to evaporation or shrinkage. The handbook also includes categories for natural gas emissions that are royalty- bearing, specifically for gas that is spilled and/or lost avoidably.

Interior’s Guidance to Operators on Reporting Requirements Has Limitations That May Hinder the Extent to Which It Can Account for Natural Gas Emissions

Interior’s limited guidance to operators on how to report natural gas emissions on the OGOR may hinder the extent to which it can account for such emissions. Interior officials told us that their focus has historically been on collecting data on royalty-bearing oil and gas production rather than on natural gas emissions, which until recently have generally been royalty-free. Thus, the guidance Interior has provided to operators on how to report natural gas emissions has not ensured that these data are consistent and complete. Without such data, Interior cannot ensure that operators are minimizing waste on federal oil and gas leases and collecting all royalties that are owed.

We identified several key limitations with Interior’s guidance for operators OGOR reporting that may hinder Interior’s ability to accurately account for natural gas emissions and potentially collect royalties when appropriate. First, Interior’s guidance does not provide specific instructions on how to estimate natural gas emissions on the OGOR. Second, Interior provides limited guidance on which OGOR reporting categories operators are to use to report flared volumes. Third, Interior’s guidance does not specify which activities are to be reported under OGOR categories for natural gas emissions. In addition, Interior does not require operators to differentiate between types of lease use volumes reported on the OGOR, which, going forward, could help Interior track progress toward its new goals for methane reduction. If finalized, BLM’s recently proposed methane and waste reduction regulations could clarify and alter BLM’s policies on natural gas emissions, but these proposed regulations do not address the key limitations in reporting and accounting for emissions that we identified.

Interior does not provide specific instructions on how to estimate natural gas emissions on the OGOR. Interior’s guidance to operators for reporting natural gas emissions on the OGOR does not specify how they are to estimate reported natural gas emissions that have occurred without measurement. Instead, BLM’s guidance on natural gas emissions, NTL- 4A, provides a list of eight general methods operators shall use to estimate emissions, which include, among others, the use of historic production data or estimates based on the expected production of other nearby wells. However, NTL-4A does not provide any specific detail or instruction on how to develop estimates of natural gas emissions based on these general methods. Furthermore, the guidance allows for use of any estimation method that is approved by a BLM supervisor. With regard to measurement, BLM’s Onshore Oil and Gas Order No. 5 provides guidance on how to measure gas production but it does not provide any specific guidance on estimating natural gas emissions. In addition, BLM’s proposed methane and waste reduction regulations contain provisions that require operators to report quantities of all vented or flared gas, and to meter flared volumes when gas flaring meets or exceeds certain thresholds, but contain no guidance on how to estimate or measure natural gas emissions below those thresholds.

In the absence of guidance with specific instructions on how to estimate natural gas emissions, we found that operators may use varying approaches to estimate emissions. Specifically, some BLM field office officials we interviewed told us that operators may meter long-term flaring volumes but use various techniques to estimate short-term flaring, venting, and lease use emissions. Some BLM field office officials that we spoke with also said that for short-term flaring, operators may rely on “gas to oil ratios” where the gas is metered temporarily to establish the ratio between associated gas and produced oil to estimate nonmetered flaring volumes. For venting and lease use volumes, however, BLM field office officials we interviewed told us that operators may use engineering estimates based on equipment specifications, which can vary—even for the same piece of equipment—based on the assumptions made by individual operators.

Without specific instructions from BLM on how to develop estimates of natural gas emissions, it may also be difficult for BLM’s production accountability staff to determine which method operators are using to estimate natural gas emissions and to verify their accuracy during periodic records reviews. For example, one operator we interviewed told us that until 2 years ago, officials at the company used rough estimates to report volumes of vented, flared, or lease use gas on the OGOR, but the company recently changed course and adopted the estimation techniques EPA prescribed in its regulations for its Greenhouse Gas Reporting Program. In contrast, another operator we interviewed told us that it continues to estimate natural gas emissions based on history and experience in the field. In addition, in our limited analysis of five detailed records that BLM provided to us—which contained operators’ documentation of natural gas emissions volumes—we found that only one operator reported lease use gas, and for that case, we could not determine which method the operator used to estimate lease use volumes. Although some BLM field office officials we spoke with told us they felt that the OGOR volume estimates were fairly reliable, without consistent accounting, Interior does not have the information it needs to have reasonable assurance that it is minimizing waste on federal oil and gas leases.

Interior provides limited guidance on which OGOR categories operators are to use to report flared volumes. Interior provides limited agency-wide guidance to operators on which OGOR categories to use when reporting volumes of flared gas, and only two BLM field offices we reviewed provide any additional instruction. As described above, under BLM’s NTL-4A, field office supervisors have some discretion in determining whether an operator’s request to vent or flare beyond the initial production phase should be approved and is subject to royalties. If the BLM supervisor determines that a loss of natural gas occurs for reasons beyond the operator’s control, such as line failures or equipment malfunction, then the vented or flared volumes are deemed unavoidably lost and are royalty-free. If the BLM supervisor determines that the loss occurs for reasons such as negligence or the failure of lessee or operator to take all reasonable measures to prevent or control the loss of gas, then the vented or flared volumes are deemed avoidably lost and are royalty- bearing. Operators must report both royalty-free and royalty-bearing vented or flared gas volumes on the OGOR.

Based on interviews with BLM field office officials and our review of ONRR’s guidance, we found that operators use four different categories to report flared gas on the OGOR, and two of these categories may also include other types of nonflared emissions. Within the OGOR, there are two categories specifically dedicated to flared gas—one for gas flared from oil wells and one for gas flared from gas wells—both of which are for royalty-free volumes. However, in the absence of clear agency-wide guidance on how to report volumes of flared gas on the OGOR— particularly royalty-bearing flared gas—some BLM field offices have allowed operators to report such volumes under two additional categories.

One of these categories is for avoidably lost oil and gas spills, which also includes royalty-bearing leaks and spills. Since 2011, two BLM field offices we reviewed have instructed operators to use this category to report royalty-bearing flaring since there is currently no reporting category on the OGOR specifically for royalty-bearing flaring. However, even with such instructions in place, officials at one of these offices told us that records reviews have shown that operators sometimes erroneously report royalty-bearing flaring under the two royalty-free flaring categories on the OGOR. The second of these additional categories that operators have used to report flaring is the category for unavoidably lost oil and gas spills, which is a royalty-free category. Including flared gas volumes under these two additional categories—which commingle flared volumes with other types of emissions—makes it difficult for Interior to account for flaring on the OGOR. Moreover, because ONRR uses OGOR data to help validate royalty payments, Interior may not be able to reasonably ensure that operators are minimizing waste on federal oil and gas leases or that all royalties actually owed on flared gas are collected. BLM’s proposed methane and waste reduction regulations do not alter OGOR categories operators should use to report flared gas.

Interior does not clearly specify which activities are to be reported under OGOR reporting categories for natural gas emissions. Interior’s guidance to operators does not include specific criteria for which activities should be reported under OGOR reporting categories for natural gas emissions, and operators may not be reporting some of these activities. For example, in an October 2010 report, we found that operators did not report operational sources such as venting from oil storage tanks, pneumatic valves, or glycol dehydrators.

Some BLM field office officials we interviewed told us that operators still may not be reporting certain natural gas emissions activities on the OGOR. For example, officials at several BLM offices told us that operators generally do not report storage tank emissions. ONRR’s guidance does not specify which reporting category should be used to report such emissions, though its Minerals Production Reporter Handbook requires operators to report volumes from unavoidably lost production, which according to BLM’s guidance NTL-4A, includes gas vapors released from storage tanks or other low-pressure production vessels. In addition, officials at one BLM field office told us that while they believe gas emitted during well completions should be reported on the OGOR, they could not point to specific guidance instructing operators where to report such volumes and were not certain of the extent to which operators were actually reporting them.

Interior officials also told us that operators are not instructed to report— and typically do not report—natural gas emissions from system-wide leaks, although there is a reporting category for unavoidably spilled and/or lost volumes. One operator told us that leaks are typically too insignificant to be reported, while another stated that if there was a gas leak, they would probably report that under the OGOR reporting category for vented emissions. Similarly, there is no guidance to operators on where to report emissions from newer technologies, such as vapor recovery units and vapor combustion units, though one operator stated that it reports gas collected from vapor recovery units under the OGOR reporting category for gas that is sold. As a result of this uncertainty with the data, Interior may not have a clear accounting of natural gas emissions, which could limit Interior’s ability to ensure that lessees pay royalties in the proper amounts and minimize waste of natural gas. In its proposed regulations, BLM has not provided additional guidance to operators on which activities should be included under the natural gas emissions reporting categories on the OGOR.

Interior does not require operators to differentiate between types of lease use volumes reported on the OGOR. Interior’s OGOR reporting category for lease use gas does not distinguish between combusted and noncombusted emission volumes, making it more difficult for Interior to accurately track progress toward reducing greenhouse gases on federal lands. Natural gas consists primarily of methane, which when combusted becomes primarily water vapor and carbon dioxide. For example, when natural gas is used to run equipment like generators, the methane is converted into carbon dioxide in the combustion process. In contrast, when natural gas is used to run pneumatic equipment on a lease, like valves to control gas flows, the gas is not combusted. Instead, some natural gas is released into the atmosphere, mostly in the form of methane. Because methane has a much greater climate impact than carbon dioxide, the impact of using the same amount of natural gas in a pneumatic valve compared to a generator is very different. As a result of current OGOR reporting requirements, combusted and noncombusted lease use volumes are reported in a single OGOR reporting category— making it difficult for Interior to accurately estimate the greenhouse gas emissions from lease use volumes reported on the OGOR.

Although Interior does not require operators to report on greenhouse gas emission volumes on the OGOR, Interior’s OGOR database is the only federal database that tracks natural gas emissions on federal leases and therefore is the most useful source of data for Interior to use when tracking greenhouse gas emissions from federal lands. BLM’s proposed methane and waste reduction regulations would not require direct reporting on all greenhouse gas emissions, but having separate reporting categories for combusted and noncombusted lease use volumes could better position Interior to track progress against the new goals to cut methane emissions under the President’s Climate Action Plan’s Strategy to Reduce Methane Emissions.

BLM Has Not Consistently Followed Its Existing Guidance in Managing Operators’ Venting or Flaring Requests

BLM has approved operators’ requests to vent or flare gas royalty-free without having the documentation its guidance requires. Field offices have also applied BLM’s guidance differently, which has resulted in some field offices requiring royalty payments on flared gas while other field offices do not. However, BLM has recently proposed new methane and waste reduction regulations that may alter its management of venting or flaring requests in the future.

BLM Has Approved Many Venting or Flaring Requests That Do Not Comply with Its Guidance

BLM officials have approved many venting or flaring requests that do not comply with BLM’s existing guidance, NTL-4A, which requires operators to provide specific documentation for requests to vent or flare beyond a short-term basis. Generally, venting or flaring on a short-term basis in temporary or emergency circumstances is described in NTL-4A as “authorized venting or flaring of gas.” Alternatively, venting or flaring requests that are more long term in nature—described in NTL-4A as “other venting or flaring” of gas—may be approved if operators submit documentation that consists of (1) an evaluation report providing an economic and a geologic justification to flare or (2) an action plan that will eliminate venting or flaring of the gas within 1 year from the date of application.

Requests to vent or flare gas have increased substantially in recent years. BLM reported that venting or flaring requests rose from 50 in 2005 to over 600 in 2011 and to about 1,250 in 2014. Our analysis of venting or flaring requests for fiscal year 2014 indicates that operators submitted a total of 1,281 requests to vent or flare gas to 16 BLM field offices nationwide, with over 80 percent of these requests submitted to just two field offices: Carlsbad, New Mexico, and Dickinson, North Dakota. Officials in both of these offices told us that in recent years they have been short-staffed and have had to triage backlogs of over 1,000 venting or flaring requests against other priorities, such as processing drilling permits or permitting rights-of-way for gas gathering pipeline. Figure 4 presents the number of venting or flaring requests submitted to each field office in fiscal year 2014.

To better understand the reasons operators submitted requests to vent or flare gas and the extent to which BLM approved requests, we analyzed a random sample of 100 requests submitted to BLM field offices in fiscal year 2014. Based on our analysis of the sample, we estimate that 99 percent of operator submitted requests were requests to flare (rather than vent).

Based on our sample of venting or flaring requests, we found that operators cited a variety of reasons they needed to vent or flare. As shown in figure 5, the vast majority of the requests cited limitations with existing infrastructure as the reason the operators needed to vent or flare gas, such as constrained pipeline capacity or problems with receiving gas plants. In contrast, only an estimated 9 percent of the requests cited that wells were not connected to—or were waiting to be connected to—gas gathering infrastructure as the reason operators needed to vent or flare gas.

Based on our sample, we also found that almost all venting or flaring requests in fiscal year 2014 did not contain the documentation needed to meet the criteria described in BLM’s guidance NTL-4A for long-term venting or flaring or an explanation for authorized short-term venting or flaring. Specifically, we estimate that 90 percent of venting or flaring requests did not have the documentation for BLM to determine whether approval of long-term venting or flaring was justified or an explanation for authorized short-term venting or flaring. Figure 6 shows our estimates of the documentation that operators provided to BLM as a justification to vent or flare.

Nonetheless, we estimate that BLM approved about 70 percent of venting or flaring requests submitted in fiscal year 2014, and of the approved requests, roughly half were approved royalty-free (see fig. 7). We estimate that nearly all of the requests that BLM approved royalty-free did not include the documentation required for long-term venting or flaring.

In discussing our sample with BLM officials, these officials said that Interior recognizes there are systemic shortcomings in how venting or flaring requests are submitted and approved. As discussed above, Interior officials told us that their focus has historically been on collecting data on royalty-bearing oil and gas production, so natural gas emissions have received less attention. In addition, BLM field office officials have described heavy workloads and a shortage of personnel that have hindered their ability to review and approve the high volumes of venting or flaring requests they have received from operators. Thus, operators have submitted—and received BLM’s approvals for—venting or flaring requests that do not contain all of the documentation required by NTL-4A. However, without collecting and reviewing the required documentation BLM supervisors cannot demonstrate that they have followed existing guidance or that they have the necessary information to inform their decisions about whether venting or flaring is needed or whether such volumes should be subject to royalties.

Selected Field Offices Have Applied BLM Guidance Differently to Venting or Flaring Requests

Officials in the six field offices we reviewed interpreted NTL-4A differently with respect to charging royalties on approved venting or flaring, which may have resulted in the operators seeking to vent or flare not receiving consistent treatment across offices. Two of the six BLM field offices we reviewed—the Carlsbad, New Mexico, office and the Casper, Wyoming, office—approved long-term flaring of some gas but also determined that the flared gas was avoidably lost and therefore subject to royalties. The BLM field office in Dickinson, North Dakota, is also considering doing so. The other three field offices we reviewed—in Farmington, New Mexico; Miles City, Montana; and Vernal, Utah—have interpreted NTL-4A to mean that when the authorizing official approves a request to flare, the flared gas will be treated as unavoidably lost gas, which is royalty-free.

Officials we spoke with in the Carlsbad office told us that they charged royalties on flared gas because oil production in their region boomed and operators made an economic choice to flare gas associated with their oil wells—and pay the royalties—rather than wait until gas gathering pipeline was available. Before deciding to charge royalties, field office officials we interviewed told us that they met with operators in the region to determine when wells could be shut in without endangering reservoir life and recoverable reserves in order to help them determine whether flared gas in the region was avoidably or unavoidably lost. As a result of these discussions, these officials told us they concluded that within their region operators could generally restrict production at their established wells without endangering the amount of oil that these wells could ultimately produce. Therefore, these officials concluded that much of the gas flared from oil wells in the region was considered avoidably lost or “wasted gas” and therefore royalties were due. Further, field office officials told us that charging royalties on flared gas could provide a small incentive for operators to develop infrastructure for gathering gas from oil wells. According to our analysis of ONRR data, royalties from flaring from onshore federal leases generated $4.5 million in revenue in fiscal year 2014.

Officials in the Casper office told us that they followed Interior’s guidance, which they interpreted as allowing them to charge royalties on gas flared from oil wells under some circumstances. Specifically, the officials we interviewed told us that operators citing lack of infrastructure to transport gas produced on oil wells could be approved to flare royalty-free if they could economically justify the lack of infrastructure, such as by the cost to connect to the nearest available pipeline. However, operators citing lack of pipeline capacity on existing pipelines as a justification to flare would be required to pay royalties. This is because the operators would have generally chosen to expand their production beyond the capacity of the existing pipeline infrastructure, knowing that capacity constraints could result in the need to flare on some occasions.

Officials in the Dickinson office told us that they are considering charging royalties on some flared gas. As a result of an increase in flaring requests in recent years, as well as limited staff and a concurrent increase in the number of applications for drilling permits, this office faced a backlog of 2,211 flaring requests by August 2015. In that month, BLM officials in the Dickinson office proposed a formula for resolving 1,943 of their 2,211 pending flaring requests—requests for flaring that has already concluded. The proposed formula would assign the first 6 days of flaring as unavoidably lost (i.e., no royalties due) gas with flaring that exceeded the 6-day threshold as avoidably lost (i.e., royalties due) gas. For the remaining 268 of the 2,211 pending flaring requests—requests for flaring that was ongoing or may occur in the future—the field office proposed reviewing the merits of each request individually, as the guidance outlines, to determine whether gas was or would be avoidably or unavoidably lost. According to a field office official, however, operators formally objected to the proposed formula, so officials may have to review the merits of each venting or flaring request individually.

In the three other field offices we reviewed—Farmington, New Mexico; Miles City, Montana; and Vernal, Utah—officials cited various reasons for not charging royalties on approved long-term flaring requests. Overall, these offices tended to generalize about the industry in their regions and the need to vent or flare, approving all requests as unavoidably lost gas and royalty-free. For example, in the Farmington office, officials we spoke with told us that their region was dominated by gas development, so flaring was not as much an issue for their office. In the Miles City office, officials we interviewed told us that there was little associated gas at oil wells in their region, and that charging royalties on flared gas might make it more costly for operators to drill new wells or shorten the life of existing wells, which they were reluctant to do. In the Vernal office, officials we spoke with told us that they had considered charging royalties on flared gas, but they were concerned that the alternative to flaring—shutting in a well—might damage oil recoverability from wells in their region.

BLM’s Proposed Regulations May Alter How It Manages Future Venting or Flaring Requests

BLM’s proposed methane and waste reduction regulations would reduce the number of venting or flaring requests field offices officials will have to individually review and acknowledges the substantial variation in how it has interpreted and applied its existing guidance. In this regard, the proposed regulations, if adopted, would include updated guidance on which gas volumes should be considered avoidably or unavoidably lost. Specifically, instead of requiring BLM field office officials to review the merits of each flaring request individually, BLM proposes setting monthly flaring limits on each well with a requirement that operators meter flaring above certain monthly limits. According to officials, if upon inspection or review, an operator is found to be exceeding flaring limits, it would be subject to penalties for noncompliance with the regulations. However, operators could seek an exception from BLM to flare above the monthly per-well limit based on an economic and geologic justification similar to that required in the existing guidance. The proposed regulations also require operators to communicate their anticipated gas collection needs to pipeline operators at the time they apply to drill a new well, which may reduce an operator’s need to flare gas assuming the infrastructure is developed. The proposed regulations also would, among other things, mandate reductions in venting from pneumatic devices and require inspections to detect and repair leaks in the oil and gas production process. As discussed above, Interior officials we spoke with told us that BLM plans to finalize the proposed regulations by the end of calendar year 2016, and they told us that finalizing the proposed regulations is an Administration priority.

Conclusions

To fulfill its responsibility to ensure that operators use all reasonable precautions to prevent waste of oil or gas on federal leases, Interior must be able to account for oil and gas produced from these leases, including how it is sold, lost, or used. Natural gas emissions are an important component of this accounting and affect both BLM’s collection of royalties as well as its tracking of harmful greenhouse gas emissions from federal leases. Since Interior has historically focused on royalty-bearing oil and gas production and has limited guidance on how to report natural gas emissions, it cannot yet consistently account for these emissions on federal leases. Better guidance for OGOR reporting could improve Interior’s ability to account for natural gas emissions and better ensure that royalties are collected where appropriate on these emissions. Further, improved reporting from operators could also help Interior better track its efforts to curb greenhouse gases from federal leases and its new goals for methane reduction.

Recommendations for Executive Action

We are making four recommendations to the Secretary of the Interior.

To help improve reporting of emissions data on the OGOR, the Secretary of the Interior should direct BLM or ONRR, as appropriate, to take the following four actions:

BLM should provide additional guidance on how to estimate natural gas emissions from federal oil and gas leases.

ONRR should provide additional guidance on how to report royalty-free and royalty-bearing flaring and consider creating a separate category for royalty-bearing flaring; how to report certain unreported or underreported emissions, such as emissions from storage tanks and gas vented during well completions; and how to differentiate between combusted and noncombusted lease use volumes reported on the OGOR, which could assist Interior in measuring its progress toward greenhouse gas reduction goals.

Agency Comments and Our Evaluation

We provided our draft report to Interior for review and comment. Interior provided written comments, in which it concurred with two of the six recommendations in the draft report, partly concurred with two others, and did not concur with the remaining two recommendations. Interior’s comments reflected the views of BLM and ONRR. Interior’s comments are reproduced in appendix III and key areas are discussed below. Interior also provided technical comments, which we incorporated as appropriate.

Interior partially concurred with our third and fourth recommendations, which would have ONRR provide guidance on how to report certain unreported or underreported emissions and on how to differentiate between combusted and non-combusted lease use volumes on the OGOR, respectively. Regarding these recommendations, Interior said ONRR would defer to BLM to provide guidance on how the emissions discussed should be accounted for by Interior. Once these decisions are made, ONRR would work with BLM to develop requirements for reporting volumes on the OGOR and collecting royalties, as appropriate. We recognize that these actions will require a collaborative effort between ONRR and BLM, as noted in Interior’s letter, and if implemented as described, would address the intent of our third and fourth recommendations.

Interior did not concur with two recommendations included in the draft report, which would have BLM apply its existing guidance on venting and flaring and issue interim guidance on the circumstances under which long-term flaring would be subject to royalties, respectively. Regarding these recommendations, Interior noted that finalizing BLM’s proposed rule, the Methane and Waste Prevention Rule, will directly address many of the concerns pointed out in the findings and recommendations directed at BLM. In its letter, Interior stated that finalizing the proposed rule is an Administration priority, and that it expects the rule to be finalized by the end of calendar year 2016. Furthermore, Interior said that issuing interim guidance before the rule is finalized would divert resources from BLM’s rulemaking effort, and would likely create significant confusion among BLM staff and the industry when the new rule is issued several months later. In response to BLM’s timeframe and stated prioritization for finalizing its proposed rule, we removed these recommendations and modified the report accordingly.

As agreed with your offices, unless you publicly announce the contents of this report earlier, we plan no further distribution until 30 days from the report date. At that time, we will send copies to the appropriate congressional committees, the Secretary of the Interior, and other interested parties. In addition, the report will be available at no charge on the GAO website at http://www.gao.gov.

If you or your staff have any questions about this report, please contact me 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 report. GAO staff who made major contributions to this report are listed in appendix IV.

Appendix I: Regulatory Actions to Reduce Natural Gas Emissions in Selected States

Since operators of federal leases may be subject to state regulations and policies regarding natural gas emissions, we reviewed the regulatory activity in five states with high federal oil and gas production and emissions. One of the five states we reviewed—Colorado—has adopted regulations intended to reduce natural gas emissions from oil and gas produced on all lands in the state. Two others—North Dakota and Wyoming—have taken similar regulatory actions within specific areas of their states. Another state—Utah—has taken regulatory actions that indirectly address natural gas emissions. The fifth state we reviewed— New Mexico—recently took an action that may reduce natural gas emissions.

These states have undertaken various actions to address natural gas emissions, as follows:

Colorado: In February 2014, Colorado adopted regulations that apply statewide to limit venting and to capture fugitive emissions, such as those emissions that leak from equipment. These regulations include a requirement that operators collect or flare 95 percent of gas associated with new wells. In addition, operators are required to use leak detection equipment at oil and gas facilities across the state. Colorado’s leak detection requirements vary by the amount of emissions produced at a facility, with higher-producing facilities required to check for leaks more often. In addition, the regulations mandate the use of low-bleed pneumatic devices and increased the gas capture target for certain storage tanks.

North Dakota: North Dakota has 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. North Dakota has imposed gas capture targets to decrease flaring by setting goals for the amount of gas that operators must collect each year; these goals increase in later years. Operators are currently working to meet a gas capture target of 85 percent for November 2016. North Dakota also requires operators, when they apply to drill a new oil well, to include a gas capture plan. According to state officials, gas capture plans help facilitate discussions between oil producers and firms that process and transport gas, and they have improved the speed at which new wells are connected to gas gathering infrastructure. State officials also told us that to meet the state’s gas capture target, operators have reduced production at some wells and delayed completing others.

Wyoming: According to state officials, reducing vented natural gas emissions has been a focus for the state of Wyoming. Wyoming has an ozone nonattainment area in the Upper Green River Basin, and regulations require operators in the nonattainment area, among other things, to use leak detection equipment to identify facilities with fugitive emissions. Generally, operators must check for leaks quarterly under the state’s leak detection program, but according to state officials, operators with satisfactory prior performance records may be allowed to check for leaks less frequently. The regulations also require that operators replace high-bleed pneumatic controllers with low-bleed controllers. According to a state official, Wyoming is reviewing its flaring rules and considering requiring gas capture plans.

Utah: Utah has adopted regulations requiring oil and gas operators to minimize their emissions of volatile organic compounds—a group of chemicals that contribute to the formation of ground-level ozone— which effectively prohibit venting from oil and gas wells, according to a state official. According to this official, because Utah is concerned with the Uinta Basin being designated an ozone nonattainment area the state’s actions have been focused on reducing ozone in the area rather than on reducing volumes of flared gas.

New Mexico: According to state officials, New Mexico was considering actions that could reduce emissions from oil and gas leases in the state, including on federal leases, and in April 2016, the New Mexico Energy, Minerals and Natural Resources Department issued a notice to operators of a new gas capture planning requirement. Effective May 1, 2016, operators are required to submit a gas capture plan outlining actions to be taken to reduce venting and flaring at new well completions.

Appendix II: Objectives, Scope, and Methodology

This report examines (1) the extent to which the Department of the Interior (Interior) can account for natural gas emissions from onshore federal leases and (2) how selected Bureau of Land Management (BLM) field offices have managed requests to vent or flare natural gas emissions on onshore leases.

To conduct this work, we reviewed relevant laws, regulations, and BLM and Office of Natural Resources Revenue (ONRR) guidance. We also reviewed independent studies of Interior’s accounting of onshore natural gas emissions conducted by Interior’s Office of Inspector General as well as related reports prepared by other federal entities, such as the Environmental Protection Agency (EPA) and the Congressional Research Service. We also reviewed BLM’s proposed regulations to reduce waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases that were proposed in January 2016.

We interviewed officials from Interior’s offices responsible for accounting for onshore natural gas emissions—BLM and ONRR. Specifically, we interviewed BLM officials in BLM headquarters; BLM’s National Operations Center in Lakewood, Colorado; and six BLM field offices we selected primarily based on (1) the volume of flared gas emitted in that region, (2) the amount of lease use gas consumed in that region, and (3) the volume of vented gas in that region in fiscal year 2014, the most recent year for which complete data were available. These field offices are located in Carlsbad, New Mexico; Casper, Wyoming; Dickinson, North Dakota; Farmington, New Mexico; Miles City, Montana; and Vernal, Utah. We visited the two BLM field offices overseeing the largest amount of flaring—Carlsbad, New Mexico, and Dickinson, North Dakota. Because this was a nonprobability sample, our findings are not generalizable to other BLM field offices but help illustrate how some offices have accounted for and managed natural gas emissions. We also visited and interviewed officials at ONRR’s office in Lakewood, Colorado. In addition, we interviewed representatives from oil and gas companies (operators) and environmental organizations.

To examine the extent to which Interior can account for natural gas emissions from onshore federal leases, we reviewed the guidance Interior provides on reporting natural gas emissions, including BLM’s Notices to Lessees and instruction memorandums and ONRR’s Minerals Production Reporter Handbook. To examine the methodology used by operators to measure or estimate natural gas emissions, we reviewed the instructions in ONRR’s Minerals Production Reporter Handbook on how operators are to report natural gas emissions in monthly Oil and Gas Operations Reports (OGOR). We interviewed BLM and ONRR officials on how natural gas emissions are estimated and reported on the OGOR. We obtained contact information for operators from the field offices and interviewed representatives from four operators operating in New Mexico and North Dakota that were able to meet with us during our fieldwork. We asked them how they calculated and reported natural gas emission volumes for the OGOR. We examined five records provided by BLM for examples of documentation of natural gas emissions volumes that operators submitted to BLM for its records review. To examine the guidance BLM provides to operators regarding reporting flared volumes on the OGOR, we reviewed BLM’s existing guidance on venting and flaring—Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases (NTL-4A)—and interviewed officials from our selected field offices on how such volumes are to be reported on the OGOR. To compare Interior’s methodology for measuring and estimating natural gas emissions with that from another agency, we also examined how EPA collects emissions data from operators for its Greenhouse Gas Inventory and Greenhouse Gas Reporting programs.

To examine how selected BLM field offices managed requests to vent or flare natural gas emissions on onshore federal leases, we reviewed BLM regulations and documents and interviewed BLM officials. To examine BLM’s actions to implement NTL-4A, we analyzed all fiscal year 2014 venting or flaring requests recorded in BLM’s Automated Fluid Minerals Support System. Fiscal year 2014 was the most recent year for which BLM could provide complete data. Specifically, we examined electronic data for 1,281 venting or flaring requests that were sent to 17 BLM field offices nationwide. We assessed the reliability of these data by interviewing knowledgeable BLM officials responsible for data entry and compared our data set with other published data. We determined that these data were sufficiently reliable for assessing BLM field office compliance with BLM’s venting and flaring guidance.

To better understand the rationale behind BLM’s acceptance or rejection of these requests, we selected a simple random sample of 100 of the 1,281 venting or flaring requests for further review. Estimates based on a probability sample are subject to sampling error. Because we followed a probability procedure based on random selections, our sample is only one of a large number of samples that we might have drawn. Since each sample could have provided different estimates, we express our confidence in the precision of our particular sample’s results as a 95 percent confidence interval (e.g., plus or minus 10 percentage points). This is the interval that would contain the actual population value for 95 percent of the samples we could have drawn. These findings can be generalized to all BLM field offices. We requested additional documentation from BLM field offices for 64 of these 100 requests that based on our review of the venting or flaring requests did not appear to result in revenue-bearing flaring. For each of these 100 requests, we reviewed the remarks field and any additional documentation that we requested and received, and determined for each venting or flaring request the NTL-4A provision and rationale, if applicable, that was used to justify royalty-free venting or flaring. We also interviewed BLM field office officials from our six selected field offices about implementation of NTL-4A in their respective offices.

To describe the actions some states have taken to address natural gas emissions on onshore leases, we selected the five states with the largest federal production of oil and gas as reported by operators on the OGOR for fiscal year 2014 (see app. I). These states were Colorado, New Mexico, North Dakota, Utah, and Wyoming. We reviewed venting and flaring regulations and policies for each state. Using a standard set of questions, we also interviewed the air quality and oil conservation offices for each of the selected states. Because this was a nonprobability sample, our findings from these states are not generalizable to other states but provide information on actions some states have taken to reduce natural gas emissions from onshore leases.

We conducted this performance audit from January 2015 to July 2016 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.

Appendix III: Comments from the Department of the Interior

Appendix IV: GAO Contact and Staff Acknowledgments

GAO Contact

Staff Acknowledgments

In addition to the contact named above, Dan Haas (Assistant Director), Carl Barden, Chuck Bausell, Richard Burkard, Keya Chateauneuf, Cindy Gilbert, Paul Kazemersky, Alison O’Neill, Katrina Pekar-Carpenter, Sara Sullivan, Jack Wang, and Arvin Wu made key contributions to this report.