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entitled 'Oil And Gas Management: Interior's Oil and Gas Production 
Verification Efforts Do Not Provide Reasonable Assurance of Accurate 
Measurement of Production Volumes' which was released on April 14, 
2010. 

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Report to Congressional Requesters: 

United States Government Accountability Office: 
GAO: 

March 2010: 

Oil And Gas Management: 

Interior's Oil and Gas Production Verification Efforts Do Not Provide 
Reasonable Assurance of Accurate Measurement of Production Volumes: 

GAO-10-313: 

GAO Highlights: 

Highlights of GAO-10-313, a report to congressional requesters. 

Why GAO Did This Study: 

Oil and natural gas produced from federal leases generated over $6.5 
billion in royalties in 2009. To verify that royalties are paid on the 
correct volumes of oil and gas, the Department of the Interior 
(Interior) verifies the quantity and quality of oil and gas, both 
onshore, through the Bureau of Land Management, and offshore, through 
the Offshore Energy and Minerals Management Service. This report 
assesses (1) the extent to which Interior's production verification 
regulations and policies provide reasonable assurance that oil and gas 
are accurately measured; (2) the extent to which Interior’s offshore 
and onshore production accountability inspection programs consistently 
set and meet program goals and address key factors affecting 
measurement accuracy; and (3) Interior’s management of its production 
verification programs. To address these questions, GAO analyzed 
Interior data on oil and gas inspections and human capital, as well as 
interviewed officials from Interior, states, oil and gas companies, 
and other countries. 

What GAO Found: 

Interior’s measurement regulations and policies do not provide 
reasonable assurance that oil and gas are accurately measured. Interior’
s varied approaches for developing and revising its measurement 
regulations are both ineffective and inefficient—Interior’s onshore 
measurement regulations have not been updated in 20 years and do not 
address current measurement technologies. Onshore and offshore staff 
have infrequently coordinated on measurement issues, although each 
addresses similar issues. Additionally, Interior’s decentralized 
process for granting waivers from current regulations and approval of 
alternative measurement technologies allows officials to make key 
decisions affecting measurement with little oversight, increasing the 
risk of approvals of inaccurate measurement technologies. Further, 
Interior has failed to determine the extent of its jurisdictional 
authority over key elements of oil and gas infrastructure, including 
gas plants and pipelines, limiting its ability to inspect these 
elements to assess the accuracy of their measurement. Finally, Interior’
s onshore and offshore policies for tracking and approving where and 
how oil and gas are measured are inconsistent, with Interior tracking 
offshore measurement points offshore, but not for onshore, creating 
challenges for onshore inspection staff to verify measurement accuracy. 

Interior’s offshore and onshore production accountability inspection 
programs are not consistently setting or meeting program goals for 
inspecting oil and gas leases and do not sufficiently address key 
factors affecting measurement accuracy. Interior’s offshore and 
onshore inspection program goals differ in key areas, with only the 
offshore program establishing goals for witnessing meter calibrations, 
a key control for accurate measurement. Additionally, while the 
onshore inspection program includes an activity to independently 
verify gas volume calculations, the offshore program does not. 
Moreover, Interior has not consistently met its inspection goals; 
offshore inspectors met program goals once between fiscal years 2004 
and 2008, and onshore inspectors met program goals about one-third of 
the time over the past 12 years. Finally, neither program sufficiently 
addresses key areas affecting measurement accuracy, including how gas 
samples are collected. 

Limited oversight, gaps in staff skills, and incomplete tools hinder 
Interior’s ability to manage its production verification programs. In 
particular, we identified several instances where production 
measurement staff work with limited oversight. For example, onshore 
engineers generally make decisions autonomously in the absence of 
central guidance and oversight. Further, despite years of critical 
reviews by GAO and others, Interior recently lowered its own 
estimation of the risks of the oil and gas program from medium to low, 
exempting it from more rigorous internal oversight. In addition, some 
key production verification staff lack critical skills, in part, 
because Interior has not provided training. For example, Interior has 
provided training only once in the past 10 years for its onshore 
engineers, despite significant changes in technology used by industry. 
Interior’s efforts to provide its inspection staff with tools to 
obtain real-time gas production data directly from producers and the 
ability to electronically document production inspection results in 
the field have shown few results. 

What GAO Recommends: 

GAO is recommending Interior improve the consistency and timely 
updating of measurement regulations and policies, clarify 
jurisdictional authority over gas plants and pipelines, and provide 
appropriate and timely training for key measurement staff. In 
commenting on a draft of this report, Interior generally agreed with 
our findings and recommendations. 

View [hyperlink, http://www.gao.gov/products/GAO-10-313] or key 
components. For more information, contact Frank Rusco at (202) 512-
3841 or ruscof@gao.gov. 

[End of section] 

Contents: 

Letter: 

Background: 

Interior's Measurement Regulations and Policies Do Not Provide 
Reasonable Assurance that Oil and Gas Are Accurately Measured: 

Interior's Differing Offshore and Onshore Production Accountability 
Inspection Programs Do Not Consistently Meet Their Goals or 
Sufficiently Address Key Factors Affecting Measurement Accuracy: 

Limited Oversight, Gaps in Staffs' Critical Measurement Skills, and 
Incomplete Tools Hinder Interior's Ability to Manage its Production 
Verification Programs: 

Conclusions: 

Recommendations for Executive Action: 

Agency Comments and Our Evaluation: 

Appendix I: Scope and Methodology: 

Appendix II: Comments from the Department of the Interior: 

Appendix III: Four Examples of the Bureau of Land Management's (BLM) 
Inconsistent Meter Approvals: 

Appendix IV: Analysis of the Department of the Interior's (Interior) 
Hiring, Training, and Retaining of Critical Measurement Staff: 

Appendix V: Production Verification Tools and Practices Used by 
Selected States, Companies, and Other Countries: 

Appendix VI: Production Verification and Accountability Practices of 
Selected States as Reported by State Officials: 

Appendix VII: GAO Contacts and Staff Acknowledgments: 

Related GAO Products: 

Tables: 

Table 1: Summary of Interior's Production Accountability Inspection 
Program Goals and Components: 

Table 2: OEMM Site Security Inspections for Oil and Gas Measurement, 
Fiscal Year 2008: 

Table 3: OEMM Liquid Oil and Gas Meter Calibrations Witnessed, Fiscal 
Year 2008: 

Table 4: Progress Toward Resolving Liquid and Gas Volume Discrepancies 
and Obtaining Missing Production Allocation Reports, as of November 
2009: 

Table 5: Summary of BLM Production Inspections, Fiscal Years 1998-2009: 

Table 6: Percentage Change in BLM Meter Calibration Activities 
Completed, Fiscal Years 2004-2008: 

Table 7: Percentage Change in BLM Tank Gauging Calibration Activities 
Completed, Fiscal Years 2004-2008: 

Table 8: BLM Production Inspection Activity Data, Fiscal Years 2004- 
2008: 

Table 9: Summary of Hiring, Training, and Retention Issues Identified 
for Interior Production Verification Staff: 

Table 10: Total Turnover Rates for Petroleum Engineers, Fiscal Years 
2004-2008: 

Table 11: Overview of Course Petroleum Engineer Technician Attendees 
by Fiscal Years 2003-2008: 

Table 12: Overview of Course Petroleum Engineer Technician Attendees 
by Fiscal Years 2003-2008: 

Table 13: Total Turnover Rates for Petroleum Engineer Technicians, 
Fiscal Years 2004-2008: 

Table 14: Total Turnover Rates for Production Accountability 
Technicians, Fiscal Years 2004-2008: 

Table 15: Total Turnover Rates for OEMM Petroleum Engineers who 
Approve Measurement, Fiscal Years 2004-2008: 

Table 16: Total Turnover Rates for OEMM Inspectors, Fiscal Years 2004- 
2008: 

Table 17: Number of Liquid Verification System (LVS) and Gas 
Verification System (GVS) analysts, Fiscal Years 2004-2009: 

Table 18: Establishment of Uncertainty Standards in Selected Entities' 
Measurement Guidance: 

Table 19: Entities Where Percentage Uncertainty Standards Are 
Incorporated Into Measurement Guidance: 

Table 20: Summary of Production Verification Practices in 10 States as 
Reported by State Officials: 

Figures: 

Figure 1: BLM Field Offices and OEMM Regional and District Offices 
Responsible for Managing Onshore and Offshore Federal Oil and Gas 
Production: 

Figure 2: Oil Tanks in Carlsbad, New Mexico: 

Figure 3: BLM Petroleum Engineer Technician Preparing to Gauge an Oil 
Tank: 

Figure 4: A Lease Automatic Custody Transfer Unit: 

Figure 5: An Orifice Meter with an Electronic Flow Computer: 

Figure 6: OEMM Inspectors Witnessing a Calibration of an Orifice Meter 
Associated With a Chart Recorder at a Land-Based Meter Location: 

Figure 7: Oil Storage Tanks that Had Not Been Inspected for Several 
Years: 

Figure 8: BLM Petroleum Engineer Technician Inspecting an Orifice 
Plate: 

Figure 9: GAO Representation of BLM's Production Verification 
Inspection and Enforcement Organizational Structure: 

Figure 10: GAO Representation of OEMM's Production Verification and 
Inspection Organizational Structure: 

Figure 11: Volume Balancing Diagram Illustrating Gas Volumes Entering 
and Leaving a System: 

Abbreviations: 

AFMSS: Automated Fluid Minerals Support System: 

API: American Petroleum Institute: 

BLM: Bureau of Land Management: 

BTU: British Thermal Units: 

DWRRA: Deep Water Royalty Relief Act: 

EPAP: Enhanced Production Audit Program: 

ERCB: Energy Resources Conservation Board: 

FMFIA: Federal Managers' Financial Integrity Act: 

FOGRMA: Federal Oil and Gas Royalty Management Act: 

FPPS: Federal Personnel and Payroll System: 

IT: Information Technology: 

LACT: Lease Automatic Custody Transfer unit: 

mcf: one thousand cubic feet: 

MMS: Minerals Management Service: 

NPR-A: National Petroleum Reserve-Alaska: 

OMB: Office of Management and Budget: 

OEMM: Offshore Energy and Minerals Management: 

PCC: Production Coordination Committee: 

RDAWP: Remote Data Acquisition for Well Production: 

SCADA: Supervisory Control and Data Acquisition: 

TIMS: Technical Information Management System: 

[End of section] 

United States Government Accountability Office:
Washington, DC 20548: 

March 15, 2010: 

Congressional Requesters: 

Oil and natural gas produced from federal lands and waters are 
critical to our nation's energy supply and reduce our reliance on 
foreign sources of energy. Specifically, in fiscal year 2008, federal 
lands and waters managed by the Department of the Interior (Interior) 
contributed about 26 and 24 percent, respectively, to the total of oil 
and gas produced in the United States. In fiscal year 2009, the 
Department of the Interior's Minerals Management Service (MMS) 
collected over $6.5 billion in royalties from companies that developed 
and produced federal oil and natural gas. These royalties represent 
one of the federal government's largest nontax sources of revenue. 

Companies that develop and produce oil and gas from federal lands and 
waters do so under leases obtained from and administered by agencies 
of Interior--the Bureau of Land Management (BLM) for onshore leases, 
and MMS's Offshore Energy and Minerals Management (OEMM) for offshore 
leases. The oil and gas produced from these leases must be properly 
measured and reported to MMS on a monthly basis. These volumes are 
then used by MMS to verify that companies are accurately paying 
royalties. Measuring oil and gas can be challenging at times, with 
overall measurement accuracy affected by numerous factors, including 
the type of meter used, the specific qualities of the gas or oil being 
measured, the rate of production, and whether oil and gas of differing 
qualities are mixed together from multiple wells prior to measurement. 
Accordingly, both BLM and OEMM have independently established programs 
intended to provide reasonable assurance that the royalty-bearing 
volumes of oil and gas are being measured accurately. These programs 
both have an on-the-ground inspection component that consists of 
activities such as examining the pipelines delivering the oil and gas 
from the well to the meter for possible diversion of oil and gas; 
inspecting meter installations to ensure they meet agency standards; 
and witnessing the calibration of meters, as well as an in-office 
component consisting of comparisons of the monthly volumes included on 
the MMS-required production reports with source measurement documents 
obtained from the company. Given that proper measurement of oil and 
gas is critical to accurate royalty collections, Interior's 
measurement verification practices have been the subject of 
considerable scrutiny through the years, both by GAO (see the Related 
GAO Products section at the end of this report) and the Royalty Policy 
Committee, a group convened in 1995 by the Secretary of the Interior 
and charged with advising Interior on managing federal leases and 
revenues. In September 2008, we reported that neither BLM nor OEMM was 
meeting its statutory or internal goals for inspecting federal leases 
that produce oil and gas and that Interior lacks assurance that the 
royalty-bearing volumes are being accurately measured.[Footnote 1] 
Furthermore, the Subcommittee on Royalty Management submitted a report 
to the Royalty Policy Committee in December 2007 that included more 
than 100 recommendations to strengthen Interior's royalty collections, 
including many directed at improving oil and gas measurement and 
reporting.[Footnote 2] 

This report responds to your request that we examine Interior's 
oversight of oil and gas measurement on federal leases. Accordingly, 
our audit objectives were to assess (1) the extent to which Interior's 
production verification regulations and policies provide reasonable 
assurance that oil and gas are accurately measured; (2) the extent to 
which Interior's offshore and onshore production accountability 
inspection programs consistently set and meet program goals and 
address key factors affecting measurement accuracy; and (3) Interior's 
management of its production verification programs. 

To conduct this work, we reviewed relevant laws, regulations, and 
Interior, BLM, and OEMM guidance. We interviewed officials in BLM 
headquarters, as well as officials from seven BLM field offices (and 
their associated state offices), selected using a nonprobability 
sample that provided a range of oil and gas operations and state 
jurisdictions. Specifically, we visited and interviewed officials in 
three BLM state offices (Colorado, New Mexico, and Wyoming) and seven 
BLM field offices (Glenwood Springs[Footnote 3] and White River in 
Colorado; Vernal in Utah; Buffalo and Pinedale in Wyoming; and 
Carlsbad[Footnote 4] and Farmington in New Mexico) and interviewed by 
telephone officials in two additional state offices (Montana and 
Utah). Additionally, we interviewed officials in four OEMM district 
offices (and their associated regional offices) that provided a range 
of geographic and regional jurisdictions. Specifically, we visited and 
interviewed officials in one OEMM regional office (Gulf of Mexico) and 
one OEMM district office (Lafayette, Louisiana) and interviewed 
officials in one additional OEMM regional office (Pacific) and four 
additional OEMM district offices (Lake Charles, Lake Jackson, New 
Orleans, and California) by telephone. 

To assess the extent to which Interior's production verification 
regulations and policies provide reasonable assurance that oil and gas 
are accurately measured, we analyzed BLM's and OEMM's measurement 
regulations and policies and conducted semistructured interviews with 
engineers from seven BLM field offices, and inspection staff from nine 
BLM field offices and four OEMM district offices. To assess the extent 
to which Interior's onshore and offshore production accountability 
inspection programs consistently set and meet program goals and 
address key factors affecting measurement accuracy, we reviewed BLM's 
and OEMM's production inspection policies, interviewed representatives 
from oil and gas companies and flow measurement research labs about 
key areas of measurement uncertainty, and analyzed BLM and OEMM 
inspection data. To assess Interior's management of its production 
verification programs, we reviewed BLM's and OEMM's internal plans for 
conducting program oversight; reviewed a nonrandom and 
nongeneralizable sample of hard copy BLM and OEMM inspection files; 
analyzed BLM inspection activity data for fiscal years 2004 through 
2008; analyzed human capital data for fiscal years 2004 through 2008 
to calculate turnover rates; assessed BLM's and OEMM's training 
programs for key production verification positions; and interviewed 
BLM and OEMM officials responsible for developing two key IT tools 
intended for production inspection staff and analyzed associated 
project documentation. Appendix I presents a more detailed description 
of our scope and methodology. 

We conducted this performance audit between October 2008 and March 
2010 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. 

Background: 

Created by Congress in 1849, Interior oversees the nation's publicly 
owned natural resources, including parks, wildlife habitat, and crude 
oil and natural gas resources on millions of acres onshore and 
offshore in the waters of the outer continental shelf. With regard to 
oil and gas in particular, Interior leases federal land, issues 
permits for oil and gas drilling, establishes guidelines for measuring 
oil and gas, and conducts production inspections. 

Leasing: 

Onshore, the Mineral Leasing Act of 1920 gave Interior the 
responsibility for oil and gas leasing on both federal lands and 
private lands where the federal government has retained mineral 
rights.[Footnote 5] Interior's BLM is responsible for managing 
approximately 700 million onshore acres, including the acreage leased 
for oil and gas development, through its 12 state offices; 38 district 
offices; and 127 field offices, 32 of which have oil and gas 
activities within their jurisdiction and are located mostly in the 
western United States. BLM is also responsible for managing the 
approximately 23 million acres of land in the National Petroleum 
Reserve-Alaska (NPR-A) in the North Slope of Alaska. The Naval 
Petroleum Reserve Production Act of 1976,[Footnote 6] as amended, 
governs federal oil and gas leasing in the NPR-A. Offshore, the Outer 
Continental Shelf Lands Act,[Footnote 7] as amended, and the Deep 
Water Royalty Relief Act (DWRRA),[Footnote 8] as amended, gave 
Interior the responsibility for leasing and managing approximately 
1.76 billion offshore acres through its three OEMM regional and seven 
district offices. These four statutes give Interior responsibility for 
collecting royalties associated with both onshore and offshore oil and 
gas production and serve as the basis for the current leasing 
framework for oil and gas leasing (see figure 1). 

Figure 1: BLM Field Offices and OEMM Regional and District Offices 
Responsible for Managing Onshore and Offshore Federal Oil and Gas 
Production: 

[Refer to PDF for image: U.S. map] 

The map depicts the location of the following: 

BLM field offices: 
Anchorage, Alaska; 
Bakersfield, California; 
Canon City, Colorado; 
Casper, Wyoming; 
Dickinson, North Dakota; 
Grand Junction, Colorado; 
Great Falls, Montana; 
Jackson, Mississippi; 
Kemmerer, Wyoming; 
Lander, Wyoming; 
Little Snake, Colorado; 
Miles City, Montana; 
Milwaukee, Wisconsin; 
Newcastle, Wyoming; 
Price/Moab, Utah; 
Rawlins, Wyoming; 
Reno, Nevada; 
Rock Springs, Wyoming; 
Salt Lake City, Utah; 
San Juan Public Lands Center, Colorado; 
Tulsa, Oklahoma; 
Worland/Cody, Wyoming. 

BLM field offices we reviewed: 
Buffalo, Wyoming; 
Carlsbad/Hobbs, New Mexico; 
Farmington, New Mexico; 
Glenwood Springs, Colorado; 
Pinedale, Wyoming; 
Roswell, New Mexico; 
Vernal, Utah; 
White River, Colorado. 

OEMM district offices: 
Houma, Louisiana; 
Lafayette, Louisiana; 

OEMM district offices we reviewed: 
Lake Charles, Louisiana; 
Lake Jackson, Texas; 
Los Angeles, California; 
New Orleans, Louisiana. 

OEMM regional offices: 
Alaska Regional Office. 

OEMM regional offices we reviewed: 
Gulf of Mexico Regional Office; 
Pacific Regional Office. 

Sources: BLM and Map Resources (map). 

[End of figure] 

Permitting: 

To drill on federal lands and waters, companies must first obtain a 
federal lease. Both MMS and BLM have auctions through which companies 
may secure the rights to federal leases that allow them to--upon 
meeting certain conditions--drill for oil and gas. Once it obtains a 
lease, a company may conduct further exploration and subsequently 
determine whether it would like to drill a well. Onshore, before a 
company may drill on leased lands, it must submit an Application for 
Permit to Drill to the appropriate BLM field office. BLM officials 
evaluate the company's proposal for drilling to ensure that it 
conforms with the relevant BLM land use plan for the area and 
applicable laws and regulations, including those focused on protecting 
the environment. In evaluating an Application for Permit to Drill, a 
BLM petroleum engineer reviews technical aspects of the proposed well 
design and drilling practices. In most cases, a BLM petroleum engineer 
will not need to specifically approve any oil or gas measurement 
equipment if a company plans to use metering technologies addressed by 
BLM's measurement regulations. However, if requested to do so by a 
company, BLM will also consider whether to approve a variance from 
current regulations governing the use of alternative metering 
technologies. After BLM approves a drilling permit, the company--or 
operator--may drill the well and commence production. Within 60 days 
of drilling, the operator must file a site facility diagram that 
accurately reflects the relative positions of the production 
equipment, piping, and metering systems. 

A similar process is followed for obtaining a permit to drill a well 
offshore. In this case, the operator submits an application for a 
drilling permit to the appropriate OEMM district office, where the 
district engineer first reviews it for completeness. After reviewing 
the technical elements of the application and verifying that they 
conform with all applicable regulations, the district engineer 
approves the permit. Only after a permit is approved can drilling 
begin. Once drilling is completed--and if the operator discovers that 
oil and gas can be economically produced from the well--the operator 
submits an application to the appropriate OEMM regional office to 
begin production that describes, among other things, how oil and gas 
will be measured. If the application is approved, the regional office 
assigns a facility measurement point, which is an identifier for each 
location where oil and gas will be measured. 

Royalty Payments to the Federal Government: 

Interior is also responsible for ensuring that the federal government 
receives payment from the private companies that extract oil and gas 
from federal land. When an operator begins producing oil or gas under 
a federal lease, the royalty interest owners--or payors--pay royalties 
on the oil or gas produced monthly according to the following equation: 

Royalty payment = (sales volume x sales price - deductions) x the 
royalty rate: 

Royalty rates for leases issued in 2007 were 12.5 percent for onshore, 
16.67 percent for offshore, and 12.5 percent or 16.67 percent for NPR- 
A. Importantly, MMS gas valuation regulations allow royalties to be 
paid on the sales value of gas after it has been processed at a gas 
plant. For processed gas, the volume measured at either BLM's or 
OEMM's official measurement point will not coincide with the final 
sales volume for royalty determination, as natural gas liquids may be 
removed prior to the gas plant. Furthermore, as the gas passes through 
the gas plant, various constituents are separated out of the gas 
streams and the end products--including gas types such as propane, 
ethane, and butane--are sold to various markets. Royalties are due on 
the sales value of each of these separate gas constituents. A 
productive lease remains in effect and the lessee can continue to 
produce oil and gas until the lease is no longer capable of producing 
in paying quantities, regardless of the length of the primary term. 

Within Interior, MMS is also responsible for revenue collection. 
[Footnote 9] MMS does this by, among other things, obtaining reports 
from payors on the amounts of oil and gas produced, the prices 
received for production, any deductions claimed, and the royalty rate 
applicable to the production. 

Oil and Gas Measurement: 

Interior has established specific regulations and other mechanisms for 
how oil and gas may be measured. The degree of certainty that both the 
quantity and quality of oil and gas are being measured accurately can 
be affected by multiple factors. Because 100 percent measurement 
accuracy is not possible, measurement specialists commonly refer to 
uncertainty ranges--or ranges of expected values. Both regulators and 
industry acknowledge this uncertainty and, to varying extents, 
incorporate uncertainty ranges into their measurement requirements. 
What both regulators and industry attempt to avoid, however, is bias-- 
or systematic error. Bias refers to when the volumes are consistently 
over-or under-measured. Therefore, the goal for measuring oil and gas 
is to minimize uncertainty and to eliminate bias. How--and the extent 
to which--this is achieved varies between oil and gas, but key 
controls include using the appropriate meter and other processing 
equipment for the situation; witnessing meter calibrations; witnessing 
sales; and verifying that volume calculations were completed 
accurately. Additional controls include following measurement 
standards intended to reduce uncertainty that have been generally 
agreed upon by industry and regulators and published by the American 
Petroleum Institute (API). Since the passage of the National 
Technology Transfer and Advancement Act in 1996, federal agencies have 
been required to adopt private-sector standards, such as API's, 
wherever practical, in lieu of creating their own proprietary, 
nonconsensus standards.[Footnote 10] 

Oil. According to an Interior official, most oil produced from federal 
lands and waters is measured through one of two very different 
methods. First, oil can be measured by periodically physically 
estimating the volume of accumulated oil--a process called tank 
gauging--which is used when oil is pumped directly from the well into 
a large cylindrical tank(s), typically located adjacent to the well. 
This is common onshore in locations where wells are not located 
adjacent to oil pipelines. The tank is used to store the oil until a 
tanker truck pumps the oil out and delivers it to a pipeline or other 
facility. These tanks can be 20 or more feet tall and hold hundreds of 
barrels or more of oil (see figure 2). 

Figure 2: Oil Tanks in Carlsbad, New Mexico: 

[Refer to PDF for image: photograph] 

Source: GAO. 

[End of figure] 

Tank gauging is a manually intensive measurement process whereby the 
gauge, a device similar to a tape measure, is used to determine the 
depth of oil in the tank both before and after the oil has been pumped 
from the tank to the truck. Then, using a conversion table specific to 
that tank, the gauger--or person gauging the tank--converts the 
difference in the before and after depths into an overall volume. At 
the same time, the gauger obtains representative samples of the oil in 
the tank and tests them to determine the extent to which impurities, 
such as water and sediment, are present.[Footnote 11] This entire 
process may be performed by the drivers of the tanker trucks, who 
drive routes through oil fields, picking up oil at many tanks along 
the way and delivering it to a central location where it is shipped, 
via pipeline, to refineries or other locations (see figure 3). This 
entire process is called a tank sale, and a receipt recording the 
amount of oil removed is prepared and later provided to the operator. 
Because tank gauging is a manual process, the accuracy of the 
measurement depends on the extent to which the gauger adheres to 
requirements established by Interior, which reference API standards. 
There are several procedures that must be strictly followed to ensure 
measurement accuracy during a tank sale. For example: 

* If the gauger does not follow standards endorsed by API, which 
include procedures for minimizing uncertainty and eliminating bias, 
errors in measurement can occur. For example, incorrectly measuring 
the depth of the oil in the tank due to the presence of unevenly 
distributed sediment on the tank bottom; a tank deformation, such as a 
dent; or using the wrong table to convert the tank depth to a volume 
would result in inaccurate measurement. 

* If the impurities present in the oil are not measured according to 
API standards, the volume of oil will be inaccurately measured. 

* Since oil tanks are often in remote locations and not supervised, 
there is risk that oil can be stolen. Because of this risk, Interior 
has policies for securing tank valves. 

Figure 3: BLM Petroleum Engineer Technician Preparing to Gauge an Oil 
Tank: 

[Refer to PDF for image: photograph] 

Source: GAO. 

[End of figure] 

The second primary method for measuring oil involves the use of lease 
automatic custody transfer (LACT) units. These are automated systems 
for measuring, sampling, recording, and transferring oil from wells to 
a pipeline or a barge, and are common on the higher production rate 
platforms in the Gulf of Mexico. Historically, these units have been 
equipped with positive displacement meters--which operate similarly to 
a gasoline pump--though other types of meters may be used as well (see 
figure 4). With this method, a critical factor for minimizing 
uncertainty is to ensure the meter is accurate. To ensure meters 
remain accurate through many years of use after manufacture, they must 
be calibrated--or proved--regularly. Meters are proved by comparing 
their measurement with the measurement of another device, such as a 
prover. The prover is itself tested for accuracy and must be clearly 
traceable to national measurement standards maintained by the U.S. 
National Institute of Standards and Technology. If the prover has 
fallen out of calibration, or the individual calibrating the meter is 
unfamiliar with the process, the measurement may be biased. API has 
standards specifying how often meters and provers must be tested. 

Figure 4: A Lease Automatic Custody Transfer Unit: 

[Refer to PDF for image: photograph] 

Source: GAO. 

[End of figure] 

Gas. Because gas produced at a well may flow at various pressures, 
thereby resulting in larger or smaller compressed volumes of 
marketable components, gas is generally measured using meter devices 
that are different from those used for measuring oil. Gas produced 
from federal lands and waters is typically measured using one of a 
variety of differential pressure devices, such as an orifice meter. 
Orifice meters have been in use for almost 100 years and are the most 
common device used to measure federal natural gas production. These 
meters force gas to flow through a circular piece of metal with a hole 
in it, called an orifice plate, to create a pressure difference 
(higher in front of the plate and lower behind it). Differential 
pressure and temperature data are measured by sensors allowing the 
volume of gas to be calculated based on equations developed by the 
American Gas Association. Historically, these data were physically 
recorded on a paper chart located near the meter and had to be 
interpreted manually. Since the early 1990s, industry has begun to use 
electronic flow computers to calculate the gas volumes, which are in 
widespread use today. Electronic flow computers are attached to the 
meter to track key parameters for calculating volumes and a variety of 
other information, such as when the meter was last calibrated and what 
size orifice plate is in the meter (see figure 5). 

Figure 5: An Orifice Meter with an Electronic Flow Computer: 

[Refer to PDF for image: 2 photographs] 

The following are labeled on the photographs: 

Electronic flow computer; 
Orifice plate fitting; 
Orifice plate; 
Meter tube. 

Source: GAO. 

[End of figure] 

A number of factors affect the accuracy of gas measurement. 

* Orifice and meter tube condition. Both the orifice plate and the 
meter tubes located upstream of the meter must be free of nicks or 
pits; not have a significant accumulation of debris, such as wax or 
other contaminants that commonly occur in gas production; and be 
installed correctly. Research shows that imperfections on the surface 
of the orifice plate, dirty meter tubes, or installing the plate 
backward can result in under measurement. 

* Orifice size. The orifice plate must be appropriately sized for the 
volume of flowing gas. If too large a plate is used, the differential 
pressure will be lower, resulting in higher levels of uncertainty. 

* Measurement of all gas. Gas production sites are often complex, with 
many pipes above and below ground. It is important that no pipes that 
can carry gas are allowed to bypass the meter so that all gas leaving 
the well is measured. 

* Presence of water or liquid hydrocarbons in the gas stream. Most 
measurement standards require the gas being measured to be free of 
liquids--meaning that any water or liquid hydrocarbons mixed with the 
gas when it was produced have been removed. This is typically 
accomplished using separators and dehydrators located at the well 
site. According to an Interior official, gas measurement will be 
biased upward when liquids are present in the gas stream. 

* Meter installation. The meter must be installed in a location where 
the gas is flowing freely and uniformly. For this to be the case, 
typically the meter must be placed a specified distance from bends in 
the pipes and other obstructions. In some cases, the flow of gas can 
be conditioned using devices to eliminate flow that could negatively 
affect measurement. API and other industry organizations have 
developed guidance specific to various meter types, for orifice meter 
size and placement, and the use of devices to condition the flow. 

Industry is also developing and using newer and, in some cases, more 
complex gas metering technologies, including Wafer V-Cone, turbine, 
ultrasonic, Coriolis, and multiphase meters; however, these meters are 
less widely used for measuring federal gas than orifice meters. 
[Footnote 12] API has established some standards for the use of some 
of these meters. Each of these meters is also associated with various 
factors that can potentially result in inaccurate measurement. 

In addition to volume, determining the quality of the gas is also 
necessary. Gas typically has many different components--methane, 
ethane, and butane, among others--that may be separated during 
processing at a gas plant and subsequently sold. The composition of 
the gas gives it its overall heating value, which is reported in 
British thermal units (BTU).[Footnote 13] The higher the BTU content, 
the higher the market value; thus, the sale price of the gas. The gas 
may be sampled through one of several different methods, including 
taking spot samples which involves taking a one-time gas sample from a 
point adjacent to the meter, or proportional-to-flow samples, which 
involves collecting a sample of gas over a specified period of time. 
[Footnote 14] Most gas samples have associated water content that can 
be precisely determined through the gas analysis, resulting in the 
actual BTU. However, if the analysis does not specifically assess the 
water content, then one can report the BTU value on a dry basis if it 
is assumed that no water is present, or on a wet basis, if it is 
assumed the gas is saturated. 

Commingling Oil and Gas. Interior has the authority to approve 
measurement agreements that allow oil or gas produced from a federal 
lease to be combined with oil or gas from another federal, state, or 
private lease; these agreements allow the combined volumes and varying 
qualities of oil or gas to be measured at some specified point 
downstream, rather than at each individual well head. Each upstream 
lease is then allocated a specific portion of the combined volume 
according to the commingling agreement. Operators may request approval 
for commingling for several reasons, including the need to reduce 
costs of installing and maintaining meters in marginally producing 
fields and to simplify their measurement operations. Additionally, BLM 
may encourage this practice to reduce the need for additional 
equipment at each well head, which reduces the environmental impacts 
on the land surrounding the well. However, the accuracy of the 
measurement of oil or gas produced may be affected by commingling. 

Production Inspections: 

To ensure compliance with all stipulations in the lease and conditions 
of approval in the drilling permit, as well as applicable laws and 
regulations, both BLM and OEMM have inspection and enforcement 
programs that are designed to verify that the operator complies with 
all measurement requirements at a well site. The authority for 
inspecting wells for this purpose is derived from the Federal Oil and 
Gas Royalty Management Act of 1982 (FOGRMA), as amended.[Footnote 15] 
This act requires the Secretary of the Interior to develop guidelines 
that specify the coverage and frequency of inspections.[Footnote 16] 
Interior has delegated responsibilities for implementing FOGRMA; BLM 
has responsibility for onshore wells, and OEMM has responsibility for 
offshore wells. Each agency has developed regulations, policies, and 
procedures to conduct inspections. Together, BLM and OEMM are 
currently responsible for ongoing oversight of oil and gas operations 
on more than 29,000 producing leases. Among other things, BLM and OEMM 
staff inspect leases to verify that oil and gas production is 
accounted for, as required by FOGRMA and agency regulations and 
policies. Finally, in many instances both onshore and offshore, the 
operators do not own or maintain the custody transfer meter--the meter 
where gas and oil are transferred from one party to another--which 
measures the oil and gas produced. Rather, that meter is owned and 
maintained by a pipeline company that is paid by the operator to 
transport the oil or gas to some point downstream. 

Onshore. Production inspections are BLM's primary mechanism for 
ensuring that operators are complying with various measurement 
regulations and policies. BLM staff conduct production inspections to 
provide reasonable assurance that oil and gas produced from federal 
leases are being measured and handled appropriately. BLM's petroleum 
engineer technicians are responsible for conducting production 
inspections, in addition to other types of inspections, including 
drilling, well plugging, and abandonment inspections. Petroleum 
engineer technicians conduct and track production inspections by 
inspecting cases--a case is either a lease or a unit agreement 
[Footnote 17] which can have between 1 to over 1,000 wells--to verify 
that oil and gas are being measured in accordance with regulations and 
policies. Production inspections typically consist of four key 
activities: (1) reviewing 6 months of production records to look for 
any anomalies, (2) assessing the physical conditions of the production 
area by looking for refuse or any leaking equipment, (3) verifying 
that the company-submitted site security diagram--which should include 
all the piping and equipment at the site--reflects what is actually at 
the site, and (4) examining a sample of both oil and gas measurement 
operations. For example, this examination may involve witnessing a gas 
meter calibration, independently recalculating the gas production 
volumes using key values recorded by the electronic flow computer, or 
gauging an oil tank. BLM production accountability technicians also 
complete in-office detailed reviews of meter statements, calibration 
records, and oil and gas production volumes reported to MMS. 

Offshore. OEMM's efforts to verify measurement consist primarily of 
physical inspections of oil and gas production platforms, and an 
automated comparison of operator-reported production data with volume 
data generated by pipeline companies. OEMM's inspectors are 
responsible for a variety of inspections, including safety and 
environmental, as well as those focusing on oil and gas production. 
OEMM's production inspections include verifying that piping connected 
to the meter is sealed to prevent theft and ensuring there are no 
bypasses around meters that could allow oil or gas to flow unmeasured. 
Additionally, OEMM inspectors witness oil and gas meter calibrations. 
OEMM also automatically compares operator-reported oil and gas 
production volumes with pipeline oil run tickets and gas volume 
statements through its Liquid Verification System and Gas Verification 
System. These programs require that operators submit gas volume 
statements and oil run tickets produced at OEMM's official metering 
points, called facility measurement points, that are used for royalty 
determination purposes. The volumes recorded on these statements, 
along with other technical information, are electronically and 
manually entered by OEMM staff. OEMM's database then compares these 
volumes with the monthly operator-reported production volumes, and 
forwards discrepancies to MMS. MMS staff then follow up with the oil 
or gas companies and work to reconcile the volume differences. 
[Footnote 18] 

Interior's Measurement Regulations and Policies Do Not Provide 
Reasonable Assurance that Oil and Gas Are Accurately Measured: 

Interior's measurement regulations and policies do not provide 
reasonable assurance that oil and gas are accurately measured because 
(1) its varied approaches for developing and revising its offshore and 
onshore regulations are ineffective and inefficient, (2) it has a 
decentralized process for approving new measurement technologies not 
addressed by current regulations, (3) it has not determined the extent 
of its authority over key elements of oil and gas production 
infrastructure, and (4) its policies for tracking where and how oil 
and gas are measured are not consistent and effective. 

Interior's Varied Approaches for Developing and Revising Its Offshore 
and Onshore Measurement Regulations Are Both Ineffective and 
Inefficient: 

Interior's approaches for developing and revising its offshore and 
onshore oil and gas measurement regulations differ, at times hindering 
Interior's ability to accurately measure oil and gas production. Since 
these regulations were first promulgated, they have been ineffectively 
revised and, in some cases, do not reflect current measurement 
technologies or industry standards. Finally, little coordination has 
occurred between OEMM and BLM, resulting not only in inefficient and 
duplicative efforts in reviewing and assessing new measurement 
technologies and practices, but a missed opportunity to take advantage 
of measurement expertise across agencies. 

Interior's Offshore and Onshore Measurement Regulations Differ, 
Permitting Inconsistent Measurement of Oil and Gas: 

Interior's regulations for measuring oil and gas vary depending on 
whether the production is from an offshore or onshore federal lease, 
resulting in inconsistent oil and gas measurement practices and, in 
some instances, reducing Interior's assurances of accurate 
measurement. More specifically, in 1982, the Secretary of the Interior 
transferred authority for offshore and onshore oil and gas measurement 
to MMS and BLM, respectively. Accordingly, each agency developed its 
own set of measurement regulations which have varying requirements for 
how oil and gas should be measured. Some variations between Interior's 
offshore and onshore measurement regulations may be appropriate 
because of the differences between offshore and onshore oil and gas 
production volumes and operating environments. For example, OEMM 
regulations require that offshore meters be calibrated more frequently 
than BLM regulations require for its onshore meters. Given the 
relatively higher volumes of oil and gas typically flowing through 
offshore meters, more frequent calibrations help ensure that even 
small meter errors are corrected before large volumes are measured 
incorrectly, according to measurement specialists. Other variations 
between offshore and onshore measurement regulations are more 
problematic. For example, orifice plates that are free of nicks, pits, 
and grooves are critical for accurate gas measurement both onshore and 
offshore. BLM has regulations requiring operators to inspect the 
orifice plates every six months to ensure they are free of these 
defects.[Footnote 19] In contrast, OEMM regulations reference API 
guidelines that highlight the importance of orifice plate inspections, 
but do not prescribe frequencies for operators to conduct these 
inspections.[Footnote 20] This omission increases the risk of 
inaccurate offshore gas measurement because OEMM does not have 
sufficient assurance that the orifice plate is free of nicks and other 
imperfections. Similarly, Interior approves the use of electronic flow 
computers both onshore and offshore for calculating gas volumes. 
However, while OEMM has a regulation specifying the conditions under 
which electronic flow computers may be used; BLM relies on individual 
states' policies. While these state policies are generally the same, 
they were issued separately over 5 years, resulting in inconsistent 
application of requirements and standards when approving these devices 
during this period. This lack of a consistent departmentwide 
regulation on the use of electronic flow computers increases the risk 
that gas may not be measured accurately. 

Interior Lacks an Integrated Approach for Ensuring Both its Offshore 
and Onshore Measurement Regulations Are Consistently Revised to 
Reflect Current Measurement Technologies: 

Interior lacks an integrated approach for ensuring that both its 
offshore and onshore measurement regulations are consistently updated 
to reflect current industry measurement technologies and practices, 
which would increase Interior's assurance that oil and gas are 
measured accurately. While OEMM has an established approach for 
annually reviewing its measurement regulations and has kept them 
reasonably updated, BLM does not have such an approach, and as a 
result, its measurement regulations have not been revised since 1989. 

OEMM routinely updates its offshore oil and gas measurement 
regulations, most recently in 2009 when it established post-hurricane 
meter verification and calibration requirements. As a result of OEMM's 
annual reviews of its regulations, they generally reflect both current 
technologies and the oil and gas industry's voluntary consensus 
measurement standards. OEMM employs two methods to help maintain its 
regulations. First, it has an office of approximately nine full-time 
regulatory specialists and engineers who, among other things, annually 
review oil and gas industry standards, including API's measurement 
standards, upon which OEMM's measurement regulations are largely 
based. As part of this review, staff assess whether any revisions to 
industry standards referenced in current regulations represent a 
technological or process change significant enough to require an 
update to OEMM's regulations. OEMM's regulatory officials also 
coordinate with OEMM's regional production and development staff--
staff responsible for approving how offshore oil and gas will be 
measured--to consider the likely impact of the revised industry 
standard. If both parties agree that updating the regulations is 
necessary, regulatory staff prepare a memorandum outlining the 
proposed change for MMS management to review. If MMS management 
approves the proposed regulatory change, the proposal continues 
through Interior's rule making process, which may or may not require 
public comment. Second, OEMM has also established a streamlined 
process to incorporate industry standards into its regulations when 
certain criteria are met--as set forth in the Administrative Procedure 
Act.[Footnote 21] In 1996, MMS issued a regulation that allows OEMM to 
incorporate industry standards by reference without public comment 
when MMS determines that the revisions to an industry standards 
document will either improve safety or represent standards for newer 
technology used by industry, and will not impose undue costs on the 
affected parties.[Footnote 22] For example, MMS first adopted API's 
1993 standards for the use of electronic flow computers in 1998; when 
MMS updated its regulations to meet API's 2005 reaffirmed standards in 
2007, it did so without soliciting public comment. According to OEMM 
officials, when notice and comment are not required, the rule making 
process is 6 to 12 months faster than when they are required. Overall, 
in part because of these two methods, OEMM's measurement regulations 
have been updated 10 times since 1988, 9 of which occurred after the 
1996 change to include regulatory standards by reference. 

In contrast, BLM has neither a dedicated staff to review changes to 
standards referenced by its regulations nor a regulation allowing it 
to update its regulations by reference when certain criteria are met. 
In part, because it lacks such an effective approach, BLM last revised 
its oil and gas measurement regulations in 1989. As a result, BLM's 
regulations do not reflect current industry adopted measurement 
technologies and standards designed to improve oil and gas 
measurement. According to a senior BLM official, BLM generally relies 
on a single method for determining whether its measurement regulations 
need to be updated. While BLM does not have any specific personnel 
formally tasked with monitoring changes in either measurement 
technologies or industry measurement standards, BLM field office staff 
and BLM management may use an informal process to reach consensus that 
various sections of BLM's oil and gas regulations need updating. This 
process has resulted in two attempts since 1989 to update BLM's 
regulations, neither of which ended in revised measurement 
regulations. The first attempt began in the early 1990s, when BLM 
published proposed gas measurement regulations in the Federal Register 
in 1994 for public comment. These regulations would have addressed, 
among other things, electronic flow computers. Because these 
regulations were not finalized, BLM did not formally address 
electronic flow computers in some jurisdictions until 10 years later 
and, only then, through BLM policy changes on a state-by-state basis. 
BLM's second attempt occurred in the late 1990s, when it proposed 
revisions to all of its oil and gas regulations and planned to publish 
them in the Code of Federal Regulations; however, after BLM drafted 
200 pages of regulations and published them in the Federal Register in 
1998, they were never finalized. 

BLM is now attempting for the third time to update its measurement 
regulations. In December 2007, Interior's Subcommittee on Royalty 
Management raised concerns about BLM's measurement regulations and 
recommended that BLM re-evaluate them.[Footnote 23] Specifically, the 
subcommittee recommended that BLM establish a working group to 
evaluate its oil and gas measurement and site security regulations to 
ensure that they include adequate guidance for BLM to provide 
reasonable assurance that sufficient royalties are paid on oil and 
gas. For example, the subcommittee suggested that when BLM reviews its 
gas measurement regulations, it evaluate the use of electronic flow 
computers and gas sampling and analysis, among other areas. Although 
the subcommittee set a June 2008 deadline for BLM to complete this 
work, in April 2009, Interior's Inspector General issued a report that 
evaluated BLM's progress and found that BLM had not yet established a 
work group to evaluate its regulations.[Footnote 24] However, instead 
of empanelling a committee to work exclusively on this large task, BLM 
has asked staff to volunteer to do this work along with their other 
responsibilities, with the consent of their supervisors. An official 
told us that obtaining approval from local supervisors for staff to 
participate in these working groups was a challenge and may have 
contributed to the delay. In August 2009, a senior BLM official told 
us that even if the regulatory process was fast-tracked, the revised 
measurement regulations would be issued at the end of 2011, at the 
earliest. According to this official, the work groups had been 
established and would begin drafting proposed regulations soon. 

Interior's Offshore and Onshore Staff Have Infrequently Coordinated on 
Measurement Regulations Resulting in Inefficient, Duplicative Efforts: 

Historically, according to both OEMM and BLM officials, there has been 
limited communication between the agencies regarding measurement 
regulations and other measurement issues. As a result, Interior does 
not have a coordinated approach for addressing measurement issues that 
draws on measurement expertise from both OEMM and BLM. Interior has, 
at various times, had staff from both OEMM and BLM independently 
reviewing and assessing the same industry standards that are 
referenced in both OEMM's and BLM's regulations, the results of which 
are not shared with one another, raising the likelihood that they may 
reach different conclusions. Furthermore, when industry develops new 
metering and measurement technologies and subsequently writes 
standards to address their use, staff from both agencies independently 
assess the new technology's effectiveness. For example, both OEMM and 
BLM have approved V-Cone meters for measuring royalty-bearing gas. 
However, the agencies did not coordinate to assess the technology or 
accuracy of the meter. Rather, staff from both OEMM and BLM each 
devoted time and resources to examining the meter. While BLM obtained 
the company-funded research evaluating the conditions under which the 
V-Cone meters could accurately measure gas, BLM did not share these 
findings with OEMM. As a result, there is a risk that the conditions 
for which meters are approved for onshore measurement and for offshore 
measurement may be different and that these different conditions may 
have varying effects on the accuracy of the oil or gas measurement. 
Interior is currently addressing some of these coordination issues 
through its Production Coordination Committee and its subteams which 
specifically address oil and gas measurement issues, which were 
established in response to a recommendation made by the Royalty Policy 
Subcommittee on Royalty Management. The Production Coordination 
Committee, established in 2008 and composed of BLM, OEMM, and MMS 
staff, is responsible for both implementing 22 of the over 100 
recommendations that require intradepartmental coordination included 
in the subcommittee's December 2007 report, as well as facilitating 
ongoing internal coordination, communication, and information sharing 
between BLM, OEMM, and MMS. According to an MMS official, one outcome 
of this effort to facilitate coordination was a November 2009 joint 
BLM and MMS workshop that provided an opportunity for staff to share 
applicable best practices and discuss common oil and gas production 
concerns, including production verification, commingling and 
allocation, gas sampling, and auditing requirements. While other BLM 
and OEMM officials told us that the agencies are now communicating 
with one another more frequently, both BLM and OEMM continue to 
independently update and revise their measurement regulations. 

Interior's Decentralized Process for Approving New Measurement 
Technologies Not Addressed by Current Regulations Increases the Risk 
of Inaccurate Oil and Gas Measurement: 

Interior lacks a centralized review process for approving technologies 
not addressed by current regulations, increasing the risk of 
inaccurate oil and gas measurement. When a company wants to use a 
technology that is not addressed by regulations, it requests specific 
approval to do so, referred to as a variance, from Interior.[Footnote 
25] Interior has delegated this decision making authority to both OEMM 
and BLM, which has resulted in the agencies developing approaches that 
are inconsistent with one another for assessing these requests. These 
inconsistent approaches may increase the risk of inaccurate 
measurement. 

OEMM's process for granting approvals is centralized and the resulting 
decisions are generally consistent. OEMM chose to retain decision 
making about variances at the regional level, where OEMM possesses 
specialized production measurement expertise, as opposed to delegating 
this responsibility to its district offices, which do not have such 
expertise. Because decisions to approve variances are centrally made 
and reviewed by engineers solely responsible for measurement issues, 
these variances are generally consistent. Most OEMM variance requests 
are reviewed in OEMM's Gulf of Mexico Production and Development 
office, which oversees production of most federal offshore oil and gas 
activity. For example, OEMM recently approved a request from one 
company to use ultrasonic meters to measure royalty-bearing gas. In 
making this decision, OEMM staff evaluated both the performance data 
on the proposed meter's accuracy as well as the economic aspects of 
using the meter, which in this instance, suggested that measurement 
costs could be lowered by reducing the need for additional pipelines 
and space on a platform. Because OEMM's internal control environment 
is structured so that these decisions are centrally made by staff 
whose primary responsibility is measurement, there is less risk of a 
meter being approved that results in inaccurate measurement. 

In contrast, BLM's approval process for variances from its measurement 
regulations are not centralized and approvals are not reviewed by 
specialized measurement staff; in some instances inconsistent 
decisions have been made, raising the risk that oil and gas 
measurements were inaccurate. For example, in some cases, where 
current measurement regulations do not apply and the BLM national or 
state offices have not provided formal guidance, the field office's 
authorized officer--who may or may not have a petroleum engineering 
degree or expertise in measurement issues--decides whether to approve 
a variance from current measurement regulations without further review 
or notifying BLM at the national level. 

We found that in BLM's approvals of four measurement technologies: 
electronic flow computers, Wafer V-Cone meters, truck-mounted Coriolis 
meters,[Footnote 26] and flow conditioners,[Footnote 27] were either 
not consistently made, not centrally reviewed, or both. For example, 
BLM documents indicate that authorized officers at different field 
offices initially approved Wafer V-Cone meters--a type of differential 
pressure meter that was marketed as having the ability to accurately 
measure gas mixed with water--but that the operating conditions for 
which they were approved were inconsistent. After these initial 
approvals, BLM, at the national level, participated in a work group 
that assessed research paid for by the meter manufacturer to determine 
under what conditions the meters could accurately measure gas. The 
results of the research, which was completed in 2005, confirmed that 
BLM had previously approved the use of Wafer V-Cone meters for 
conditions outside of the meters' ability to accurately measure the 
gas. BLM issued a nationwide Instruction Memorandum in November 2006 
specifying the conditions under which BLM's authorized officers could 
approve Wafer V-Cone meters, as well as requiring that all previously 
approved Wafer V-Cone meters be brought into compliance.[Footnote 28] 
In response, one of the field offices we visited sent a letter to all 
companies in its jurisdiction in January 2009--over 2 years after BLM 
issued its Instruction Memorandum--requesting that all companies 
submit a plan to BLM outlining how they would bring any noncompliant 
Wafer V-Cone meters into compliance by May 2009. As a result, 
according to a BLM official, some royalty-bearing gas was inaccurately 
measured over a period of several years and resulted in costs to 
companies that were required to retrofit measurement installations 
that had been approved by BLM. Additionally, because BLM management 
does not centrally review approvals made by authorized officers at the 
field offices, they are unaware of what approvals are made at the 
field office level. For example, in November 2008, the BLM national 
office issued a nationwide Instruction Memorandum requesting 
information on the number of field offices that had approved truck-
mounted Coriolis meters for oil measurement.[Footnote 29] This 
incident suggests that BLM management was both unaware of how 
frequently this technology was being used and what measurement 
performance data were used by field office authorized officers in 
granting any variances (see appendix III for further details). 

Furthermore, we found that within BLM field offices, the authority of 
the authorized officer is inconsistently delegated to one of several 
different BLM positions, which have different professional 
backgrounds. For example, in four of the seven field offices we 
visited, the petroleum engineers have approval authority, in two field 
offices the associate field office manager has approval authority, and 
in one field office a petroleum engineer technician has approval 
authority. In addition, according to BLM staff who make decisions on 
whether to approve variances, they typically request supporting 
technical information from the operator; conduct Internet searches for 
related material to review; and, in some cases, consult with 
authorized officers in other field offices, though there is no 
requirement to do so prior to making a decision on an application for 
a variance. 

Recently, BLM established a Gas Measurement team, as recommended by 
the Subcommittee on Royalty Management in December 2007, to assess new 
gas measurement technologies and consider other measurement issues; 
however, the team consists of staff who have volunteered for the task, 
subject to approval from their supervisors. Furthermore, the team 
members must split their time between their primary job 
responsibilities and their new role in assessing the technologies and 
considering measurement issues--potentially limiting the amount of 
time that they can devote to the gas measurement tasks. According to 
one member of the Gas Measurement team, this has created some 
challenges, as there are a large number of measurement issues that BLM 
needs to address, yet they have limited staff available to devote to 
the task. Finally, the team currently serves in an advisory role by 
assisting the authorized officers who have authority at the field 
office level. At the time of our site visits to seven BLM field 
offices, from March through May 2009, some staff stated that they 
would coordinate with the newly established Gas Measurement team, 
while others did not tell us whether they would coordinate with the 
team. 

Interior Has Not Determined the Extent of Its Authority over Key 
Elements of Oil and Gas Production Infrastructure Necessary for 
Ensuring Accurate Measurement: 

Interior has not determined the extent of its authority over two key 
elements of oil and gas production infrastructure that are necessary 
for ensuring accurate measurement: (1) meters in (or after) gas plants 
which, in some cases, may include the meter where oil and gas are 
measured for royalties; and (2) meters owned by pipeline companies, 
which frequently own, operate, and maintain the meter used at the 
official measurement point on federal leases, as well as the 
production data the meter generates. 

Interior's Failure to Determine the Extent of Its Authority over 
Certain Gas Plant Sales Meters Has Resulted in Limited Oversight of 
Measurement at Certain Gas Plants, Reducing Assurances that Royalty- 
Bearing Volumes Are Being Correctly Measured: 

Interior has exercised limited oversight over certain gas plants 
because it has failed to determine the extent of its authority for 
overseeing gas plants that process gas produced both onshore and 
offshore and what regulatory standards apply to the meters used in gas 
plants to measure royalty-bearing federal production. Gas plant meters 
are critical in determining accurate royalty payments as, often, 
operators measure the unprocessed gas at the well head and transfer 
the gas to a gas plant. Gas plants further refine unprocessed natural 
gas into various constituents upon which royalty payments are due. 
Beside methane, which is the most common constituent, these 
constituents include butane, propane, ethane, and other products that 
can be used in a variety of ways, including residential heating, 
transportation, and plastic manufacturing. Because many of these other 
sales products may have higher market values than natural gas used in 
homes, royalties paid on these components can be responsible for a 
significant share of royalties provided by a lease. As such, any 
inaccurate measurement at gas plants could significantly impact 
royalties that are due to the federal government. Accordingly, 
ensuring that sales products are accurately measured is essential for 
determining the correct royalty amount. Until recently, Interior had 
not physically inspected gas plant meters used to measure royalty-
bearing gas production--except in the Pacific region, where OEMM 
approved official measurement royalty points in the gas plant. 
According to officials and documents obtained from Interior, for over 
20 years, there has been a history of uncertainty as to which agency 
had both the legal authority and regulatory responsibility to inspect 
gas plant meters. For onshore gas plants, BLM and MMS have attempted 
to bring resolution to this uncertainty but, so far, they have been 
unsuccessful. For example: 

* BLM and MMS established a Gas Plant task force in the mid-1980s to 
examine agency roles and responsibilities and industry requirements 
related to the gas stream, from the well head to the gas plant tail 
gate--meters measuring processed natural gas products. The central 
question the task force addressed was, "What are the roles of BLM and 
MMS in ensuring that the United States fully receives royalties due 
from the sale of all products produced from the gas stream?" The task 
force concluded that BLM would ensure that oil and gas were measured 
correctly before they leave the federal lease and that MMS would 
conduct a reasonableness check, through a formula, that gas plant 
products were correctly allocated back to the correct federal lease. 
The task force further concluded that MMS could make special requests 
to BLM to examine meters at a gas plant, if necessary; but that, in 
general, BLM's role regarding gas plants was very limited. One key 
finding of the task force was the existence of a "a void in regulatory 
connection between BLM's 'measurement point' and MMS's 'sales point,'" 
though no specific actions were taken to address this. Finally, the 
task force concluded that, in general, while the government should 
generally be assured that the gas plant products are being accurately 
measured, verifying this is not among BLM's highest priorities. 

* BLM and MMS revisited this issue in 1996 when they established an 
Oil and Gas Royalty Measurement Point/Gas Accountability work group to 
address, in part, potential oversight gaps between BLM's point of 
measurement and MMS's sales point at a gas plant. The work group 
raised the issue that the BLM point of measurement and the MMS sales 
point were two different points; with BLM's point of measurement 
typically located upstream of MMS's sales point. A document from one 
of the work group's meetings stated that "independent verification of 
actual volumes measured at the sales point (e.g., a meter in a gas 
plant), against what has been reported as sold, is not being conducted 
by either agency [BLM or MMS]." The memo further concluded that, 
"Additionally, all measurement for sales purposes which occurs after 
the BLM approved point of measurement does not require approval or 
need to meet any standards for accuracy," meaning that meters used to 
measure products upon which royalties are due are not required to meet 
any regulatory standards for accuracy. 

As of September 2009, according to a BLM official, meters used in gas 
plants to measure onshore royalty-bearing federal production did not 
have to meet federal standards, and BLM did not independently verify 
volumes measured at gas plants. According to a senior BLM official, 
the reason BLM does not inspect meters in gas plants is that, until 
recently, BLM assumed that this was MMS's responsibility. When we 
discussed gas plants with BLM staff at field offices, some petroleum 
engineer technicians did express some concern about the accuracy of 
royalty payments based on how products were both handled and measured 
downstream of BLM's point of measurement. However, most BLM staff were 
not concerned because they considered anything past their point of 
measurement beyond their jurisdiction. 

Similarly, OEMM has not determined the extent of its authority over 
gas plants processing gas produced offshore, which has resulted in 
OEMM's exercising minimal oversight over measurement issues in Gulf of 
Mexico gas plants. While OEMM did issue a regulation in 1998 allowing 
OEMM inspectors to inspect meters in gas plants, according to Interior 
officials, this provision has historically been used in cases where 
the lease operator owned the gas plant--which, because of industry 
consolidation and pipeline infrastructure, is common only in the 
Pacific region.[Footnote 30] However, officials told us that, more 
commonly in the Gulf of Mexico, gas plants are not owned by the 
operator and OEMM has not determined its authority in these cases. 
Accordingly, OEMM does not have regulations specifically addressing 
the types of meters used in gas plants or standards for how often 
these meters are calibrated; and, until recently, has not conducted 
any inspections of gas plants, thereby increasing the uncertainty 
about whether royalty-bearing gas is being properly measured. 

In December 2008, because of concerns raised by the Associate Director 
of OEMM about the lack of oversight at gas plants, OEMM initiated a 
comprehensive review of all gas plants in the Gulf of Mexico region 
processing royalty-bearing offshore federal gas. OEMM's efforts 
identified 37 gas plants, of which 27 were then processing federal 
gas; the remaining 10 gas plants were not operating because of the low 
volumes of gas being produced from the Gulf of Mexico. OEMM's 
inspections, which began in June 2009, included obtaining or creating 
a site-security diagram for the gas plant, identifying all meters 
associated with the plant, reviewing meter calibration reports, and 
identifying potential bypasses around royalty determination meters. 
OEMM plans to use some of these data to create a gas plant database 
that could be used for future audits. These gas plant inspections 
identified several potential areas of concern. First, OEMM identified 
one instance of possible misreporting of gas production. Each month, 
operators are required to submit to MMS their monthly production 
reports which, among other things, indicate which gas plant the 
operator's gas is being transferred to for processing. In this 
instance, an OEMM official found that the total monthly volume 
attributed to a particular gas plant for processing was significantly 
greater than the plant's total gas processing capacity for a month. 
Second, OEMM identified several instances in which meters had not been 
calibrated in accordance with OEMM's measurement regulations. Finally, 
OEMM identified piping configurations in gas plants that would 
potentially allow royalty-bearing gas streams to bypass the royalty 
sales point without being measured. 

Interior's Office of the Solicitor is now reviewing what legal 
authority BLM and OEMM have for inspecting gas plants, and whether or 
not regulations need to be written or revised. According to Interior's 
attorneys, they began the review of OEMM authority in May 2009, and 
BLM requested a review of its authority in September 2009. 

Interior Has Not Determined the Extent of Its Authority over Meters 
and Pipelines, Limiting Production Verification Efforts: 

Interior has not determined the extent of its authority to obtain 
production data from meters designated as the official point of 
measurement or its authority over the meters themselves, when they are 
owned by pipeline companies; thus, limiting Interior's ability to 
access key production data and equipment necessary for verifying 
production.[Footnote 31] While Interior has some statutory authority 
over pipelines and other shippers, such as tanker trucks that 
transport oil and gas produced from federal leases, neither BLM nor 
OEMM has issued regulations to enable Interior to implement this 
authority.[Footnote 32] This creates two challenges for both BLM's and 
OEMM's production verification. First, because Interior currently does 
not obtain production and meter information directly from the pipeline 
companies, it relies on operators to provide the information. 
According to some Interior staff, obtaining the documents necessary 
for audits from the operators instead of the pipeline company is both 
inefficient and time-consuming. Several BLM staff at both the state 
and field office level with whom we spoke said that they have 
encountered situations where the operator did not have the required 
production records necessary for BLM to verify production--such as oil 
tank gauging records, meter calibration records, and gas analysis 
reports. In these instances, BLM worked through the operator to obtain 
the documents from the pipeline company. In one instance, a BLM 
official told us that during a meeting to discuss how BLM would obtain 
the necessary production documentation with both the operator and the 
pipeline company, a pipeline company official initially refused to 
provide BLM the documents, explaining that BLM did not have 
jurisdiction over pipelines. In these instances, BLM enters into a 
protracted interaction with the involved parties, which often results 
in BLM's requesting oil and gas production companies--either 
operators, lessees, or both--to obtain these records from the pipeline 
companies, which lengthens the time it takes for BLM inspection staff 
to verify production. 

Second, Interior's uncertainty about its authority over the physical 
meter itself when it is owned by the pipeline company complicates 
Interior's efforts to schedule appointments to witness meter 
calibrations or other inspections--a critical control for ensuring 
accurate measurement. For example, some offshore inspectors told us 
that they had, in several instances, not been able to witness meter 
calibrations as planned because the pipeline company staff changed 
their schedule for calibrating a specific meter without notice. As a 
result, OEMM inspectors are less able to meet their goals for 
witnessing meter calibrations. Additionally, the unnecessary cost OEMM 
incurs for flying an inspector out to a platform to witness a meter 
calibration is significant--up to $5,000. According to OEMM officials, 
they currently have no direct recourse with the pipeline company when 
they cancel the calibration without providing notice. 

Interior's Policies for Tracking Where and How Oil and Gas Are 
Measured are Not Consistent or Effective, Reducing Assurance that Oil 
and Gas Are Being Measured and Reported Accurately: 

Interior, which has delegated responsibility for oil and gas 
production verification to OEMM and BLM, tracks measurement points 
offshore but not onshore, thereby reducing Interior's assurance that 
oil and gas are being accurately measured and reported. [Footnote 33] 
Additionally, while Interior has developed specific policies and 
instituted controls for reviewing and approving offshore commingling 
requests,[Footnote 34] it has not done the same for onshore 
commingling requests, creating situations where, according to staff, 
verifying production is difficult. 

Interior Does Not Consistently Track All Measurement Points, Resulting 
in Uncertainty about the Location of Meters Measuring Oil and Gas 
Produced from Federal Lands: 

Interior tracks offshore measurement points to assist in verifying oil 
and gas production, but not onshore measurement points, which creates 
uncertainty about the location of the official point of measurement 
and complicates production verification work. Offshore, OEMM tracks 
the number and location of its official points of measurement by 
assigning a facility measurement point number to each point of 
measurement. Each facility measurement point number, in turn, is 
associated with one or more meters that are numerically identified 
with meter ID numbers. In addition, MMS requires that operators report 
their monthly production volumes by their facility measurement point. 
OEMM subsequently matches these volumes with volumes generated by the 
pipeline companies and recorded on oil run tickets or gas volume 
statements. In this way, OEMM is able to identify the measurement 
point for all volumes of offshore oil and gas produced and to verify 
reported production compared with meter production records. 

Onshore, BLM does not track either the number or location of its 
official measurement points for each lease--routinely called the point 
of measurement and described as the last meter before the oil or gas 
leaves the lease. This lack of tracking complicates BLM's production 
verification efforts. Moreover, MMS does not require onshore operators 
to report meter identification information, such as an ID number, on 
the monthly production reports, as it does for offshore operators. 
This makes it difficult to associate the oil or gas production 
reported on the monthly production report with any particular meter on 
the lease. Current measurement regulations require that all onshore 
oil and gas be measured on the lease or within the boundaries of the 
associated unit, unless BLM allows an operator to measure the 
production off-lease--at a location other than the lease where it was 
produced. However, BLM has no regulatory or policy requirement for the 
operator to clearly identify the point of measurement or provide BLM 
with specific identifying information. The absence of a clear 
identifier for the point of measurement has created challenges for BLM 
in verifying production and operators in reporting production. BLM 
petroleum engineer technicians and production accountability 
technicians verify production, in part, through ensuring the point of 
measurement meter is functioning properly and comparing operator-
reported volumes on the monthly production report to production 
information recorded by the meter. Without clear identification of the 
point of measurement in the field and a meter ID number on the monthly 
production report, BLM staff may not be able to correctly identify the 
point of measurement. BLM staff with whom we spoke from nine field 
offices expressed a range of views on the difficulty they have with 
identifying the point of measurement while conducting production 
inspections. Generally, BLM petroleum engineer technicians said that 
when the point of measurement is at the well head, it is easy to 
identify; however, when off-lease measurement has been approved, 
locating the point of measurement can be challenging. Petroleum 
engineer technicians in most of the nine field offices stated that 
having clear documentation of the point of measurement would assist 
them in completing their inspections. 

Additionally, some BLM staff stated that operators may be unaware of 
the location of the official BLM point of measurement, resulting in 
misreporting production. Specifically, field offices have experienced 
cases in which operators measured and reported gas from unapproved off-
lease central delivery points--central locations at which gas from 
multiple leases or units is measured. These meters may be measuring 
commingled federal, private, and state production, which the operators 
allocate back to individual wells located upstream. According to BLM 
staff, it is unclear whether operators are doing this intentionally or 
unintentionally. To address some of this uncertainty, the Wyoming BLM 
state office issued an Instruction Memorandum addressing this issue in 
2003, after it determined that operators were using off-lease central 
delivery point allocation systems, which led to significant 
discrepancies between the operator-allocated volumes and the point of 
measurement volumes.[Footnote 35] The memorandum further stated that 
without a clear understanding of where BLM's point of measurement is, 
it is impossible to correctly account for production volumes, among 
other things. More recently, in March 2009, the Pinedale, Wyoming, 
field office issued a letter to all the operators in its jurisdiction 
stating that "due to the changing composition of production facilities 
and point of measurement for many wells, the Pinedale field office 
finds it necessary to require operators to provide additional 
measurement information for purposes of verifying production and 
measurement," which include posting at each lease site a list of all 
wells that flow through each of the measurement devices located on the 
lease. 

Interior's Inconsistent Policies and Processes for Approving 
Commingling Agreements Compound Its Difficulties in Ensuring that Oil 
and Gas Are Accurately Measured: 

Interior's offshore and onshore policies for approving specific 
agreements for how oil and gas can be measured after being combined 
with oil or gas from another lease--commingling agreements--are 
inconsistent. OEMM has explicit policies and a centralized process for 
approving specific agreements for how oil and gas can be commingled. 
In contrast, BLM lacks a clear policy and uses a decentralized 
process, which makes its staffs' efforts to verify production 
difficult. As a general rule, because offshore commingling involves 
only federal production, offshore commingling agreements may be less 
complex than onshore commingling agreements, which may include 
federal, state, and private production. 

Offshore, OEMM reviews requests for commingling agreements at a single 
office in each of its regional offices, rather than delegating this 
responsibility to petroleum engineers in its district offices. In 
addition, in the Gulf of Mexico, where the majority of commingling 
agreements are reviewed, each request is reviewed by two different 
supervisors to ensure consistency. Additionally, OEMM guidance 
provides criteria for evaluating commingling and allocation agreements 
in the Gulf of Mexico region. For example, to protect federal royalty 
interests, OEMM guidance instructs petroleum engineers not to allow 
production from leases with different royalty rates to be commingled 
without a separate measurement that meets API standards because, 
according to an agency official, production may be misallocated to a 
lease with a different royalty rate, resulting in inaccurate royalty 
payments. Moreover, OEMM requires operators with commingling 
agreements that involve nonfederal production to not only report 
production on their monthly production report, but to separately 
report their allocated production on a monthly production allocation 
schedule report. The purpose of this report is to provide additional 
information about how allocated volumes are divided among different 
leases in a commingling agreement. This report provides OEMM and MMS 
with an additional control for verifying commingled production, since 
the data are corroborated by the operators' monthly production report. 

In contrast, BLM lacks sufficient policies and a consistent process 
for determining whether to allow federal production to be commingled 
with other federal, state, or private production prior to measurement. 
This results in complicated commingling agreements that, according to 
BLM staff, make verifying production difficult. BLM's policy for 
reviewing and approving requests to commingle and allocate production 
includes fewer criteria than OEMM's and creates significant challenges 
for BLM's petroleum engineer technicians and production accountability 
technicians in verifying production. Operators may submit a request to 
commingle production to their local BLM field office, where a 
petroleum engineer typically reviews the request and determines 
whether to approve it. According to petroleum engineers in six of the 
seven field offices we visited, however, there is a lack of sufficient 
BLM national guidance on how to review the requests. As a result, 
petroleum engineers we met with told us they rely, instead, on a 
variety of other guidance, including guidance produced at the field or 
state office level. For example, petroleum engineers from two field 
offices--one in Utah and one in Wyoming--told us that they consider 
criteria included in an Interior Geological Survey Conservation 
Division Manual, issued in 1974. A petroleum engineer from Wyoming 
provided us with Wyoming BLM general guidance dated May 2001 that was 
applicable to Wyoming field offices. Finally, a petroleum engineer 
from a field office in New Mexico told us he considers criteria from 
both local BLM guidance issued in 1995 and the findings of a 1994 
joint BLM and Industry Off-lease Sales, Usage, and Measurement 
Subcommittee report. While there are similarities among these guidance 
documents, it appears as though BLM staff are not routinely 
referencing uniform national guidance and, therefore, are increasing 
the risk that when presented with similar commingling requests, they 
may make different decisions. Seemingly inconsistent decisions have 
caused at least one operator to raise the issue to a BLM State 
Director. In this instance, the operator's request to commingle 
production at one field office had been denied; whereas, according to 
the operator, the same types of commingling requests were routinely 
approved at another field office within the same state. Additionally, 
BLM currently has no guidance on what role either petroleum engineer 
technicians or production accountability technicians--staff who verify 
commingled production--have in reviewing and approving commingling 
requests. While the majority of petroleum engineers we spoke with in 
the seven field offices stated that when approving a commingling 
agreement, they would consider the effect on the petroleum engineer 
technicians' and production accountability technicians' capacity to 
ensure that production is measured and reported accurately; petroleum 
engineers from one field office said they would not. 

Finally, petroleum engineer technicians and production accountability 
technicians--staff responsible for ensuring that production of oil and 
gas is accurately reported--told us that commingling and allocation 
agreements create significant challenges for verifying production, and 
the lack of guidance exacerbates the challenges. In all seven field 
offices we reviewed, production accountability technicians--those most 
responsible for conducting in-depth record reviews to ensure 
production is accurately reported--stated that when production is 
commingled prior to measurement, verifying production is significantly 
more difficult. Furthermore, several production accountability 
technicians acknowledged that, even after completing an in-depth 
records review, they were not confident that all production was being 
properly measured and accounted for, and that the complexities of 
these agreements may make it nearly impossible, in some cases, to 
ensure that production is accurately attributed to the appropriate 
lease. This inability to confidently verify production greatly 
increases the risk that misreported volumes and their associated 
royalty payments will go undetected. 

Interior's Differing Offshore and Onshore Production Accountability 
Inspection Programs Do Not Consistently Meet Their Goals or 
Sufficiently Address Key Factors Affecting Measurement Accuracy: 

Interior's production accountability inspection programs for offshore 
and onshore differ in key areas. Additionally, Interior is not 
consistently completing either its offshore or onshore required 
production inspections. Finally, Interior's offshore and onshore 
production inspection programs do not sufficiently address key factors 
affecting measurement accuracy, thereby increasing the risk that oil 
and gas are not being accurately measured. 

Although Interior's Offshore and Onshore Production Accountability 
Inspection Programs Have Recently Been Revised, They Differ in Key 
Areas: 

Interior's offshore and onshore oil and gas production accountability 
inspection programs have been revised multiple times in the past 
several years, with each program inconsistently emphasizing different 
key measurement inspection goals and activities intended to provide 
reasonable assurance that oil and gas are measured accurately. 

OEMM Recently Revised its Production Accountability Inspection 
Program, Which Emphasizes Annual Goals for Witnessing Meter 
Calibrations and Site Security Inspections: 

OEMM's production accountability inspection program--which emphasizes 
annual goals for its offshore inspectors to witness meter calibrations 
and conduct site security inspections--has been revised twice in the 
past 2 years. From 1994 until 2007, OEMM's inspection program required 
annually witnessing the calibration of 5 percent of gas royalty 
meters, the proving of 10 percent of oil royalty meters, and 
conducting site security inspections on all offshore platforms and 
measurement locations (see figure 6). In 2008, we found that OEMM had 
not defined key terms for its inspection program and recommended that 
the Secretary define "significant quantities of oil or gas" and 
"history of noncompliance."[Footnote 36] In 2008, OEMM established an 
interim annual goal of conducting site security inspections on the 
highest producing 100 oil and gas platforms in the Gulf of Mexico, 
while leaving its goals for witnessing meter calibrations unchanged. 
[Footnote 37] Finally, in 2009, OEMM implemented our recommendation by 
revising its inspection program to incorporate definitions for 
"significant quantities of oil and gas" and "history of 
noncompliance." OEMM's current annual inspection goals are to: 

* witness the proving of 10 percent of oil meters and the calibration 
of 5 percent of gas meters; 

* annually inspect the site security of all high-producing oil and gas 
facilities--defined as those facilities that produce more than 1,000 
barrels of oil per day, or the equivalent heating value for 
gas[Footnote 38] and all other locations on a 3-year cycle; and: 

* continue to reinspect all platforms that have been placed on the 
Monthly Operators Compliance list--a list OEMM district offices use to 
track violations that inspectors find during their work--until the 
violation has been corrected. 

Figure 6: OEMM Inspectors Witnessing a Calibration of an Orifice Meter 
Associated With a Chart Recorder at a Land-Based Meter Location: 

[Refer to PDF for image: photograph] 

Source: GAO. 

[End of figure] 

OEMM inspection staff can perform two measurement-related activities 
while inspecting a measurement location: (1) witnessing meter 
calibrations, and (2) completing a site security inspection. According 
to Interior officials and oil and gas company measurement staff, 
witnessing calibrations is recognized as a strong control for ensuring 
accurate measurement. OEMM staff told us that their presence when 
company staff are calibrating the meters is a key mechanism for 
ensuring proper measurement of federal oil and gas production. 
Conducting site security inspections verifies that offshore platforms 
and other measurement facilities meet OEMM's regulations concerning 
the handling of oil and gas production. Such inspections typically 
include a visual examination of piping to verify that oil and gas do 
not flow around--or bypass--measurement meters. 

However, OEMM does not conduct certain activities that BLM uses to 
verify gas production, such as independently verifying electronic flow 
computer gas calculations. According to an OEMM official, for a short 
period of time in 1988, OEMM independently verified gas meter volume 
calculations while conducting inspections; however, this practice was 
discontinued when measurement inspections were incorporated into 
OEMM's overall inspection program at the district office level. 
Further, unlike BLM, which has through state policies established a 3 
percent overall uncertainty limit for gas measurement that 
incorporates uncertainties introduced by the temperature reading, the 
differential pressure reading, and the overall meter installation, 
among other inputs; OEMM has not. To assess compliance with the 3 
percent uncertainty, BLM worked with a private independent lab with 
expertise in flow measurement to develop an "uncertainty calculator" 
that allows BLM staff to input data and determine the overall 
measurement uncertainty for any given gas measurement configuration. 
When we asked an OEMM official about why OEMM had not established an 
overall uncertainty level, the official told us OEMM had not 
considered including the concept in its production verification 
processes. 

OEMM district offices track violations that inspectors find during 
their work in a monthly operators' compliance list, maintained at the 
district level. Once OEMM staff place a facility with a history of 
violations on their tracking list, OEMM inspects the facility at least 
once every four months until the district manager determines that the 
operator has remedied the violation; at which point, the operator is 
removed from the Monthly Operator Compliance list. Currently, these 
violations are not formally tracked on an OEMM-wide basis, limiting 
OEMM's oversight of operators that have violations. 

Finally, in addition to OEMM's witnessing meter calibrations and site 
security inspections, MMS has additional checks on the accuracy of 
operator-reported production volumes called the Liquid Verification 
System and the Gas Verification System. Each month, OEMM staff use 
these systems to compare the operator-reported oil and gas volumes 
with volumes of oil and gas measured by pipeline company meters, which 
OEMM recalculates based on raw meter data. When volumes do not match, 
MMS staff work to reconcile the volumes through meeting with operators 
and requesting additional documentation. 

BLM's Recently Revised Production Accountability Inspection Program 
Includes Several Key Activities beyond Witnessing Meter Calibrations 
and Inspecting Site Security, Although BLM Lacks Annual Goals for 
Witnessing and Other Measurement Activities: 

BLM's production inspection program--which was recently revised-- 
differs from OEMM's inspection program in several ways. Prior to 
fiscal year 2009, BLM's production inspection program required staff 
to annually inspect all cases--BLM's unit of inspection, which may be 
one or several leases containing from 1 to over 200 wells--rated as 
high priority for production, or those producing at least 12,000 
barrels of oil or 120,000 thousand cubic feet (mcf) per month. In 
addition, staff were required to inspect all high priority compliance 
cases--cases where the operator had six or more FOGRMA-related 
incidents of noncompliance, or two or more major incidents of 
noncompliance, within a 24-month period. The production inspection 
program further required inspections once every 3 years on all other 
cases. For fiscal year 2009, BLM lowered the criteria for "high 
production," thereby increasing the number of high priority production 
inspections--or cases that require annual production inspections. 
BLM's current production accountability inspection program requires 
the following: 

* annual inspections of high priority production cases--producing, on 
average, 6,000 barrels of oil or 80,000 mcf of gas per month--and 
inspections once every 3 years for all remaining cases, and: 

* annual inspections of high priority compliance cases--cases where 
the lease operator has had two major, or a total of six or more FOGRMA-
related incidents of noncompliance with BLM regulations in the 
preceding 24 months. 

BLM's production inspection program also includes a wider range of 
activities than OEMM's inspection program; however, unlike OEMM, BLM 
has not established annual goals for witnessing oil and gas meter 
calibrations. Specifically, BLM inspectors complete one of two types 
of production inspections. The first type requires inspectors to 
complete four separate components for each producing case: (1) an 
assessment of the case's site security, including whether any bypasses 
around the meter are present; (2) a surface protection review, or 
visual examination of the surrounding surface area for trash or other 
items that should not be there; (3) a review of 6 months of operator-
reported production reports; and (4) an oil or gas measurement 
activity. Several of the measurement activities are similar to OEMM's 
activities, including witnessing oil and gas meter calibrations and 
witnessing a tank gauging; however, BLM has no annual goals for 
specific measurement activities. Alternatively, BLM staff may conduct 
an in-depth records review, which are more detailed examinations of 
oil and gas production documents. 

BLM conducts several key measurement activities that OEMM does not, 
including both in-depth record reviews and verifications of gas 
volumes calculated by electronic flow computers. BLM's production 
accountability technicians generally conduct the in-depth record 
reviews by routinely asking operators to provide volume data generated 
by the meters, which they compare with the monthly operator-reported 
production volumes.[Footnote 39] During these record reviews, 
production accountability technicians may also review additional 
documentation on both meter calibrations and gas samples, both of 
which are used to verify production. Additionally, petroleum engineer 
technicians and production accountability technicians may elect to 
verify the calculated gas volume on the electronic flow computer. This 
verification typically requires staff to record such factors as 
temperature, differential pressure, and sometimes, the integral value--
a key factor required to verify gas volumes--and to recalculate the 
volume in accordance with the American Gas Association gas volume 
equation. Recalculating gas volumes can provide assurance that the 
electronic flow computer's software is accurately calculating the 
volumes. As a result of this activity, BLM has found instances where 
the electronic flow computer is incorrectly calculating volumes. As 
one petroleum engineer technician explained, BLM staff identified at 
least one particular model of an electronic flow computer that was 
incorrectly calculating volumes, which caused the operator to hire a 
consultant to further study the problem. In contrast, as previously 
mentioned, OEMM does not check the calculations of the electronic flow 
computers. Also, as mentioned previously, BLM developed an overall 3 
percent uncertainty limit for gas measurement, as well as software to 
calculate the uncertainty. 

When petroleum engineer technicians identify violations of BLM's 
regulations in the field, BLM policy is to issue an "incident of 
noncompliance." These incidents of noncompliance, depending on the 
severity of the violation, may either be minor or major. For example, 
according to current BLM regulations, off-lease measurement of gas 
without prior approval is generally considered a minor violation, 
whereas not recording the temperature of oil to the nearest degree 
during a sale is typically considered a major violation. BLM personnel 
in each field office track these incidents of noncompliance data in 
BLM's database. However, BLM does not use an overall assessment of 
operators' compliance across field offices as criteria for high 
priority compliance cases. Consequently, when a BLM field office 
places a case in its high priority inspection category, it does not 
consider an overall assessment of the operator's compliance on federal 
cases outside of a particular field office's jurisdiction. 
Accordingly, being placed on the high priority list by one field 
office has no impact on how the same operator is viewed by another 
field office. As a result, the same operator may have multiple major 
incidents of noncompliance; by not tracking across field office 
jurisdictions, BLM is also limited in its oversight of an operator's 
noncompliance (see table 1). 

Table 1: Summary of Interior's Production Accountability Inspection 
Program Goals and Components: 

Goals and components: Defined "high producing"; 
BLM: Yes; 
OEMM: Yes. 

Goals and components: Defined "history of noncompliance"; 
BLM: Yes; 
OEMM: Yes. 

Goals and components: Established annual goal for witnessing gas meter 
calibrations; 
BLM: No; 
OEMM: Yes. 

Goals and components: Established annual goal for witnessing oil meter 
calibrations; 
BLM: No; 
OEMM: Yes. 

Goals and components: Established annual goal for witnessing oil tank 
gaugings; 
BLM: No; 
OEMM: Yes. 

Goals and components: Review site security diagrams and inspect for 
meter bypasses; 
BLM: Yes; 
OEMM: Yes. 

Goals and components: Track incidents of noncompliance across 
jurisdiction boundaries; 
BLM: No; 
OEMM: No. 

Goals and components: Verify electronic flow computer volume 
calculation; 
BLM: Optional; 
OEMM: No. 

Goals and components: Use a gas volume uncertainty calculator; 
BLM: Optional; 
OEMM: No. 

Goals and components: Perform volume reconciliation - comparisons 
between operator-reported volume data and pipeline-generated volume 
data; 
BLM: Optional; 
OEMM: Yes. 

Goals and components: Receive meter calibration reports; 
BLM: Optional; 
OEMM: Yes. 

Source: GAO analysis. 

[End of table] 

Interior Has Not Routinely Achieved Its Oil and Gas Production 
Accountability Inspection Annual Goals, Which Reduces Its Assurance 
that Oil and Gas Are Measured Accurately: 

Neither OEMM nor BLM has consistently completed statutory or agency 
required production inspections, a key control for verifying oil and 
gas production. Offshore, OEMM met its oil and gas site security and 
calibration witnessing inspection goals once between fiscal years 2004 
and 2008 for the four district offices we reviewed. Onshore, BLM met 
its minimum goal of inspecting all producing cases once every 3 years, 
approximately one-third of the time over the past 12 years in the six 
field offices with reliable data we reviewed.[Footnote 40] 

OEMM Met its Annual Production Inspection Goals Once in 5 Fiscal Years: 

Offshore, for the four district offices we reviewed, OEMM met its oil 
and gas site security and calibration witnessing inspection goals only 
once--2008--during fiscal years 2004 through 2008. In 2008, OEMM's 
site security goal for the Gulf of Mexico, its major production area, 
was to conduct inspections on the 100 highest-volume measurement 
locations; its goal in the Pacific region was to inspect all meters. 
See tables 2 and 3 for more detailed data for the four district 
offices we reviewed. 

From 2004 through 2007, OEMM's goals were to conduct site security 
inspections on 100 percent of all measurement locations. During those 
years, the agency performed about half of the site security 
inspections required to meet the annual goals. OEMM staff told us 
that, during these years, there was a shortage of inspectors and 
inspections were delayed because of the ongoing cleanup related to 
Hurricanes Katrina and Rita in 2005. We are unable to present data for 
these years because, according to OEMM officials, district offices 
often did not correctly record site security inspections on their 
inspection forms. This problem was identified in 2007; since then, 
OEMM has instituted a new policy to ensure that these inspections are 
being recorded correctly. 

Table 2: OEMM Site Security Inspections for Oil and Gas Measurement, 
Fiscal Year 2008: 

District office: Lake Charles; 
Inspection activity: Meters requiring inspection; 
Oil: Meters in the top 100 highest volume measurement locations: [A]; 
Oil: All other active meters: 124; 
Gas: Meters in the top 100 highest volume measurement locations: 16; 
Gas: All other active meters: 520. 

District office: Lake Charles; 
Inspection activity: Meters inspected; 
Oil: Meters in the top 100 highest volume measurement locations: [A]; 
Oil: All other active meters: 118; 
Gas: Meters in the top 100 highest volume measurement locations: 16; 
Gas: All other active meters: 484. 

District office: Lake Charles; 
Inspection activity: Percentage inspected; 
Oil: Meters in the top 100 highest volume measurement locations: [A]; 
Oil: All other active meters: 95; 
Gas: Meters in the top 100 highest volume measurement locations: 100; 
Gas: All other active meters: 93. 

District office: Lake Jackson; 
Inspection activity: Meters requiring inspection; 
Oil: Meters in the top 100 highest volume measurement locations: 15; 
Oil: All other active meters: 121; 
Gas: Meters in the top 100 highest volume measurement locations: 25; 
Gas: All other active meters: 410. 

District office: Lake Jackson; 
Inspection activity: Meters inspected; 
Oil: Meters in the top 100 highest volume measurement locations: 15; 
Oil: All other active meters: 116; 
Gas: Meters in the top 100 highest volume measurement locations: 25; 
Gas: All other active meters: 347. 

District office: Lake Jackson; 
Inspection activity: Percentage inspected; 
Oil: Meters in the top 100 highest volume measurement locations: 100; 
Oil: All other active meters:96; 
Gas: Meters in the top 100 highest volume measurement locations: 100; 
Gas: All other active meters: 85. 

District office: New Orleans; 
Inspection activity: Meters requiring inspection; 
Oil: Meters in the top 100 highest volume measurement locations: 61; 
Oil: All other active meters: 170; 
Gas: Meters in the top 100 highest volume measurement locations: 48; 
Gas: All other active meters: 342. 

District office: New Orleans; 
Inspection activity: Meters inspected; 
Oil: Meters in the top 100 highest volume measurement locations: 61; 
Oil: All other active meters: 164; 
Gas: Meters in the top 100 highest volume measurement locations: 48; 
Gas: All other active meters: 313. 

District office: New Orleans; 
Inspection activity: Percentage inspected; 
Oil: Meters in the top 100 highest volume measurement locations: 100; 
Oil: All other active meters: 96; 
Gas: Meters in the top 100 highest volume measurement locations: 100; 
Gas: All other active meters: 92. 

District office: California[B]; 
Inspection activity: Meters requiring inspection; 
Oil: Meters in the top 100 highest volume measurement locations: 19; 
Oil: All other active meters: [B]; 
Gas: Meters in the top 100 highest volume measurement locations: 15; 
Gas: All other active meters: [B]. 

District office: California[B]; 
Inspection activity: Meters inspected; 
Oil: Meters in the top 100 highest volume measurement locations: 19; 
Oil: All other active meters: [B]; 
Gas: Meters in the top 100 highest volume measurement locations: 15; 
Gas: All other active meters: [B]. 

District office: California[B]; 
Inspection activity: Percentage inspected; 
Oil: Meters in the top 100 highest volume measurement locations: 100; 
Oil: All other active meters: [B]; 
Gas: Meters in the top 100 highest volume measurement locations: 100; 
Gas: All other active meters: Total: [B]. 

District office: Total; 
Inspection activity: Meters requiring inspection; 
Oil: Meters in the top 100 highest volume measurement locations: 95; 
Oil: All other active meters: 415; 
Gas: Meters in the top 100 highest volume measurement locations: 104; 
Gas: All other active meters: 1,272. 

District office: Total; 
Inspection activity: Meters inspected; 
Oil: Meters in the top 100 highest volume measurement locations: 95; 
Oil: All other active meters: 398; 
Gas: Meters in the top 100 highest volume measurement locations: 104; 
Gas: All other active meters: 1,144. 

District office: Total; 
Inspection activity: Percentage; 
Oil: Meters in the top 100 highest volume measurement locations: 100; 
Oil: All other active meters: 96; 
Gas: Meters in the top 100 highest volume measurement locations: 100; 
Gas: All other active meters: 90. 

Source: GAO analysis of OEMM data. 

[A] The Lake Charles district office did not oversee any of the 100 
top-producing measurement locations in the Gulf of Mexico in fiscal 
year 2008. 

[B] Goals in the California district differed in 2008 because of the 
limited number of meters in the region; specifically, inspectors 
conduct site security inspections on 100 percent of royalty meters 
annually. 

[End of table] 

Additionally, in 2008, OEMM met or exceeded its goals for witnessing 
10 percent of oil meter provings and 5 percent of gas meter 
calibrations. We are not reporting data for witnessing calibrations 
from 2004 through 2007 because OEMM expressed concern about the 
reliability of data for those years.[Footnote 41] 

Table 3: OEMM Liquid Oil and Gas Meter Calibrations Witnessed, Fiscal 
Year 2008: 

District office: Lake Charles; 
Oil: Oil meters: 124; 
Oil: Meter provings witnessed: 37; 
Oil: Percentage inspected: 30; 
Gas: Gas meters: 536; 
Gas: Meter calibrations witnessed: 30; 
Gas: Percentage inspected: 6. 

District office: Lake Jackson; 
Oil: Oil meters: 136; 
Oil: Meter provings witnessed: 14; 
Oil: Percentage inspected: 10; 
Gas: Gas meters: 435; 
Gas: Meter calibrations witnessed: 23; 
Gas: Percentage inspected: 5. 

District office: New Orleans; 
Oil: Oil meters: 231; 
Oil: Meter provings witnessed: 54; 
Oil: Percentage inspected: 23; 
Gas: Gas meters: 390; 
Gas: Meter calibrations witnessed: 39; 
Gas: Percentage inspected: 10. 

District office: California[A]; 
Oil: Oil meters: 19; 
Oil: Meter provings witnessed: 19; 
Oil: Percentage inspected: 100; 
Gas: Gas meters: 15; 
Gas: Meter calibrations witnessed: 15; 
Gas: Percentage inspected: 100. 

District office: Total; 
Oil: Oil meters: 510; 
Oil: Meter provings witnessed: 124; 
Oil: Percentage inspected: 24; 
Gas: Gas meters: 1376; 
Gas: Meter calibrations witnessed: 107; 
Gas: Percentage inspected: 8. 

Source: GAO analysis of OEMM data. 

[A] Goals in the California district differed in 2008 because of the 
limited number of meters in the region; specifically, inspectors 
witness calibrations on 100 percent of royalty meters annually. 

[End of table] 

For MMS' Liquid Verification System and Gas Verification System 
reconciliation activities, MMS established a goal of resolving 100 
percent of the discrepancies it identified between the operator- 
reported monthly oil and gas reports and the volumes included on 
pipeline meter source documents by mid-2010. MMS staff follow up on 
missing documents that operators have not provided, such as the 
monthly production allocation schedule report, which are used to 
verify volumes reported by operators that are part of a commingling 
agreement that include production from nonfederal sources. As of 
November 2009, MMS had added additional staff and made progress toward 
this goal, but numerous discrepancies remain (see table 4). 

Table 4: Progress Toward Resolving Liquid and Gas Volume Discrepancies 
and Obtaining Missing Production Allocation Reports, as of November 
2009: 

Activity: Liquid verification system discrepancies; 
Baseline (as of December 2008): 2,427; 
Discrepancies remaining: 733; 
Percentage reduction: 70. 

Activity: Gas verification system discrepancies; 
Baseline (as of December 2008): 5,134; 
Discrepancies remaining: 3,561; 
Percentage reduction: 31. 

Activity: Missing production allocation schedule reports; 
Baseline (as of December 2008): 419; 
Discrepancies remaining: 402; 
Percentage reduction: 4. 

Source: GAO analysis of MMS data. 

[End of table] 

BLM Has Not Routinely Met its Production Inspection Goals, Decreasing 
Assurances that Oil and Gas are Being Accurately Measured: 

For onshore areas, BLM has been unable to consistently meet its 
statutory or agency goal for completing production inspections, which 
is a key control for ensuring that all production is properly 
measured. As we reported in September 2008, BLM's production 
inspection data were not entirely reliable, in part due to some 
ongoing issues related to the Cobell Indian Trust lawsuit[Footnote 42] 
that resulted in the shutdown of BLM's information technology (IT) 
systems. As a result, BLM's ability to accurately identify high 
priority producing cases was limited, which impacted our ability to 
report BLM's production inspection data at the time. Consequently, we 
limited our current analysis of BLM data for the seven field offices 
we reviewed to determining whether or not cases--both high-and low-
priority--had been inspected at least once every 3 years, in 
accordance with BLM's inspection frequency criteria for low-priority 
cases. While BLM's production inspection program tracks inspections on 
a case level, it is worth noting that a single case may include 
anywhere from one to several hundred wells. When a case contains 
multiple wells, BLM requires that each production inspection include 
inspections of one-fourth of the wells in the case. Our analysis of 
BLM data suggests that numerous producing cases have not been 
inspected for many years, raising significant uncertainty about 
whether the oil and gas are being accurately measured (see figure 7). 

Figure 7: Oil Storage Tanks that Had Not Been Inspected for Several 
Years: 

[Refer to PDF for image: photograph] 

Source: GAO. 

[End of figure] 

Approximately 2 percent, or 198, of active cases between fiscal years 
1998 and 2009 requiring an inspection in the six BLM field offices we 
reviewed had not been inspected.[Footnote 43] The percentage of 
uninspected cases varied by field office, with a low of zero cases in 
the Glenwood Springs, Colorado, field office to a high of about 101 
cases, in the Carlsbad, New Mexico, field office. Additionally, we 
found that about 67 percent of cases had not met BLM's minimum 3-year 
inspection requirement. Finally, BLM met or exceeded its minimum 3-
year inspection goals for approximately 31 percent of active cases in 
the field offices we visited, though the percentage varied 
significantly by field office. For example, the Glenwood Springs, 
Colorado, field office had met the minimum goal for about 58 percent 
of its cases, whereas both the Carlsbad, New Mexico, and Vernal, Utah, 
field offices met the minimum goal for about 27 percent of their cases 
as table 5 illustrates. 

Table 5: Summary of BLM Production Inspections, Fiscal Years 1998-2009: 

Field office: Cases requiring an inspection with no inspection; 
Buffalo, Wyoming: 38; 
Carlsbad, New Mexico: 101; 
Farmington, New Mexico: 38; 
Glenwood Springs, Colorado: 0; 
Pinedale, Wyoming: 2; 
Vernal, Utah: 19; 
White River, Colorado[A]: [A]; 
Total: 198. 

Field office: Percentage of cases requiring an inspection with no 
inspection; 
Buffalo, Wyoming: 2; 
Carlsbad, New Mexico: 5; 
Farmington, New Mexico: 1; 
Glenwood Springs, Colorado: 0; 
Pinedale, Wyoming: 1; 
Vernal, Utah: 2; 
White River, Colorado[A]: [A]; 
Total: 2. 

Field office: Cases not meeting BLM's 3-year minimum inspection goal; 
Buffalo, Wyoming: 1,233; 
Carlsbad, New Mexico: 1,261; 
Farmington, New Mexico: 2,569; 
Glenwood Springs, Colorado: 79; 
Pinedale, Wyoming: 152; 
Vernal, Utah: 601; 
White River, Colorado[A]: [A]; 
Total: 5,895. 

Field office: Percentage of cases not meeting BLM's 3-year minimum 
inspection goal; 
Buffalo, Wyoming: 54; 
Carlsbad, New Mexico: 68; 
Farmington, New Mexico: 77; 
Glenwood Springs, Colorado: 42; 
Pinedale, Wyoming: 56; 
Vernal, Utah: 71; 
White River, Colorado[A]: [A]; 
Total: 67. 

Field office: Cases meeting or exceeding BLM's 3-year minimum 
inspection goal; 
Buffalo, Wyoming: 1,019; 
Carlsbad, New Mexico: 503; 
Farmington, New Mexico: 743; 
Glenwood Springs, Colorado: 110; 
Pinedale, Wyoming: 117; 
Vernal, Utah: 228; 
White River, Colorado[A]: [A]; 
Total: 2,720. 

Field office: Percentage of cases meeting or exceeding BLM's 3-year 
minimum inspection goal; 
Buffalo, Wyoming: 44; 
Carlsbad, New Mexico: 27; 
Farmington, New Mexico: 22; 
Glenwood Springs, Colorado: 58; 
Pinedale, Wyoming: 43; 
Vernal, Utah: 27; 
White River, Colorado[A]: [A]; 
Total: 31. 

Field office: Total; 
Buffalo, Wyoming: 2,290; 
Carlsbad, New Mexico: 1,865; 
Farmington, New Mexico: 3,350; 
Glenwood Springs, Colorado: 189; 
Pinedale, Wyoming: 271; 
Vernal, Utah: 848; 
White River, Colorado[A]: [A]; 
Total: 8,813. 

Source: GAO analysis of BLM data. 

[A] The Interior Office of the Inspector General is currently 
evaluating the reliability of inspection data at the White River, 
Colorado, field office. 

[End of table] 

BLM petroleum engineer technicians and production accountability 
technicians provided multiple explanations for not completing their 
required inspections. First, onshore leases have recently experienced 
high levels of drilling; and under BLM's formal inspection strategy, 
conducting drilling inspections take priority over conducting 
production inspections. In one field office, a BLM official told us 
that, historically, the field office's de facto policy was to not 
complete production inspections. Second, when BLM revised the volume 
criteria downward for high priority cases, the number of cases that 
required annual inspections increased, which further reduced 
inspection staffs' ability to inspect low priority cases. Third, BLM 
officials in the majority of field offices we visited told us they had 
challenges with hiring and retaining staff at sufficient numbers to 
complete their required inspections. In particular, BLM officials told 
us that the low pay, when compared with industry, and the high housing 
costs in energy boom towns were major factors affecting hiring and 
staff turnover. Finally, the lack of a stable workforce resulted in 
multiple attempts to hire new staff. When BLM was successful in hiring 
staff, more senior and experienced staff told us that they had to 
spend additional time providing on-the-job training, which reduced the 
pace of the senior staff inspections. So, despite seeing an increase 
in staff at a field office, it is possible that staff will complete 
fewer inspections because of the time spent training new staff. 

Furthermore, while BLM has not established goals for witnessing 
calibrations like OEMM, BLM staff may still conduct these activities. 
Our analysis of BLM data shows that BLM staff conducted gas meter 
calibrations and oil tank gaugings measurement activities with 
decreasing frequency between fiscal years 2004 through 2008 for seven 
of the eight BLM field offices we reviewed which had reliable data 
(see table 6). Specifically, the frequency with which BLM staff 
completed meter calibration activities as part of a production 
inspection decreased by 62 percent for the eight field offices we 
reviewed between fiscal years 2004 and 2008. 

Table 6: Percentage Change in BLM Meter Calibration Activities 
Completed, Fiscal Years 2004-2008: 

Field office: Buffalo, Wyoming; 
Percentage change: -9. 

Field office: Carlsbad, New Mexico; 
Percentage change: -91. 

Field office: Farmington, New Mexico; 
Percentage change: -57[A]. 

Field office: Glenwood Springs, Colorado; 
Percentage change: -71. 

Field office: Hobbs, New Mexico; 
Percentage change: -93. 

Field office: White River, Colorado; 
Percentage change: [B]. 

Field office: Pinedale, Wyoming; 
Percentage change: -57. 

Field office: Roswell, New Mexico; 
Percentage change: 0. 

Field office: Vernal, Utah; 
Percentage change: -69[A]. 

Field office: Total; 
Percentage change: -62. 

Source: GAO analysis of BLM data. 

[A] According to BLM officials, the reliability of data provided for 
these offices may have been affected for several years because of 
issues related to the impact the Cobell lawsuit had on BLM's IT 
systems. Specifically, some data at the inspection activity level may 
not have been entered into the system between 2004 and 2008 because of 
system shutdowns. Therefore, numbers presented here, while 
representative of what is in the system, may be undercounts. 

[B] The Interior Office of the Inspector General is currently 
evaluating the reliability of inspection data at the White River, 
Colo., field office. 

[End of table] 

Petroleum engineer technicians from five of the nine field offices we 
spoke with did not believe that they were witnessing a sufficient 
number of gas meter calibrations. When asked why more calibrations 
were not witnessed, staff typically said there was either insufficient 
staff or time. For petroleum engineer technicians in the four BLM 
field offices who felt a sufficient number of calibrations were 
witnessed, staff stated that they had infrequently identified meter 
calibration problems and, therefore, believed it was an area of lower 
concern. 

Analysis of tank gauging inspection data also shows a general decline 
in the number of tank gaugings entered by BLM petroleum engineer 
technicians in BLM's database. From fiscal years 2004 through 2008, 
tank gauging activity codes were entered with decreasing frequency for 
seven of the eight BLM field offices we reviewed for which we had 
reliable data (see table 7). Overall, the frequency with which BLM 
staff completed meter calibration activities as part of a production 
inspection decreased by 33 percent for the eight field offices we 
reviewed between fiscal years 2004 and 2008. 

Table 7: Percentage Change in BLM Tank Gauging Calibration Activities 
Completed, Fiscal Years 2004-2008: 

Field office: Buffalo, Wyoming; 
Percentage change: -44. 

Field office: Carlsbad, New Mexico; 
Percentage change: -55. 

Field office: Farmington, New Mexico; 
Percentage change: 240[A]. 

Field office: Glenwood Springs, Colorado; 
Percentage change: -57. 

Field office: Hobbs, New Mexico; 
Percentage change: -67. 

Field office: White River, Colorado; 
Percentage change: [B]. 

Field office: Pinedale, Wyoming; 
Percentage change: -74. 

Field office: Roswell, New Mexico; 
Percentage change: -50. 

Field office: Vernal, Utah; 
Percentage change: -50[A]. 

Field office: Total; 
Percentage change: -33. 

Source: GAO analysis of BLM data. 

[A] According to BLM officials, the reliability of data provided for 
these offices may have been affected for several years because of 
issues related to the impact the Cobell lawsuit had on BLM's IT 
systems. Specifically, some data at the inspection activity level may 
not have been entered into the system between 2004 and 2008 because of 
system shutdowns. Therefore, numbers presented here, while 
representative of what is in the system, may be undercounts. 

[B] The Interior Office of the Inspector General is currently 
evaluating the reliability of inspection data at the White River, 
Colorado, field office. 

[End of table] 

According to BLM petroleum engineer technicians from the nine field 
offices we spoke with, representatives from five of the offices told 
us that they were not completing a sufficient number of tank gaugings 
and provided several reasons why more were not completed. Staff from 
two of the field offices stated that a limiting factor in completing 
additional tank gaugings was a lack of tank gauging equipment, whereas 
staff from another field office explained that they had insufficient 
staff and competing priorities. Staff from one field office who 
concluded that they were completing a sufficient number of tank 
gauging activities explained that they were consistently completing 
them on all cases with tanks, while staff from one other field office 
said that the office had never identified under-reported production 
from completing the tank gauging activity. 

Interior's Production Accountability Inspection Programs Do Not 
Sufficiently Address Key Factors Affecting Gas Measurement Accuracy: 

Interior's production accountability inspection programs do not 
sufficiently address six key factors that may affect measurement 
accuracy: (1) witnessing gas sample collections, (2) verifying BTU 
values are correctly reported, (3) witnessing orifice plate 
inspections, (4) assessing impacts of liquids in gas streams, (5) 
addressing low differential pressure, and (6) inspecting meter tubes. 

* Witnessing gas sample collections. Interior has not established 
goals for witnessing gas samples collected by industry. Because the 
heating value of gas--measured in BTU--is directly related to the 
royalties paid on the gas, any contamination or mishandling of the 
sample has the potential to lead to an incorrect BTU analysis. 
According to BLM calculations, a 10 percent error in reported heating 
value will result in a 10 percent error in royalties due. With onshore 
royalties valued at $2 billion per year, a 1 percent error in reported 
heating value would lead to a $20 million error in royalties paid. 
Current regulations require industry to take gas samples annually for 
onshore, and semiannually for offshore. However, one member of BLM's 
Gas Measurement team expressed concerns about how companies were 
collecting these gas samples in the field, and how those samples were 
subsequently handled and transported. Currently, neither BLM nor OEMM 
have regulations in place stating how or where a sample is to be 
taken, how a sample is to be analyzed, or how heating value should be 
reported. Additionally, neither BLM nor OEMM have established goals 
for witnessing gas sample collections, or tracking the number of 
samples the agencies may have witnessed during the course of an 
inspection. Furthermore, procedures for collecting gas samples were 
only recently incorporated into BLM's training courses, meaning that 
some BLM staff may not have the knowledge required to identify 
incorrect gas sampling techniques. 

* Verifying BTU values are correctly reported. Interior only recently 
clarified how companies should report onshore gas BTU values, but does 
not sufficiently verify that operator-reported BTU values are correct. 
In December 2007, the Royalty Policy Committee's Subcommittee on 
Royalty Management recommended that Interior establish consistent 
guidelines for how companies report BTU values. Until 2009, BLM did 
not have a formal policy for how operators were to report BTU values. 
Instead, BLM informally carried forward a 1980 policy from the U.S. 
Geological Survey--which oversaw oil and gas activities and royalty 
collections before BLM and MMS assumed responsibility for overseeing 
oil and gas production. This policy allowed operators to report the 
BTU value with an assumed water content, as gas may contain water 
vapor. According to BLM documents, this assumption has resulted in an 
automatic reduction as high as 1.74 percent in the BTU value, which 
corresponds to approximately a 1.74 percent decrease in royalty 
payments. On July 30, 2009, BLM issued an instruction memorandum to 
its field office staff defining its policy for reporting BTU values. 
[Footnote 44] The policy requires that all BTU values in the monthly 
production report be reported on a dry basis--without an assumed water 
content--unless the gas sample is analyzed for water content. In that 
case, the actual BTU value should be reported. BLM can verify this 
value when conducting a limited number of annual record reviews by 
comparing BTU values from gas analysis reports with the BTU value on 
the operator-reported production report. BLM estimates that this 
policy change may increase royalties up to $35 million per year. 
However, BLM had not formally communicated this policy change to 
companies producing onshore gas, as of September 2009. As a result, 
companies may continue to erroneously submit incorrect BTU values, 
thereby placing royalty collections at risk. Additionally, the same 
December 2007 Subcommittee on Royalty Management report included a 
recommendation that Interior develop a means to systematically compare 
reported BTU values on the operator-reported monthly production report 
with BTU values from lab analyses. According to MMS officials, in 
early 2010, they are planning to incorporate BTU comparisons into 
their Gas Verification System. However, a BLM official told us that 
comparisons will continue to be made on a limited basis during in-
depth record reviews completed by production accountability 
technicians and that there is no plan to increase these reviews. 

* Witnessing orifice plate inspections. Neither BLM nor OEMM has 
established specific goals for witnessing orifice plate inspections, a 
critical factor for ensuring accurate gas measurement (see figure 8). 
While BLM has a regulatory requirement for the operator to inspect the 
orifice plate semiannually, it has no goal for BLM inspectors to 
witness this activity. According to BLM petroleum engineer technicians 
in multiple field offices, orifice plates are generally inspected 
during a meter calibration; however, BLM is unable to readily provide 
summary data from its database on the number of orifice plates 
inspected, the condition of the plates, or whether the plates were 
replaced. OEMM lacks a regulatory requirement for operators to inspect 
the condition of orifice plates with a specified frequency, and also 
lacks a goal for inspectors to physically witness the inspection of 
the plate, although OEMM officials and staff told us that inspectors 
routinely examine the orifice plate during the gas meter calibrations 
that they witness, and that conducting orifice plate inspections was 
included in a 2009 OEMM meter inspection training course. Similarly, 
OEMM does not track data in its database on the number of orifice 
plates inspected, the condition of orifice plates, or whether a plate 
was replaced. 

Figure 8: BLM Petroleum Engineer Technician Inspecting an Orifice 
Plate: 

[Refer to PDF for image: photograph] 

Source: GAO. 

[End of figure] 

* Assessing impacts of liquids in gas streams. Neither BLM nor OEMM 
has a policy or an inspection activity for assessing the effects of 
liquids in gas on gas measurement. According to one BLM official, the 
impact of liquids in gas on measurement accuracy has largely been 
ignored by federal regulators, although the effect could be 
significant. Petroleum engineers at four of the seven BLM field 
offices we visited stated that they generally consider the impact of 
liquids on measurement; however, BLM does not have sufficient 
regulations or guidance on this issue and a BLM official told us that 
BLM does not currently have the authority to require the installation 
of additional equipment that would remove liquids from the gas stream. 
One petroleum engineer explained that contracts between the operator 
and the pipeline company include a maximum limit on liquids in the gas 
stream and that, if the limit is exceeded, the pipeline company will 
refuse to transport the gas. However, most of BLM's points of 
measurement are at the well head, where liquids in gas may be more 
prevalent. Similarly, an OEMM official told us that OEMM does not 
require petroleum engineers to determine the extent to which any 
liquids may affect gas measurement. However, the official noted that a 
measurement system without any equipment to remove liquids prior to 
measurement would not be approved, but that there were no requirements 
to assess whether this equipment would sufficiently remove liquids. 
Similarly, offshore inspectors are not required to examine whether 
liquids are present in gas meters--but some OEMM inspectors told us 
that they would likely notice the presence of liquids. 

* Addressing low differential pressure. Interior has not fully 
addressed the impact of low differential pressures on gas measured by 
orifice meters. Typically, wells are calibrated for a continuous 
operating flow; however, there can be wide fluctuations in gas flow 
over time, resulting in extreme shifts in differential pressure--
either raising it or lowering it. According to BLM officials, 
accurately measuring gas under low-pressure conditions can be 
difficult. Operators may size the orifice plates and calibrate the 
meters to accurately measure the gas during times of high pressure. 
This, in turn, limits the ability of the meters to accurately measure 
gas at low pressure. To date, BLM does not have regulations 
specifically addressing the complexities that arise with measuring gas 
under low pressure. While BLM has developed a tool--an uncertainty 
calculator--which allows staff to input various measurement 
parameters, including the differential pressure, and determine whether 
the measurement uncertainty exceeds BLM's 3 percent limit, we found 
that staff are not consistently using this important tool. Moreover, 
according to a BLM official, an industry group has recently completed 
a study on the impact of low differential pressure on gas measurement 
with results suggesting that at lower differential pressures, 
measurement uncertainty increases. However, according to a BLM 
official, BLM has not fully reviewed the study, though its results 
could inform a policy on gas measurement at low differential pressures. 

* Inspecting meter tubes. Interior has not established goals for 
inspecting meter tubes, despite the potential impact on measurement 
that could result. According to BLM's 1994 draft gas measurement 
regulations, proper meter tube condition is essential for accurate 
measurement. These draft regulations established a requirement for 
operators to inspect the meter tubes once every 5 years; however, the 
regulations were not finalized, and BLM never implemented that 
requirement. Furthermore, BLM does not currently include meter tube 
inspections as a component of its inspection program. Similarly, OEMM 
has no regulatory requirement for inspecting meter tubes. 

Limited Oversight, Gaps in Staffs' Critical Measurement Skills, and 
Incomplete Tools Hinder Interior's Ability to Manage its Production 
Verification Programs: 

Interior's management of its production verification programs are 
hindered by its (1) limited and inconsistent oversight of its oil and 
gas production accountability programs; (2) difficulties in hiring, 
training, and retaining staff; and (3) longstanding challenges with 
providing inspection staff with key information technology tools to 
allow them to more efficiently complete their production inspections. 

Interior Has Exercised Limited and Inconsistent Oversight of its Oil 
and Gas Production Accountability Programs: 

Interior has not completed reviews of its production accountability 
programs' internal controls in recent years. Moreover, Interior's more 
decentralized organizational structure for its onshore inspection 
program, when compared to its offshore program, raises the risk of 
inconsistent program oversight. Finally, Interior's onshore oversight 
of production inspection data entry and key engineering decisions are 
less robust when compared with its offshore controls. 

Interior Has Not Recently Conducted Internal Reviews of Its Production 
Verification Internal Controls: 

Interior has exercised limited programmatic oversight of key areas of 
its oil and gas production verification programs. Like all federal 
agencies, Interior is required to conduct ongoing internal reviews of 
its internal controls by both the Federal Managers' Financial 
Integrity Act (FMFIA)[Footnote 45] and OMB Circular-123, Management's 
Responsibility for Internal Control. However, Interior has made 
inconsistent and, in some cases, incomplete efforts to meet this 
requirement. 

In accordance with this internal review requirement, senior management 
in both BLM and MMS are to annually determine which programs should be 
subject to formal review in order to supplement management's judgment 
as to the adequacy of internal controls and to ensure that adequate 
resources are allocated to evaluate those controls, among other 
responsibilities. Interior requires both BLM and MMS to annually 
create an Internal Control Review Plan that (1) summarizes their 
programs, (2) identifies the relative risk ranking of each of the 
programs, and (3) establishes the type of control evaluation to be 
conducted and the year the evaluation will be completed. However, BLM 
and MMS have undertaken inconsistent approaches to meeting these 
requirements. 

BLM has not conducted a timely review of its production accountability 
program and has recently lowered the risk associated with its 
production verification program, despite mounting evidence that the 
program is placing at risk Interior's ability to ensure that the 
federal government is accurately collecting revenue. In our review of 
BLM's completed internal control reviews, we found that it had not 
conducted any reviews related to production verification in the 
western United States since 2000. Moreover, while BLM had planned to 
complete a review in 2009, it was canceled in light of ongoing reviews 
being conducted by GAO and Interior's Inspector General. According to 
BLM's 2009 - 2011 Internal Control Review Plan, no subsequent 
production verification reviews are planned. Additionally, BLM has 
lowered its assessment of the risk of the program, despite reports 
issued by GAO, Interior's Inspector General, and the Royalty Policy 
Committee's Subcommittee on Royalty Management, that pointed out 
weaknesses in internal controls within Interior's oil and gas 
production and royalty collection programs. According to federal 
standards on internal controls, monitoring of internal reviews should 
include policies and procedures for ensuring that findings of audits 
and other internal reviews are promptly resolved.[Footnote 46] 
Additionally, Interior guidance requires that such reports should be 
given appropriate consideration in determining risk. In fiscal year 
2009, BLM lowered the risk rating of its oil and gas program from 
medium to low. According to a BLM official, risk ratings are assigned 
through a subjective evaluation based on program management knowledge. 
In reviewing supporting risk assessment documentation, we found 
several questionable assumptions in the years leading up to the risk 
determination made in the most recent plan. In reviewing supporting 
BLM oil and gas program risk assessment documentation, we found that 
BLM documents ranked the production accountability program as a low 
risk area for three reasons. First, BLM officials determined there was 
a low risk of lost potential revenue collection due to incorrect 
production reporting, despite the fact that Interior was missing tens 
of thousands of monthly production reports from operators. 
Specifically, BLM assumed that potential losses from not submitting 
production reports may only be 0.1 percent of royalties, which, given 
that onshore production accounted for approximately $2 billion, the 
losses might amount to $2 million. Second, BLM officials determined 
that there was a low risk of not completing its production inspections 
due to its workforce levels and the capability of the workforce. 
Finally, BLM officials concluded that due to significant efforts over 
the past several years to improve internal controls, the production 
accountability program had a low level of risk due to a lack of 
internal controls. 

Similarly, MMS has not completed any reviews of production 
verification related internal control activities in 5 years. While MMS 
completed one internal control review of OEMM's offshore inspection 
program in 2004, this review examined many aspects of the inspection 
program, not just those addressing production verification. The key 
findings of the review were that OEMM needed more clearly defined 
inspection strategies, and that about 70 percent of inspection staff 
had taken some training in measurement. According to MMS's 2009-2011 
Internal Control Review Plan, OEMM's production verification program 
is scheduled to be reviewed in 2011, although the scope of this review 
has yet to be planned. Finally, in contrast to BLM's low risk status 
for its production verification programs, MMS has assigned a medium 
risk status for both its offshore inspection program and its 
production verification program, although MMS officials were unable to 
provide us with supporting documentation for how they determined the 
risk level. 

Interior's Decentralized Approach to Onshore Oversight, When Compared 
to its More Centralized Approach to Offshore Oversight, May be 
Reducing Program Effectiveness: 

Interior has undertaken very different approaches to the oversight of 
the production inspection programs for onshore leases and offshore 
leases. BLM's production inspection program is decentralized, with 
field offices being granted a great deal of autonomy for making key 
decisions. In contrast, OEMM's Gulf of Mexico Regional Inspection 
Program is more centrally managed.[Footnote 47] The difference in 
oversight approaches may lead Interior to miss opportunities to 
identify best practices; deploy such tools across Interior's 
operations; and, as a result, place program oversight at risk. 

Agencies are generally provided the opportunity to determine how best 
to delegate responsibilities and conduct supervision. However, as a 
general matter, effective organizational structures should facilitate 
the flow of information needed for decision making to appropriate 
staff throughout the agency and provide for reasonable mechanisms to 
ensure that agency staff are appropriately supervised. An agency's 
structure may be centralized or decentralized given the nature of the 
organization's operations, but the management should be able to 
clearly articulate the considerations and factors taken into account 
in balancing the degree of centralization versus decentralization. 
According to Federal Standards for Internal Controls, key among the 
considerations for determining effective organizational structures are 
ensuring that clear internal reporting relationships have been 
established, which effectively provide managers information they need 
to perform their job.[Footnote 48] 

BLM's Inspection and Enforcement Program--which includes production 
inspections--for onshore leases is relatively decentralized (see 
figure 9). While BLM has created a number of mechanisms for 
coordinating the operations of the production inspection program 
across field and state office jurisdictional boundaries, key 
supervisory functions remain largely under the control of field 
offices where, according to some BLM officials, supervisors have 
limited understanding of the jobs they are supervising. BLM's 
Inspection and Enforcement Program is currently coordinated at the 
national level by two national lead coordinators, one of whom 
coordinates program issues through quarterly teleconferences with 
state coordinators. According to one of the national coordinators, 
much of the inspection program oversight has been delegated to state 
coordinators who are responsible for conducting periodic reviews of 
inspections completed by field office inspection staff and 
coordinating among the state's field offices. This national 
coordinator further told us that reviews completed by the state 
coordinators are not systematically reviewed at the national level. 
Under the federal standards for internal control, federal agencies 
should employ internal control activities, such as top-level review, 
to help ensure that management's directives are carried out and to 
determine if the agencies are effectively and efficiently using 
resources.[Footnote 49] According to several state coordinators, their 
reviews--which are not standardized--may include reviewing data in 
BLM's inspection database or participating with petroleum engineer 
technicians in conducting inspections in the field. Should a state 
coordinator identify areas of concern during these reviews, the state 
coordinator does not have authority to require that petroleum engineer 
technicians or production accountability technicians modify their 
work, as neither the national or state coordinators have supervisory 
authority over the BLM staff at the field office level. Rather, BLM's 
petroleum engineer technicians and production accountability 
technicians, in some field offices, report to and are evaluated at the 
field office level by BLM field office managers[Footnote 50] who, 
according to BLM staff, do not in all instances have a strong 
background in oil and gas operations and production verification. 
Furthermore, while BLM offers an "Oil and Gas Training for Managers" 
course, managers are not required to take it. Therefore, state 
coordinators must relay any findings or concerns about an individual's 
performance to the field office manager, though there is no 
requirement that the field office manager act upon any findings. 
Several state coordinators told us that providing input on inspectors' 
performance to field office managers has been met with varying degrees 
of success. For example, one state coordinator stated that the field 
office managers were generally unreceptive to input on their staffs' 
job performance; whereas, another state coordinator explained that 
field office managers had been accommodating to their feedback on 
petroleum engineer technicians' or production accountability 
technicians' performance. The national and state coordinators' lack of 
supervisory authority may be putting the inspection and enforcement 
program at risk of diminished effectiveness. 

Figure 9: GAO Representation of BLM's Production Verification 
Inspection and Enforcement Organizational Structure: 

[Refer to PDF for image: organization chart] 

National Inspection and Enforcement Coordinator (has advisory 
consultation responsibilities with all entities): 

BLM State Office Director (has direct supervisory authority over the 
following): 
* State Inspection and Enforcement Coordinator; 
* BLM Field Office Manager; 
- PE; 
- PET; 
- PAT. 

Source: GAO. 

[End of figure] 

In contrast, OEMM's Gulf of Mexico region inspection program is more 
centralized and systematic in its oversight of its five district 
offices (see figure 10). OEMM's inspection program is overseen 
directly by the supervisor of district operations, who has direct 
supervisory authority over each of the five district office managers. 
The district managers, who are typically petroleum engineers, 
supervise the district's chief inspector who, in turn, oversees the 
lead inspectors and other district inspectors. Furthermore, OEMM has a 
regional inspection coordinator whose role is to, in part, ensure that 
inspection activities are consistent across the OEMM district offices. 
In fulfilling these duties, the regional inspection coordinator has 
weekly discussions with lead inspectors in each of the five district 
offices and also holds a monthly teleconference among all supervisory 
inspection staff, for further coordination. In addition, the regional 
inspection coordinator conducts yearly consistency reviews of each 
district, which involve observing inspection personnel performing 
inspections, interviewing district inspection personnel, and reviewing 
inspection statistics. Findings and recommendations from the 
consistency reviews are documented in a standardized report. District 
offices are required to develop an action plan within 15 days to 
address any shortcomings identified during the review. If a district 
office fails to respond to the recommendations--which, according to 
the regional inspection coordinator, has not yet happened--then, 
regional management would be notified, according to the regional 
official who prepares these reports. 

Figure 10: GAO Representation of OEMM's Production Verification and 
Inspection Organizational Structure: 

[Refer to PDF for image: organization chart] 

OEMM Regional Manager (has direct supervisory authority over the 
following): 
* Regional Supervisor for Production and Development; 
* Petroleum Engineers, Surface Commingling and Production Management; 
* Regional Manager of District Operations (has direct supervisory 
authority over the following): 
* District Office Managers; 
* District Office Inspectors. 
* Regional Inspection Coordinator (coordinates inspections for the 
regional manager with District Office Inspectors). 

Source: GAO. 

[End of figure] 

Interior Has Exercised Limited Oversight of its Onshore Inspection 
Data and Engineering Approvals When Compared with Its Offshore 
Oversight: 

Our review also found that Interior's oversight of inspection data 
varied significantly between BLM and OEMM, with BLM exercising limited 
oversight of its onshore inspection data and, thereby, increasing the 
risk of inaccurate inspection data. Typically, BLM petroleum engineer 
technicians document the results of their inspections on BLM official 
forms and, later, enter those results in BLM's inspection database. 
Except for situations where a petroleum engineer technician has not 
completed the required training, BLM does not require that inspection 
forms be reviewed to ensure that inspections were properly conducted 
or that the results of those inspections were properly documented in 
its database. Furthermore, when BLM petroleum engineer technicians 
find violations in the field, they may issue incidents of 
noncompliance without supervisory review, unless the petroleum 
engineer technician has not completed the required training. 

We found BLM's controls over its production inspection data were 
insufficient to ensure accurate data. In examining BLM's controls over 
inspection data, we (1) reviewed a nongeneralizable sample of 43 hard 
copy production inspection files for inspections completed between 
fiscal years 2004 and 2008 for four of the seven field offices we 
visited[Footnote 51] and (2) analyzed all BLM production inspection 
data for fiscal years 2004 through 2008 from the nine field offices we 
reviewed. We found several errors, including discrepancies between 
what was documented in the hard copy files and what was entered in 
BLM's database and inconsistencies in how BLM's chart verification 
production inspection activity was conducted to ensure accurate gas 
measurement. Additionally, we found errors in how specific production 
inspection activities were entered into BLM's database. 

Specifically, our review of 43 hard copy files identified instances 
where inspection activities documented in BLM's database were not 
supported by documents in the hard copy files and that BLM staff were 
inconsistently completing the chart verification production inspection 
activity--an activity to independently verify the electronic flow 
computers' gas volume calculations. BLM's internal guidance for 
documenting inspections requires that, without exception, 
documentation gathered during the inspection be incorporated into the 
hard copy files. Yet, we identified instances where BLM's database 
indicated that a particular activity had been completed, but no 
supporting documentation was included in the hard copy file. For 
example, we identified several instances where BLM's database 
indicated that a meter calibration activity had been completed, yet no 
calibration report was included in the hard copy file. We further 
found other instances where BLM staff were unable to locate hard copy 
files, and one instance where a hard copy file contained no 
information. 

Our hard copy file review also found instances where BLM staff were 
inconsistently completing the chart verification production inspection 
activity--an activity to verify the reasonableness of the monthly 
operator-reported volumes and that the electronic flow computer is 
functioning properly. We found some instances where BLM staff compared 
the operator-submitted monthly gas volumes, divided by the number of 
days in the month to the daily gas volumes displayed on the well's 
electronic flow computer to determine whether they are were reasonably 
close. Alternatively, we found that other BLM staff used parameters 
displayed in the electronic flow computer to independently recalculate 
the volumes and compare those volumes to the volume displayed on the 
electronic flow computer. Additionally, one BLM petroleum engineer 
technician told us he used BLM's Gas Measurement Uncertainty 
Calculator, which is used to verify whether gas is measured within an 
overall 3 percent uncertainty range, when completing a chart 
verification inspection activity, although we found no evidence of 
this in the hard copy files we selected. Furthermore, though BLM's 
internal guidance for documenting inspections states that precise and 
clear documentation allows anyone reviewing the file to verify the 
inspection type and all completed activities associated with that 
inspection, we found that hard copy files in two of the four field 
offices were disorganized and not easily interpreted. For example, in 
several of the files, it was not possible to determine what inspection 
actions were completed without the assistance of BLM officials. 

Finally, our analysis of all production inspection data recorded in 
BLM's database for fiscal years 2004 through 2008 for the nine field 
offices we reviewed, found that approximately 38 percent of the 
production inspections appeared to be coded incorrectly, suggesting 
that BLM does not have sufficient controls in place to ensure that 
production inspections are being conducted or entered into its 
database in accordance with agency policy. Specifically, BLM guidance 
on entering data for production inspections states that duplicate 
inspection activities should not be entered for the same inspection 
unless an oil or gas volume discrepancy was found; yet approximately 
10 percent of inspections we analyzed included duplicate entries for 
inspection activities that are not associated with volume 
discrepancies. For example, a single production inspection from fiscal 
year 2004 had site security coded nine times and surface protection 
coded ten times which, according to BLM's database coordinator, is 
incorrect. Further, an additional 28 percent of production inspections 
recorded in BLM's database appeared to be erroneous because they did 
not include all four required inspection activities. For example, 
production inspections for producing cases should have four associated 
inspection activities--record review, surface protection, site 
security, and at least one measurement-related activity. However, we 
found numerous examples where the inspections were missing one or more 
of these activities (see table 8). 

Table 8: BLM Production Inspection Activity Data, Fiscal Years 2004- 
2008: 

Total production inspections: Production inspections recorded in 
accordance with BLM criteria; 
Number: 6,443; 
Percentage: 62. 

Total production inspections: Production inspections with erroneous 
duplicate inspection activities and/or potential missing inspection 
activities; 
Number: 994; 
Percentage: 10. 

Total production inspections: Production inspections with missing 
inspection activities and no duplicate inspection items; 
Number: 2,893; 
Percentage: 28. 

Total production inspections: Total; 
Number: 10,330; 
Percentage: 100. 

Source: GAO analysis of BLM data. 

[End of table] 

In contrast, OEMM has stronger supervisory controls for inspection 
data, providing greater assurance these data are accurate. Inspectors 
document the results of their inspections on official OEMM forms, 
specifying the kinds of inspections completed; which meters were 
observed; and what, if any, violations were documented. After the 
inspections are completed, one or more supervisory inspectors review 
the inspection form, and then give it to a clerical worker for 
recording in OEMM's database. If violations are found, they are issued 
during the inspection and are reviewed by supervisory inspectors. 

In examining OEMM's controls over inspection data, we also reviewed a 
nongeneralizable sample of 20 hard copy production inspection files 
for inspections completed between fiscal years 2007 and 2008 for two 
of the four district offices we reviewed.[Footnote 52] We found one 
instance where what was documented in the OEMM hard copy file did not 
match what was entered in OEMM's database regarding one of the two 
inspection activities--meter calibration witnessing. In the other 19 
instances, we found that the hard copy inspection files matched what 
was in OEMM's database. We also found that the files were complete, in 
that they contained the required documentation for these inspections. 

Regarding engineering approvals, there are also inconsistent 
supervisory controls between onshore and offshore programs, as well. 
We found that production measurement related engineering approvals 
completed by BLM petroleum engineers are typically not reviewed by 
other engineers. In many of the field offices we visited, petroleum 
engineers have approval authority for both variances of measurement 
regulations, as well as commingling and allocation agreements. These 
engineering approvals are significant and can greatly impact 
production verification and accountability for a number of years. Yet, 
BLM does not have controls in place to ensure a reasonable level of 
consistency in applying these policies. According to BLM petroleum 
engineers we spoke with, their engineering approvals have not been 
routinely reviewed, and according to one BLM official, the effect of 
poor decisions could have long-lasting impacts. For offshore 
production, OEMM engineers who approve systems for measuring oil and 
gas are centralized in one of OEMM's three regional offices: the Gulf 
of Mexico, Pacific, and Alaska.[Footnote 53] The OEMM engineering 
approvals of proposed measurement systems and commingling arrangements 
are reviewed twice--first by a supervisory engineer, and then by the 
section chief, who signs and issues the final approval. 

Interior Lacks Staff with Critical Production Verification Skills 
because of Difficulties in Hiring, Training, and Retaining Staff, 
Placing Production Verification Efforts at Risk: 

Interior's production verification program staff lack critical skills 
because of challenges in hiring experienced staff, not consistently 
providing the appropriate training for these staff, and high turnover 
in key production verification positions, according to agency 
officials. Onshore, agency officials told us that Interior has 
experienced challenges in hiring staff for its petroleum engineer, 
petroleum engineer technician, and production accountability 
technician positions; providing these staff with timely and ongoing 
training; and retaining these staff over the long term. Furthermore, 
while Interior's staffing challenges are less pronounced for its 
offshore program, there have been fewer difficulties in hiring and 
retaining staff, the agency has not consistently offered its engineers 
or inspectors a formal training program on oil and gas measurement 
(see table 9). 

Table 9: Summary of Hiring, Training, and Retention Issues Identified 
for Interior Production Verification Staff: 

BLM: 

Petroleum engineer; 
Hiring: [Check]; 
Training: [Check]; 
Retaining: [Check]. 

Petroleum engineer technician; 
Hiring: [Check]; 
Training: [Check]; 
Retaining: [Check]. 

Production accountability technician; 
Hiring: [Check]; 
Training: [Check]; 
Retaining: [Check]. 

OEMM: 

Petroleum engineer; 
Hiring: [Check]; 
Training: [Check]; 
Retaining: [Empty]. 

Inspector; 
Hiring: [Check]; 
Training: [Check]; 
Retaining: [Check]. 

MMS: 

Liquid and Gas verification system staff; 
Hiring: [Empty]; 
Training: [Empty]; 
Retaining: [Empty]. 

Source: GAO analysis. 

[End of table] 

Interior Has Key Weaknesses in Hiring, Training, and Retaining Staff 
in Critical Measurement Positions, Reducing Assurance that Oil and Gas 
Are Accurately Measured: 

Interior has weaknesses in key onshore and offshore positions critical 
for providing assurances that oil and gas are measured accurately due 
to challenges in hiring, training, and retaining these staff. Under 
federal standards for internal controls, federal agencies are to 
maintain effective management of their workforce in order to achieve 
results. Management should ensure that skill needs are continually 
assessed and that the organization is able to obtain a workforce that 
has the required skills that match those necessary to achieve 
organizational goals. Training should be aimed at developing and 
retaining employee skill levels to meet changing organizational needs. 
[Footnote 54] Specific to oil and gas activities, FOGRMA requires that 
the Secretary of the Interior establish and maintain adequate programs 
for the training of all such authorized representatives in methods and 
techniques of inspections and accounting that will be used in the 
implementation of the law.[Footnote 55] 

According to both BLM and OEMM staff, hiring for the following key 
positions has been difficult in recent years because of low pay 
relative to comparable private sector jobs: BLM and OEMM petroleum 
engineers, BLM petroleum engineer technicians, BLM production 
accountability technicians and OEMM inspectors. For example, BLM's 2008 
- 2013 Human Capital Plan identifies both the petroleum engineer and 
petroleum engineer technician positions as critical to its mission and 
identifies high salaries offered by industry and a lack of affordable 
housing in energy "boom towns" as factors that make recruiting 
employees for these positions difficult. Additionally, a 2007 study 
conducted by BLM on position classifications for its petroleum 
engineers and petroleum engineer technicians found, in many cases, a 
significant pay disparity between federal employees and the private 
sector, though the amount varied by location. For example, the report 
found that starting salaries for BLM petroleum engineers entering the 
workforce for the first time were between $10,000 and $35,000 less per 
year than in the private sector. Furthermore, while some BLM officials 
acknowledged benefits to government employment, including job 
stability, this benefit has not been sufficient to consistently 
attract qualified candidates. Additionally, BLM officials told us that 
several areas where BLM has field offices also have high costs of 
living, including in Pinedale, Wyoming, and Glenwood Springs, 
Colorado. In both of these locations, BLM officials told us that they 
had experienced difficulties in hiring staff at current salary levels 
because housing costs in these localities were such that finding 
affordable housing was extremely difficult. Offshore, OEMM officials 
told us that hiring petroleum engineers and inspectors had been 
difficult, but less so for engineers recently because of the economic 
downturn. OEMM officials told us that the private sector was able to 
offer significantly higher salaries for inspectors, compared with 
OEMM. However, one benefit OEMM offers is that, unlike many private 
sector offshore jobs, which require extended stays on offshore 
platforms, OEMM inspectors infrequently spend more than one day on a 
platform. 

Neither BLM nor OEMM have consistently provided training necessary for 
performing official job duties of BLM and OEMM petroleum engineers, 
BLM petroleum engineer technicians, BLM production accountability 
technicians, and OEMM inspectors. For example, BLM and OEMM petroleum 
engineers are not required to take measurement training or other 
courses related to production verification. Specifically, BLM's 
petroleum engineers, who generally have responsibility for approving 
measurement methods not authorized under current regulations and 
reviewing and approving commingling agreements, do not have any 
required initial measurement training or subsequent annual maintenance 
training requirements. Similarly, OEMM petroleum engineers do not have 
specific measurement training requirements; instead, relying on an 
annual training plan that is developed according to individual topic 
preferences. Furthermore, BLM has not provided its petroleum engineer 
technicians and production accountability technicians with the 
necessary training. For example, BLM offers a core curriculum for its 
petroleum engineer technicians, requiring that they pass a six module 
training course, obtain official BLM certification, and then be 
recertified once every 5 years to demonstrate continued proficiency; 
however, BLM has not offered a recertification course since 2002. 
While BLM has, on occasion, offered training for its production 
accountability technicians, both a BLM training coordinator and staff 
we spoke with stated that it was not sufficient for fully 
understanding and performing the full range of job responsibilities. 
In contrast, OEMM does not offer its inspectors a core inspection 
training curriculum, though there is a requirement for completing 60 
hours of training. In 2009, the Gulf of Mexico OEMM region also 
provided its inspectors with a newly implemented measurement class. 
However, while OEMM officials at four district offices we spoke with 
acknowledged that measurement issues were complex, OEMM does not 
systematically evaluate the extent to which inspectors have 
measurement knowledge, nor are there requirements for inspectors to 
take specific measurement training. As a result, OEMM does not have an 
effective system to evaluate whether its inspection staff lacks 
important measurement expertise. 

Finally, Interior has struggled with high turnover rates in its 
onshore production verification positions. Specifically, we found that 
turnover rates for BLM's petroleum engineers, petroleum engineer 
technicians, and production accountability technicians were generally 
high and, according to BLM officials, were negatively impacting 
program implementation. Furthermore, we obtained and analyzed BLM 
human capital data and found that, for example, the overall turnover 
rate for petroleum engineers was between 33 and 100 percent between 
fiscal years 2004 through 2008 for the eight field offices we 
examined.[Footnote 56] Similarly, the overall turnover rates for the 
same period for petroleum engineer technicians ranged between 30 and 
83 percent for 7 of the 9 field offices we examined; with the 
remaining two offices having turnover rates of 22 percent or less. 
Finally, overall turnover rates for production accountability 
technicians were also generally high, with 8 of the 9 field offices 
having turnover rates of 50 percent or more between fiscal years 2004 
and 2008.[Footnote 57] According to BLM officials, staff turnover is 
impeding the production verification program in two areas. First, 
staff turnover results in the loss of institutional knowledge of the 
program. Second, BLM must direct its resources toward attracting and 
hiring staff, then have more senior staff provide on-the-job training 
for the new staff, which limits the senior staffs' capacity for 
completing their own work. Finally, BLM's 2008 - 2013 Human Capital 
report suggests that turnover will continue to be a challenge as it 
estimates that approximately 25 percent of its petroleum engineers and 
47 percent of its petroleum engineer technicians will be eligible to 
retire by 2013. In contrast, OEMM petroleum engineers and inspectors 
generally had overall turnover rates less than BLM for fiscal years 
2004 through 2008. For example, overall turnover rates for OEMM 
petroleum engineers in the OEMM Gulf of Mexico and Pacific regional 
offices--which are responsible for measurement approvals for the four 
district offices we reviewed--did not have overall turnover rates 
exceeding 30 percent between fiscal years 2004 and 2008. Additionally, 
we found that overall turnover rates for OEMM inspectors varied 
between 27 and 44 percent between fiscal years 2004 and 2008. For 
example, the California district office had an overall rate of 44 
percent turnover, based on the four inspectors who left the position 
over those 5 years; the Lake Jackson, Texas, district office had an 
overall rate of 27 percent turnover. Finally, according to MMS 
officials, MMS has added a significant number of staff to its Liquid 
and Gas Verification system to help address current backlogs. Current 
provisions in federal employment regulations allow agencies to adjust 
pay rates to be more competitive with the private sector. For example, 
federal agencies may increase pay by increasing the General Schedule 
grade of the position, requesting special pay rates for difficult to 
fill positions, and providing bonuses for hiring and retention. 
However, while BLM has only recently begun to use some financial 
incentives for recruiting and retaining staff, BLM has not adjusted 
its overall pay structure for these positions and turnover rates 
remain high (see appendix IV for additional information on human 
capital challenges within key measurement positions). 

Interior's Longstanding Efforts to Implement Two Key Technologies to 
Improve Production Verification Are Behind Schedule and Years From 
Widespread Implementation: 

Interior's efforts to develop (1) software to allow inspection staff 
to remotely monitor gas production, and (2) a mobile computing 
platform for inspection staff to enter inspection results while in the 
field, are behind schedule and, according to agency staff, years from 
widespread use. 

Interior's 10-Year Effort to Obtain Continuously Updated Gas 
Production Data Have Shown Few Results: 

BLM's Remote Data Acquisition for Well Production (RDAWP) program--a 
program designed to allow BLM staff to monitor gas production in near 
real-time--has shown few results, despite 10 years of development at 
costs of over $1.5 million. BLM envisioned the RDAWP program as a 
means to provide industry and government with common tools to validate 
production and to view production data in near real-time in an 
automated and secure environment. BLM developed the concept of 
remotely monitoring oil and gas production data through meetings held 
with BLM field staff in 1999. Presently, many companies receive 
production data in real-time via Supervisory Control and Data 
Acquisition (SCADA) software. RDAWP works by BLM attaching specially 
designed electronic equipment to the company's computer server, which 
relays the SCADA production data to a BLM server. Currently, BLM has 
only been able to access these electronic data through individual 
voluntary agreements with companies--as BLM does not currently require 
that operators of federal leases provide BLM access to raw production 
data from the electronic flow computers. According to the BLM project 
manager, if BLM staff had access to these data, BLM could potentially 
complete production inspections more quickly and reduce the burden on 
industry in fulfilling BLM audit requests for multiple years of 
electronic flow computer production data and meter calibration 
reports. Specifically, according to BLM's project manager and project 
documents, RDAWP would provide BLM staff with a more automated means 
to complete several gas production inspection activities, such as: 

* Verifying Electronic Flow Computer Gas Calculations. First, RDAWP 
would assist in verifying volumes reported by the operator on the 
monthly production reports by integrating the reports into the RDAWP 
software. Second, RDAWP would automatically independently recalculate 
the gas volumes and compare it to the volume generated by the 
electronic flow computer. Finally, RDAWP would reduce the need for BLM 
staff to visit the field to complete this work as the data would be 
available in the field office. 

* Meter Calibration. Currently, meter calibration inspection 
activities may be completed by either reviewing meter calibration 
reports or actually witnessing a meter calibration. RDAWP would 
greatly assist in this task because when electronic flow computers 
were calibrated, it would generate an event log that would clearly 
record and store the "as found" and "as left" calibration values. With 
RDAWP, BLM staff would be able to determine from the office whether 
meters had been calibrated within the required time frame, and if any 
error was greater than 2 percent, which, according to BLM regulations, 
requires that the operator correct and resubmit previous monthly 
production reports. 

* Other Inspection Activities. Finally, data obtained from the 
electronic flow computers would also provide several other key data. 
Currently, BLM requires gas sample analyses annually, unless otherwise 
approved. As the BTU value of gas is necessary for calculating the 
volume, according to a BLM official, the gas sample data must be 
entered into the electronic flow computer. RDAWP's ability to pull in 
data from the electronic flow computers would assist BLM staff in 
ensuring that gas samples were being taken. Additionally, BLM would 
more easily be able to track well status--or whether the well was 
producing or not producing. BLM has historically faced challenges in 
having accurate information on whether or not a well was producing. 
RDAWP would allow BLM staff to see, on a daily basis, whether the well 
was producing and how many days in a month it produced. 

In 2003, BLM proposed a business case for obtaining real time 
production data--which eventually became known as RDAWP--that 
consisted of four phases: 

Phase I. An initial pilot project encompassing 60 wells with one 
operator in the Farmington, New Mexico, resource area. 

Phase II. If BLM opted to proceed after Phase I, a second phase would 
proceed with 300 to 600 wells, from three to four operators, and 
include the Farmington, New Mexico; Durango, Colorado; and Buffalo, 
Wyoming, field offices. 

Phase III. The third phase would be full-scale use of RDAWP across all 
federal leases. 

Phase IV. The last proposed phase would be to apply the technology and 
knowledge from RDAWP at the well head to other applications, such as 
using it to monitor major pipelines and other elements of the nation's 
infrastructure. 

The 2003 BLM business case also states that there are no other 
available alternatives to RDAWP that can deliver the requirements of 
this proposal. Furthermore, while BLM acknowledged that oil and gas 
companies may employ technologies similar to RDAWP for monitoring oil 
and gas production, according to a BLM official, BLM lacks the 
authority to access companies' secured servers to obtain this 
production data. Finally, the contractor responsible for implementing 
the RDAWP program proposed a roll-out schedule that would begin with 
200 wells connected to RDAWP in the first quarter of 2004 and ending 
in the third quarter of 2009 with a total of 108,500 wells connected. 

As of the fourth quarter of 2009, BLM has completed trials in two 
field offices, has an ongoing pilot project in one field office where 
50 wells are connected to RDAWP, and spent in excess of $1.5 million 
on the RDAWP program for fiscal years 2003 through 2009. Since 2003, 
according to the current project manager, RDAWP pilot projects have 
been conducted in two BLM field offices, Farmington, New Mexico, and 
one in Wyoming--although the manager could not identify which Wyoming 
field office. During these pilot projects, according to BLM officials, 
improvements were made to the RDAWP technology. However, funding and 
IT issues related to the Cobell lawsuit, according to a BLM official, 
considerably slowed the project. Finally, when we asked BLM project 
management staff to provide specific data on the $1.5 million RDAWP 
expenditures, it was unable to do so. 

In March 2009, we visited the Glenwood Springs, Colorado, BLM field 
office to assess the effectiveness of the ongoing pilot project, which 
had begun in late 2008. According to BLM staff, they had not yet used 
the RDAWP system to assist in completing an actual production 
inspection because the RDAWP software was incorrectly calculating 
volumes. Additionally, RDAWP was unable to fully access the event logs 
from the electronic flow computer or the operator-reported monthly 
production report from BLM's inspection database. Finally, BLM staff 
told us that they had not been given any criteria by which to evaluate 
the RDAWP pilot project. BLM staff did say, however, that RDAWP could 
be an effective tool if it worked as designed. We followed up with 
staff in the Glenwood Springs, Colorado, field office in late July 
2009 to learn whether or not any changes had occurred. A BLM official 
told us that RDAWP now appeared to be calculating the volumes for the 
50 wells correctly and that BLM management was working with the 
company to increase the number of wells included in the RDAWP program 
to those within the entire case. This would, according to the BLM 
official, allow staff to use the software to help complete a single 
production inspection. 

Also, in early 2009, BLM updated its cost-benefit analysis plan for 
RDAWP, which included elements of the contractor's roll-out schedule. 
The roll-out schedule envisioned that by the end of the first quarter 
in 2009, 200 wells would be connected to RDAWP, and that by the end of 
the first quarter of 2010, approximately 9,000 wells would be 
connected. This outcome appears unlikely given the limited number of 
wells currently connected. 

Despite the conclusion made by Interior in its 2003 business case 
analysis, it appears that there are commercial alternatives to 
Interior's efforts. During the development of RDAWP, another program 
within BLM responsible for monitoring and auditing gas volumes 
acquired commercially available off-the-shelf software to assist in 
production verification. Specifically, in 2008 BLM's Helium program, 
overseen by the Amarillo, Texas, field office, BLM worked with 
producers and purchasers of helium to procure a common suite of 
software. According to the BLM Helium program manager, the benefits of 
this approach are that purchasers, transporters, and the seller (BLM) 
have a common data platform through which they can verify volumes and 
audit one another. According to the program manager, this software 
cost approximately $500,000, which included training and 5 years of 
support. As part of our review, we spoke with representatives of the 
company that developed this software and found that it provides 
similar functionality to that offered through RDAWP. Additionally, 
according to a representative of the company participating with BLM in 
the RDAWP program, this software is widely used within the oil and gas 
industry, and has many of the functionalities outlined as goals for 
the RDAWP program. In 2006, as part of BLM's RDAWP development 
process, BLM completed an alternative analysis to examine its options 
for its production verification program. This analysis compared three 
options, including (1) maintaining the status quo and continuing to 
rely on-the-ground inspections, (2) procuring a customized off-the-
shelf solution--RDAWP, or (3) developing software entirely in-house 
for obtaining well head production data. However, it does not appear 
as though BLM considered the software obtained by BLM's Helium program 
in its analysis of option 2 because only the RDAWP option is included 
in the section identifying customized off-the-shelf technology 
alternatives. See appendix V for production verification tools and 
policies used by other countries, states, and private companies, but 
not widely used by Interior. 

Interior's Efforts to Provide Inspection Staff with Mobile Computing 
Capabilities For Use in the Field Are Moving Slowly and Are Years From 
Full Implementation: 

Interior's BLM and OEMM are independently developing the capacity for 
inspection staff to (1) electronically document inspection results, 
and (2) access reference documents, such as API standards and 
measurement regulations, via laptops while in the field. BLM initiated 
work on this tool in 2001, whereas OEMM is now in the preliminary 
planning stages of a similar tool. According to agency officials, 
widespread implementation of a mobile computing tool to assist with 
production verification is still several years away. 

In 2000, according to the BLM official previously responsible for 
developing BLM's mobile computing capabilities, BLM identified a need 
for an alternative to its current approach of documenting inspection 
results on paper while in the field, and subsequently entering the 
results in BLM's database when back in the office. At the time, 
according to this official, BLM management identified two concerns 
with the current approach; first, staff had to contend with duplicate 
data entry--once in the field on paper, and once back in the field 
office into the database; and second, inspection data were not being 
entered into the database in a timely manner. In 2001, according to 
this same official, BLM received funds to fulfill a requirement in the 
Energy Policy and Conservation Act Amendments of 2000 for an inventory 
of onshore oil and gas reserves and concluded that an investment in 
mobile computing was warranted.[Footnote 58] The development of mobile 
computing was initially directed toward work associated with drilling 
inspections. At the time, according to this official, the Buffalo, 
Wyoming, BLM field office was experiencing high drilling rates for 
coalbed methane, and the field office manager was looking for ways to 
minimize the amount of time petroleum engineer technicians spent in 
the office entering data; the field office manager, according to a BLM 
official, proposed that mobile computing could be part of the 
solution. After evaluating several options, BLM selected one option 
and started a pilot in 2001. According to feedback from petroleum 
engineer technicians, the BLM official told us that initial results 
were positive, with some technicians estimating a time savings of 50 
percent through having the ability to document drilling inspection 
data on a laptop, and later uploading those data into BLM's database. 
The BLM project team then examined its applicability for other types 
of inspections, including production. However, in 2003, Interior's IT 
systems were seriously impacted by the Cobell Lawsuit.[Footnote 59] 
The mobile computing project was initiated again in 2006 after BLM 
received additional funding for seven field offices. BLM used 
approximately $200,000 to purchase laptops designed to withstand use 
in the field, for inspection staff in the seven offices. However, 
despite this purchase of computers, BLM had not developed software for 
electronically documenting production inspections. In April 2008, BLM 
worked with a company specializing in field data collection software 
development--including for the oil and gas industry--to explore 
various mobile computing options for BLM. According to the BLM 
official, over the course of several days, BLM and the company were 
able to develop prototype electronic forms for the several types of 
BLM oil and gas inspections through a slight modification of the 
company's off-the-shelf software. More recently, in August 2009, a BLM 
national inspection and enforcement coordinator told us that a BLM IT 
advisory group decided to prioritize the electronic forms for 
production inspections over other inspection types. However, the 
official was unable to provide us with a time frame for when this 
technology would be widely adopted at the field office level. 

In our discussions with petroleum engineer technicians from the seven 
field offices we visited, we learned that some staff in three of the 
field offices we reviewed generally used laptops while in the field. 
However, those staff using laptops stated that this use is not helping 
reduce duplicate data entry because there are no electronic forms for 
many of the inspections, and they currently lack the ability to 
automatically upload their inspection results into BLM's inspection 
database. Staff in all seven field offices told us that having the 
capability to document inspections in the field and upload them into 
the database at the end of the day would save time, allowing them to 
spend more time in the field doing actual inspection work. 
Additionally, the former project manager stated that the use of 
electronic forms could also improve the reliability of inspection data 
through the use of data edit checks. For example, an electronic form 
could be designed so that duplicate inspection activities could not be 
entered for the same inspection and that inspections could not be 
closed out unless all the relevant data fields were populated. 

According to OEMM officials, OEMM is also considering the use of 
mobile computing in its inspection program. However, it is at the 
conceptual stage and no money has yet been allocated to development. 
The justification for moving toward mobile computing is the need for 
OEMM inspectors to have access to large amounts of technical reference 
material to complete inspections. For example, one official explained 
that right now, some inspectors are carrying 50 pounds of paper with 
them when they fly out to platforms to complete inspections, and that 
the ability to access this reference material electronically would 
benefit the inspectors. Moreover, with inspectors having the 
capability to electronically document inspections in the field, OEMM 
would be able to free up those data entry staff to work on other 
programs, rather than their current practice of recording inspections 
on paper and then handing the paper copies to other staff in the 
district offices to enter into OEMM's inspection database. OEMM 
officials also stated that electronic data entry would provide 
additional controls for ensuring that the reliability of inspection 
data remains high. For example, with the proper edit checks, OEMM 
would not have had the data issues with the site security data entries 
that prevented it from knowing the number of inspections it completed 
between 2004 and 2007. Finally, OEMM officials stated that this 
initiative would be funded under the program budget for updating 
OEMM's entire database, called OCS (Outer Continental Shelf) Connect. 
The officials told us that funding would not be available for at least 
20 months, so full implementation of mobile computing is at least 2 to 
4 years away. 

Conclusions: 

The Department of the Interior is charged with the critical role of 
ensuring that the country's oil and gas assets are carefully developed 
and that the American people receive fair compensation when these 
assets are sold. A key part of this role consists of providing 
reasonable assurance that oil and gas are accurately measured and that 
measurement efforts undertaken by the private companies that are 
developing these national resources are held to high standards. 
Interior's current approach of delegating to BLM and OEMM the 
responsibility for developing and updating oil and gas measurement 
regulations, approving measurement technologies not addressed by 
current regulations, and developing policies for commingling oil and 
gas has resulted in inconsistent regulations and decisions regarding 
measurement. This has resulted in inefficiencies and increased risk of 
inaccurate oil and gas measurement. While Interior's Production 
Coordination Committee, on which representatives of BLM, OEMM, and MMS 
serve, has been tasked with providing advice on measurement issues, 
the Committee's lack of formal decision-making authority for these 
critical issues at the department level means that Interior cannot be 
assured that it is accurately measuring federally produced oil and gas. 

Additionally, because Interior has not determined the extent of its 
authority over key elements of the oil and gas production 
infrastructure, the result has been limited oversight of key 
facilities, including pipelines and gas plants, which refine gas into 
royalty-bearing saleable commodities. Furthermore, according to 
Interior officials, in instances when pipeline companies own and 
maintain meters on federal leases, Interior has limited direct access 
to them or their associated production data. This absence of rigorous 
federal oversight increases the risk that oil and gas may not be 
accurately measured. 

Interior also has not ensured that controls over where and how oil and 
gas are measured are being consistently applied to leases located 
offshore and onshore, and BLM does not provide sufficient criteria for 
approving commingling agreements to enable staff to verify that oil 
and gas are being measured and reported accurately under such 
agreements. Without the ability to consistently track where and how 
oil and gas are measured, Interior cannot be assured that production 
reported to Interior is accurate. 

Furthermore, Interior's delegation of production accountability 
inspection programs to BLM and OEMM has resulted in inconsistent 
emphasis on key areas affecting oil and gas measurement accuracy 
across the two agencies. Also, while OEMM now appears to be able to 
meet its annual goals for inspecting oil and gas producing leases 
under its revised strategy, BLM has not consistently been able to do 
so. This lack of consistency, as well as BLM's inability to inspect 
all wells, does not provide Interior sufficient assurance that it is 
properly measuring and accounting for oil and gas removed from federal 
lands. 

Moreover, BLM faces challenges overseeing production verification 
through its field office structure. While decentralized management 
approaches can be effective, BLM's structure and lack of top level 
review has led to inconsistencies within its production verification 
program across field offices. Without such review, BLM is not 
employing internal control activities specified in federal standards. 
Further, BLM's database and hard copy files have a wealth of 
information on oil and gas production inspections, but without 
adequate controls to ensure complete and accurate production 
inspections and lacking the transfer of this information into 
Interior's electronic data systems, BLM may lack adequate data to 
track annual progress toward meeting its goals and demonstrating 
compliance with its regulations. 

In addition, according to agency staff, because Interior has not 
provided sufficient or timely training for many of its key staff 
responsible for oil and gas measurement, knowledge gaps exist 
departmentwide, but are particularly pressing in some disciplines and 
in some BLM field offices. Compounding this, according to agency 
staff, program operations at many BLM locations are being further 
impeded by high staff turnover rates. Furthermore, while the recent 
downturn in the oil and gas sector has reduced competition between 
Interior and the private sector for staff, as the economy improves and 
oil and gas companies begin hiring again, Interior may, once again, 
increasingly be challenged in attracting and retaining qualified 
staff. Until Interior can maintain a well-trained and stable 
production verification workforce, Interior risks not having staff 
with sufficient knowledge to identify inaccurate oil and gas 
measurement. 

Finally, Interior has begun developing tools it anticipates will lead 
to greater staff productivity, but it has been unable to deploy these 
tools on a widespread basis. Specifically, while BLM has made progress 
in developing in-house software for obtaining and analyzing gas 
production data from electronic flow computers, it has fallen behind 
the private sector in collecting and analyzing these data and adopting 
common software that facilitates data exchanges for verifying oil and 
gas volumes. Additionally, while BLM has recognized the need for staff 
to have mobile computing technology for documenting production 
inspections in the field, it has not developed the necessary 
technology. OEMM has recently expressed an interest in developing a 
similar tool for its inspectors, yet no coordination has occurred 
between BLM and OEMM on the development of such a tool. 

Recommendations for Executive Action: 

To increase Interior's assurance that it is accurately measuring oil 
and gas produced on federal lands and waters, we are making 19 
recommendations to the Secretary of the Interior. 

To improve the consistency and efficiency of Interior's oil and gas 
measurement regulations and policies, we recommend that the Secretary 
empower a centralized panel consisting of staff with measurement 
expertise from BLM and OEMM to take the following actions: 

* increase consistency between offshore and onshore measurement 
regulations, as appropriate; 

* annually review changes in the industry measurement technologies and 
standards that Interior's regulations reference to determine whether 
the related regulations should be updated; 

* provide departmentwide guidance on measurement technologies not 
addressed in current regulations and approve variances for measurement 
technologies in instances when such technologies are not addressed in 
current regulations or departmentwide guidance; and: 

* develop guidance clarifying when federal oil and gas may be 
commingled and establish standardized measurement methods in such a 
way that production can be adequately measured and verified. 

To provide greater assurance that key elements in the oil and gas 
production infrastructure are adequately overseen, the Secretary 
should determine the extent to which Interior has authority regarding: 

* pipelines, including meters that pipeline companies own, as well as 
other methods transportation companies use to ship and measure oil and 
gas produced from federal leases; and: 

* gas plants that process gas from federal leases, including the 
requirements and responsibilities for approving gas plant meters, and 
conducting inspections of them. 

If Interior determines that its authority over any of these components 
is lacking or unclear, the Secretary should seek the appropriate 
authority or clarification from Congress. 

To help ensure that Interior is consistently tracking where and how 
oil and gas are measured, the Secretary should require that: 

* BLM track all onshore meters, including information about meter 
location, identification number, and owner; 

* MMS require onshore operators to report meter identification numbers 
in the required monthly production reports; and: 

* BLM petroleum engineers work with BLM staff conducting production 
verification to confirm that commingling agreements are (1) consistent 
with Interior guidance on such agreements, and (2) are adequately 
structured to facilitate key production verification activities before 
such agreements are approved. 

To help ensure that Interior's production accountability inspection 
program consistently addresses key areas affecting measurement 
accuracy and that BLM meets its inspection goals, the Secretary should: 

* establish goals for (1) witnessing onshore oil and gas meter 
calibrations, (2) witnessing onshore and offshore gas sample 
collections, (3) comparing onshore reported BTU values with gas 
analyses, and (4) inspecting onshore and offshore orifice plates and 
meter tubes; and: 

* consider an alternative onshore production inspection strategy that 
enables BLM to inspect all wells within a reasonable time frame, given 
available resources. 

To improve the consistency of Interior's management of its onshore 
production and inspection program, the Secretary should direct BLM to: 

* review and revise, as appropriate, its oversight of field and state 
offices and train managers involved in BLM's inspection and 
enforcement program to ensure adequate and appropriate review of 
personnel, processes, and production, consistent with standards for 
internal controls; and: 

* conduct reviews of the quality and completeness of the hard copy 
production inspection program files across field offices periodically 
and ensure that the data in these files are accurately entered into 
its database. 

To address gaps in critical oil and gas measurement abilities, the 
Secretary should: 

* direct BLM and OEMM to ensure that key onshore and offshore 
production verification staff have received initial standardized 
training necessary to effectively carry out their job functions and 
receive ongoing measurement training as needed; and: 

* determine what additional policies or incentives are necessary, if 
any, to attract and retain qualified measurement staff at sufficient 
levels to ensure an effective production verification program. 

To improve the tools available to Interior's production inspection 
staff, the Secretary should: 

* direct BLM to evaluate its commitment to further develop its in-
house software, in light of the functionality, cost, and ease of 
adoption by Interior and industry of commercially available software; 
and present the results of this evaluation to Congress; 

* require all companies purchasing federal leases to immediately 
provide Interior access to oil and gas production data generated by 
electronic flow computers to leave open a range of future options for 
electronic data exchanges with operators; 

* direct BLM to implement a mobile computing solution for its 
inspection and enforcement program to allow staff to spend more time 
in the field conducting inspections and to improve the reliability of 
the inspection data; and: 

* coordinate onshore and offshore inspection staffs' efforts to design 
and implement a mobile computing solution for inspectors in the field, 
while taking into account any unique or specific needs associated with 
onshore versus offshore inspections. 

Agency Comments and Our Evaluation: 

We provided a draft of this report to Interior for review and comment. 
Interior generally agreed with our findings and fully concurred with 
16 of our 19 recommendations and partially concurred with the 
remaining three recommendations. 

With regard to the recommendation in our draft report which stated 
that the Secretary empower the Interior's Production Coordination 
Committee to: (1) increase consistency between offshore and onshore 
measurement regulations, as appropriate; (2) review changes in the 
industry measurement technologies and standards annually that 
Interior's regulations reference to determine whether the related 
regulations should be updated; (3) assess measurement technologies not 
addressed in current regulations and approve variances, as 
appropriate; and (4) develop guidance clarifying when federal oil and 
gas may be commingled and establish standardized measurement methods 
in such a way that production can be adequately measured and verified, 
Interior agreed with our findings and the need for more consistency in 
these decisions. However, Interior expressed uncertainty as to whether 
the Production Coordination Committee (PCC) is the appropriate entity 
to oversee the implementation of the recommendations because it was 
formed as an ad hoc body. While Interior acknowledged that the PCC 
might be the appropriate body, it believed that the Secretary should 
be allowed to make such a determination. We appreciate Interior's 
acknowledgement that the current system, where these authorities are 
dispersed, results in inconsistencies and that some centralization of 
authority is needed. In light of these concerns, we agree that some 
flexibility on determining whether the PCC, or some other body, should 
be empowered with this departmentwide authority is justified. 
Accordingly, we modified our recommendation to allow for the Secretary 
to empower a centralized body comprised of staff from OEMM and BLM to 
carry out the roles we described. 

Interior partially concurred with our recommendation that a 
centralized panel should assess measurement technologies not addressed 
in current regulations and approve variances, as appropriate. Interior 
agreed that it should periodically assess measurement technologies not 
addressed by regulations, and provide staff with guidance when 
technologies are not addressed by its regulations. Interior noted they 
are considering a range of alternatives to provide additional controls 
for providing assurances that variance approvals are subject to 
additional review. We are concerned that continued reliance on 
dispersed authority for variances may not fully address the 
longstanding challenges with ensuring consistency across 
jurisdictional boundaries, and that without a strong framework to 
ensure greater centralization and coordination, such inconsistencies 
may persist. We strongly believe that a centralized panel that has 
shared expertise from both OEMM and BLM would be best suited to 
address new, and increasingly complicated, measurement technologies. 
It is our hope that by empanelling departmentwide expertise with the 
authority to regularly update regulations, fewer variances would be 
needed. We further believe that this same panel could issue 
departmentwide guidance on the uses of new technologies not already 
addressed by regulations, thereby limiting the need for any 
distributed decision making and the related inconsistencies we found 
during the course of our work. Because we are concerned that companies 
may request to use advanced technologies not well understood, and 
because of the limited background measurement knowledge of some 
Interior staff who approve variances, we believe it is important that 
the most knowledgeable people in the department make reasoned 
decisions on their approvals. In deference to Interior's concerns, we 
modified our recommendation to allow for the centralized panel to 
develop departmentwide guidance on the use of technologies that it 
determines to be technically sufficient but not covered by current 
regulations, and that the centralized panel approve variances only in 
cases where such technologies are not addressed by either current 
regulations or departmentwide guidance. 

Finally, Interior partially concurred with two of our recommendations 
addressing IT issues. While Interior agreed with our recommendation 
that BLM conduct a study of its RDAWP program in light of commercially 
available software, it did not agree that the results of the study be 
presented to Congress. Rather, Interior preferred that the results be 
presented only to the Secretary. We believe that Interior could 
provide the results of a study to the Secretary as an interim measure, 
but given this technology's potential to significantly improve 
Interior's production verification efforts, Congress should have clear 
and thorough information available to it when determining how federal 
funds are spent. As such, we made no change. Interior also partially 
agreed with our recommendation that Interior should coordinate its 
onshore and offshore inspection staffs' efforts to implement a mobile 
computing solution for inspections in the field. Interior expressed 
concerns that the different operating environments may necessitate 
different technological solutions for BLM and OEMM staff. We fully 
recognize this issue, and understand that the work environments 
offshore and onshore may lead the agencies to develop different 
solutions. However, we believe that BLM's staff have accumulated a 
large body of knowledge on this issue after its 10-year effort at 
developing a system, and that this knowledge may help OEMM as it works 
toward developing its own mobile computing solution. Accordingly, we 
modified our recommendation to clearly state the BLM and OEMM should 
coordinate the development of a mobile computing solution for their 
staffs, taking into account any unique or specific needs associated 
with onshore versus offshore inspections. This allows each agency the 
flexibility to adopt an approach that best meets the agencies' needs, 
while ensuring that both agencies keep one another informed of their 
progress thereby reducing the possibility of duplicative or 
unnecessary work, and providing the opportunity to take advantage of 
any economies of scale that could exist. Interior also provided 
several technical clarifications, which we incorporated as 
appropriate. Appendix II contains the Department of the Interior's 
comment letter. 

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 of this report 
to the appropriate congressional committees, the Secretary of the 
Interior, the Director of the Bureau of Land Management, the Director 
of the Minerals Management Service, and other interested parties. In 
addition, this report will be available at no charge on the GAO Web 
site at [hyperlink, http://www.gao.gov]. 

If you or your staff members 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 VII. 

Signed by: 

Frank Rusco: 
Director, Natural Resources and Environment: 

List of Requesters: 

The Honorable Jeff Bingaman: 
Chairman: 
Committee on Energy and Natural Resources: 
United States Senate: 

The Honorable Nick J. Rahall, II: 
Chairman: 
Committee on Natural Resources: 
House of Representatives: 

The Honorable Darrell Issa: 
Ranking Member: 
Committee on Oversight and Government Reform: 
House of Representatives: 

The Honorable Carolyn Maloney: 
House of Representatives: 

[End of section] 

Appendix I: Scope and Methodology: 

This report assesses (1) the extent to which the Department of the 
Interior's (Interior) production verification regulations and policies 
provide reasonable assurance that oil and gas are accurately measured; 
(2) the extent to which Interior's offshore and onshore production 
accountability inspection programs consistently set and meet program 
goals and address key factors affecting measurement accuracy; and (3) 
Interior's management of its production verification programs. 

For all three report objectives, we reviewed relevant laws, 
regulations, and Interior, Bureau of Land Management (BLM), and 
Offshore Energy and Minerals Management (OEMM) guidance. We 
interviewed officials in BLM headquarters and officials from ten BLM 
field offices (and their associated state offices), selected using 
nonprobability samples, that provided a range of oil and gas 
operations and jurisdictions.[Footnote 60] Specifically, we visited 
and interviewed officials in three BLM state offices (Colorado, New 
Mexico, and Wyoming) and eight BLM field offices (Glenwood Springs and 
White River in Colorado; Vernal in Utah; Buffalo, Pinedale, and 
Rawlins[Footnote 61] in Wyoming; and Carlsbad[Footnote 62] and 
Farmington in New Mexico) and interviewed by telephone officials in 
two additional state offices (Montana and Utah). 

Additionally, we interviewed officials in four OEMM district offices 
(and their associated regional offices) that provided a range of 
geographic areas and jurisdictions. Specifically, we visited and 
interviewed officials in one OEMM regional office (Gulf of Mexico) and 
one OEMM district office (Lafayette, Louisiana) and interviewed by 
telephone officials in one additional OEMM regional office (Pacific) 
and four additional OEMM district offices (Lake Charles, Lake Jackson, 
New Orleans, and California). In addition, we interviewed 
representatives from 10 state oil and gas agencies, 8 oil and gas 
companies, and 6 regulatory entities overseeing oil and gas 
measurement from other countries about key areas that affect oil and 
gas measurement accuracy and their production verification programs. 
In addition, we collected and analyzed data from both BLM's Automated 
Fluid Minerals Support System (AFMSS) and OEMM's Technical Information 
Management System (TIMS). 

To assess the extent to which Interior's production verification 
regulations and policies provide reasonable assurance that oil and gas 
are accurately measured, we analyzed BLM's and OEMM's laws and 
regulations addressing oil and gas measurement and conducted 
semistructured interviews with key BLM and OEMM production 
verification staff, including BLM petroleum engineers; BLM petroleum 
engineer technicians; BLM production accountability technicians; OEMM 
petroleum engineers; and OEMM inspectors. We also compared several 
aspects of BLM's and OEMM's oil and gas measurement regulations to 
identify areas of variation. We further interviewed OEMM regulatory 
affairs staff and BLM headquarters staff about the processes employed 
by both OEMM and BLM for updating their measurement regulations. 
Additionally, we examined the laws and regulations for providing the 
Secretary of the Interior authority to oversee key areas of oil and 
gas infrastructure, including gas plants, meters, and pipelines; we 
also interviewed Interior officials within its Solicitor's Office to 
obtain their legal assessment of Interior's authority over these 
areas. Finally, we examined BLM and OEMM regulations for how oil and 
gas measurement points are tracked and what criteria the agencies use 
to approve requests to commingle oil or gas production prior to 
measurement. To learn more about tracking measurement points and how 
commingling affects measurement accuracy, our semistructured interview 
guide included questions addressing these topics. During these 
discussions, we used a standard interview protocol, in which 
respondents were asked a standard set of open-ended questions. We 
asked these BLM and OEMM staff to address whether they could identify 
official measurement points and what effect commingling agreements had 
on their ability to accurately verify production. 

To assess the extent to which Interior's offshore and onshore 
production accountability inspection programs consistently set and 
meet program goals and address key factors affecting measurement 
accuracy, we reviewed and analyzed BLM's and OEMM's inspection program 
goals and inspection data and assessed to what extent these programs 
addressed key areas affecting measurement accuracy. To assess the 
extent to which Interior's production accountability inspection 
program consistently sets program goals, we obtained and reviewed 
OEMM's and BLM's inspection strategies and identified areas of 
variation. To assess the extent to which OEMM and BLM were meeting the 
program goals for completing inspections, we requested and analyzed 
production inspection data from both BLM and OEMM. Specifically, we 
collected and analyzed data from BLM's AFMSS to determine the extent 
to which BLM was meeting its statutory and agency goals for completing 
production inspections. Prior GAO work concluded that, because of the 
Cobell litigation which resulted in IT systems shutting down for 
extended periods of time, several BLM field offices were unable to 
accurately identify high priority cases--cases requiring annual 
inspections--because they could not readily access the Minerals 
Management Service's (MMS) monthly production reports to examine 
volumes. Accordingly, we limited our analysis to determining whether 
BLM was meeting its inspection goal for low priority cases--cases 
requiring inspections once every 3 years. We collected and analyzed 
production inspection data for fiscal years 1998 through 2009 to 
determine the frequency with which BLM was inspecting active cases. We 
further collected and analyzed BLM's AFMSS data on measurement 
activities, including meter calibrations and tank gaugings, completed 
during production inspections for fiscal years 2004 and 2008. We 
assessed the reliability of BLM's AFMSS production inspection data by 
(1) performing electronic testing for obvious errors in accuracy and 
completeness; (2) reviewing existing documentation about the data and 
the system that produced them; (3) interviewing agency officials 
knowledgeable about the data; and (4) verifying with agency officials 
a limited sample of our results. We determined that BLM's data 
documenting completed production inspections were sufficiently 
reliable for the purposes of this report. However, based on our 
findings related to production inspection activities and our limited 
file review, we had less confidence in those data. However, we 
determined that the meter calibration and tank gauging measurement 
code data were sufficiently reliable to indicate trends over time, but 
not the actual number of activities completed. 

Additionally, we collected and analyzed data from OEMM's TIMS database 
to determine the extent to which OEMM was meeting its statutory and 
agency goals for witnessing meter calibrations and conducting site 
security inspections for fiscal years 2004 through 2008. We assessed 
the reliability of OEMM's TIMS production inspection data by (1) 
performing electronic testing for obvious errors in accuracy and 
completeness; (2) reviewing existing documentation about the data and 
the system that produced them; and (3) interviewing agency officials 
knowledgeable about the data. We determined that, based on our 
discussions with OEMM officials, only the fiscal year 2008 data was 
sufficiently reliable for our reporting purposes. 

Finally, to identify key areas that affect measurement accuracy not 
currently addressed by Interior's production accountability programs, 
we reviewed technical papers and interviewed representatives from 
industry, independent research organizations, the U.S. National 
Institute of Standards and Technology, the American Petroleum 
Institute, and BLM and OEMM officials responsible for oil and gas 
measurement. For these interviews, we used a standardized interview 
protocol, in which respondents were asked a standard set of open-ended 
questions. We asked these respondents to identify key factors that 
affect measurement accuracy. We then analyzed the extent to which 
BLM's and OEMM's production inspection program addressed the key areas 
affecting measurement uncertainty. 

To evaluate Interior's management of its production verification 
programs, we examined its oversight activities, human capital 
policies, and the extent to which Interior was successful in 
developing key tools to assist its production inspection staff. To 
examine Interior's oversight of its oil and gas production 
verification program, we reviewed documentation on both BLM's and 
OEMM's internal reviews of their production verification programs, 
including the criteria for assigning a risk rating to the programs. We 
also interviewed agency officials about BLM's and OEMM's organizations 
as they relate to key oil and gas production verification staff, 
including the supervisory relationships. To examine internal controls 
related to production inspection documentation, we selected a 
nongeneralizable sample of hard copy BLM files from four of the seven 
field offices we visited. We nonrandomly selected files from fiscal 
years 2004 through 2008 to provide us with a range of measurement 
activities, including meter calibrations, tank gaugings, meter 
provings, and run ticket verifications. Specifically, we reviewed 7 
files in the Vernal, Utah, field office; 9 files in the White River, 
Colorado, field office; 9 files in the Pinedale, Wyoming, field 
office; and 18 files in the Buffalo, Wyoming, field office. We 
reviewed the files for completeness and whether the files supported 
data recorded in BLM's database. In total, we reviewed 43 files out of 
a possible 3,566 available files to select from between fiscal years 
2004 and 2008 for the four field offices we reviewed. Because we did 
not conduct a truly random sample, our analysis does not indicate the 
prevalence or extent of the problems we identified. This applies to 
both the field offices whose files we reviewed, as well as the 28 
field offices whose files we did not review. We selected hard copy 
files based on OEMM data that indicated that the files included site 
security inspections and indications the files might contain 
additional information that would inform our understanding of OEMM's 
overall inspection process. Our nongeneralizable sample included a 
review of 20 out of a total of 562 available hard copy inspection 
files for fiscal years 2007-2008 in those two district offices. 
Because we did not conduct a truly random sample, our analysis does 
not indicate the prevalence or extent of the problems we identified. 
This applies to both the district offices whose files we reviewed, as 
well as the five district offices whose files we did not review. We 
also collected and analyzed BLM AFMSS production inspection data from 
the nine field offices we reviewed for fiscal years 2004 through 2008 
and used BLM's documentation criteria to assess whether data was 
correctly coded. We also examined MMS and BLM staffing and training 
data. Specifically, we collected and analyzed staffing data for the 
nine BLM field offices, four OEMM district offices and two OEMM 
regional offices we reviewed, for fiscal years 2004 through 2009, to 
calculate turnover rates for BLM petroleum engineers, BLM petroleum 
engineer technicians, BLM production accountability technicians, OEMM 
petroleum engineers, and OEMM inspectors. We obtained human capital 
data from Interior's Federal Personnel and Payroll System (FPPS) for 
all nine BLM field offices and for four OEMM district offices. For 
regional OEMM staff performing the work of petroleum engineers, we 
obtained human capital data from regional office officials. We 
assessed the reliability of the FPPS data for BLM and OEMM staff by 
(1) interviewing agency officials knowledgeable about the data, (2) 
working closely with agency officials to identify any data problems, 
and (3) corroborating, on a limited basis, staff names included in the 
FPPS with names of staff on sign-in sheets obtained during our site 
visits and interviews. 

Additionally, we reviewed training records and interviewed BLM and 
OEMM staff about training requirements and course offerings. In 
reviewing BLM's Remote Data Acquisition for Well Production program, 
we collected and analyzed project timelines, budget information, and 
planning documents. We also interviewed BLM project managers; 
representatives from the oil and gas company voluntarily participating 
in the pilot project; and BLM staff in the Glenwood Springs, Colorado, 
field office who had access to the software about the programs' 
effectiveness. To learn about oil and gas production monitoring and 
verification software used in the private sector, we interviewed oil 
and gas company representatives about their software, as well as held 
meetings with oil and gas software manufacturers. To assess BLM's and 
OEMM's efforts to develop a mobile computing option for field 
inspection staff, we analyzed project documentation, interviewed 
project managers, and discussed the potential applications of mobile 
computing with BLM staff from nine field offices and OEMM staff from 
four district offices. 

Finally, in order to develop an informed view of how others involved 
in oil and gas production seek to perform similar functions, we 
examined how states, other countries, and private companies perform 
such functions. In particular, we reviewed state government 
regulations and policies and interviewed regulatory officials from a 
nongeneralizable sample of 10 states selected to represent states with 
the most production in barrels of oil equivalent. These states 
included Alaska, California, Colorado, Kansas, Louisiana, New Mexico, 
Oklahoma, Texas, Utah, and Wyoming. Further, we interviewed 
representatives from eight oil and gas producers, representing a range 
of scales of operations. We also reviewed the oil and gas regulations 
of Canada's Alberta, British Columbia, Newfoundland, and Labrador 
provinces; Mexico; Norway; and the United Kingdom; and interviewed 
their regulatory officials. We selected these countries on the basis 
of several criteria, including the volume of national production. We 
were unsuccessful in our attempts to also obtain information and 
interview officials with relevant expertise from Russia and Kuwait. 

We conducted this performance audit between October 2008 and March 
2010 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. 

[End of section] 

Appendix II: Comments from the Department of the Interior: 

United States Department of the Interior: 
Office Of The Secretary: 
Washington, D.C. 20240: 

February 26, 2010: 

Mr. Frank Rusco: 
Director, Natural Resources and Environment: 
Government Accountability Office: 
441 G Street, N.W. 
Washington, D.C. 20548-001: 

Dear Mr. Rusco: 

Thank you fur the opportunity to review and comment on the Government 
Accountability Office's (GAO) draft report entitled, "Oil, And Gas 
Management: Interior's Oil and Gas Production Verification Elfarts Do 
Not Provide Reasonable Assurance of Accurate Measurement of-Production 
Volumes," (GA0-00-000). The Department of the Interior (Department) 
appreciates the recognition of its efforts currently underway to 
implement the GAO's recommendations. The Department generally agrees 
with the findings and fully concurs with sixteen of the 
recommendations. 

As mentioned in technical comments submitted earlier, four 
recommendations that Interior's Production Coordination Committee take 
actions to address GAO findings should be directed to the Secretary to 
delegate for resolution as appropriate. The Production Coordination 
Committee is an ad-hoc committee established to oversee cross-bureau 
coordination and collaboration and may be the appropriate group to 
address these recommendations. However, the Secretary should make that 
determination. 

The Department partially agrees with the recommendation to "assess 
measurement technologies not addressed in current regulations and 
approve variances, as appropriate." The Department agrees that 
measurement technologies should be periodically assessed and agency 
guidance provided; however, we do not agree that individual onshore 
variances in the use of measurement technology should be approved by 
the PCC or any other headquarters office. These offices are too 
removed from the variance request to make timely and informed 
decisions. The 13LM is currently exploring ways to ensure that the 
approval of variances is properly reviewed and if effective, 
ultimately incorporated into national guidance. Establishing variance 
review teams who can quickly review variance requests, or requiring 
additional review by second-level professionals prior to management 
approval are two of several possible alternatives to resolve the 
issues identified by the GAO. 

The Department would also prefer that GAO's recommendation for the 
Secretary "to direct BLM to evaluate its commitment to further 
developing its in-house software, in light of the functionality, cost 
and ease of adoption by Interior and industry of commercially 
available software, and present the results of this evaluation to 
Congress;" he revised to allow presentation of such an evaluation and 
agency recommendations to the Secretary for further consideration.
The Department partially concurs with the final recommendation, which 
is to coordinate onshore and offshore inspection staffs efforts to 
design and implement a mobile computing solution for inspections in 
the field. The Bureau of Land Management (BLM) and the Minerals 
Management Service (MMS) will continue to assess technology and 
research the use of a mobile computing solution for their inspectors. 
There are technical constraints such as intrinsic safety, weight, and 
space, which must be considered for offshore implementation and may 
require different solutions. 

As noted in the draft report, oil and gas leasing and development 
onshore, managed by the BLM, and offshore, managed by the MMS, operate 
in different regulatory and operational environments. The Department 
is focused on standardizing common agency practices, where 
appropriate, particularly those that make operations more efficient 
and effective. Both the BLM and the MMS arc working to develop new 
regulatory requirements regarding commingling of produced oil and gas 
from different sources that would be appropriate in their respective 
environments. 

The BLM and the MMS are collaborating on many important issues, such 
as the revision of Onshore Order f13, which will require onshore 
operators to include meter identification numbers on monthly 
production reports. Also, the BLM and the MMS are reviewing the 
Department's authority to regulate gas plants that process gas from 
Federal leases, including the requirements and responsibilities for 
approving gas plant meters and conducting inspections of them. This 
will lead to appropriate inspection and enforcement measures by both 
bureaus. 

Technical comments on the draft report have been provided separately. 
If you have any questions about this response or the technical 
comments, please contact LaVanna Stevenson-Harris, BLM Audit Liaison 
Officer. at 202-912-7077, or Andrea Nygren, MMS Audit Liaison Officer. 
at 202-208-4343. 

Sincerely, 

Signed by: 

Wilma A. Lewis: 
Assistant Secretary: 
Land and Minerals Management: 

[End of section] 

Appendix III: Four Examples of the Bureau of Land Management's (BLM) 
Inconsistent Meter Approvals: 

Variances to BLM's measurement regulations are made by the authorized 
officer at the field office level without additional review. As a 
result of this, there have been instances of inconsistent approvals at 
both the field office and state office level. Specifically, we found 
four instances of measurement technologies that had been approved in a 
possibly inconsistent manner: (1) electronic flow computers, (2) Wafer 
V-Cone meters, (3) truck-mounted Coriolis meters, and (4) flow 
conditioners. 

Electronic Flow Computers. BLM's initial approvals of electronic flow 
computers were inconsistent across its field offices, and subsequent 
state policies authorizing their use were issued independently between 
2004 and 2009. According to a BLM official, beginning in the early 
1990s, oil and gas companies began using electronic flow computers-- 
which are not addressed in BLM's 1989 gas measurement regulations--in 
lieu of chart recorders for measuring and recording gas volumes. BLM 
regulations require the authorized officer at the field office to 
ensure that any alternative method of measurement be approved only if 
it was equal to or better than what the regulations addressed. This 
official told us that electronic flow computers were approved with 
both inconsistent conditions of approvals, or had no approvals at all. 
Partly in response to this new technology, BLM wrote and published 
draft gas measurement regulations in the January 1994 Federal Register 
for public comment. These draft regulations, according to a BLM 
official, would have resolved internal inconsistencies with approving 
electronic flow computers by establishing criteria for granting 
approvals. BLM never finalized its revised gas measurement 
regulations. Rather, 10 years later, individual BLM state offices--
beginning in 2004 with Wyoming and ending in July 2009 with Alaska--
separately issued standardized Notices to Lessees establishing 
standards for the use of electronic flow computers. At least one 
standard included in these policies was initially included 14 years 
earlier in the draft 1994 gas measurement regulations. 

Wafer V-Cone Meters. BLM has inconsistently approved Wafer V-Cone 
meters at the field office level. In the mid 1990s, a manufacturer 
developed a meter designed to provide accurate gas measurement with 
significantly shorter lengths of upstream and downstream meter tubes, 
as well as accurately measure gas associated with liquids. The meter-- 
called a Wafer V-Cone meter--is similar to an orifice meter in that it 
measures the differential pressure, along with other parameters used 
in calculating the volumes. The Wafer V-Cone was marketed in areas 
with coal-bed methane production, as coal-bed methane is frequently 
produced with large quantities of water. According to BLM documents, 
prior to 2006, BLM field offices had received and approved requests 
for installing Wafer V-Cone meters on federal leases. However, BLM 
found that the conditions of approvals and the policies for approving 
them were inconsistent between field offices. Later, BLM found that 
Wafer V-Cone meters did not meet the manufacturer's stated 
specifications for accuracy. In 2005, under the direction of BLM, the 
manufacturer contracted with an independent flow measurement lab to 
study the conditions under which Wafer V-Cone meters could accurately 
measure gas. The research showed that the Wafer V-Cone manufacturer's 
stated ranges for operating the meter were not accurate and that, 
while Wafer V-Cones could accurately measure gas, it could only do so 
within a narrow operating range. According to a BLM official, Wafer V-
Cone meters tend to undermeasure gas when high volumes are flowing 
through it and over-measure gas when low volumes are flowing through 
it. In November 2006, BLM issued a memo clarifying the flow conditions 
under which the authorized officer in the field offices could approve 
the Wafer V-Cone. The memo also stated that all previously approved or 
unapproved Wafer V-Cone meters would have to be brought into 
compliance within a "reasonable time frame." During the course of our 
work, we obtained one field office's plan for bringing Wafer V-Cones 
presently measuring federal gas into compliance, which was dated 
January 20, 2009--2 years after the initial BLM policy was put into 
place--which requested that operators bring their Wafer V-Cone meters 
into compliance by May 1, 2009. In this intervening time, according to 
a BLM official, federal gas was inaccurately measured. Some operators 
at the time of our visit in May 2009 had already begun retro-fitting 
the meter runs or replacing Wafer V-Cones with the more traditional 
orifice meters to bring the measurement into compliance. A BLM 
official estimated that the total number of meter reconfigurations 
will be in the thousands, with per-well costs ranging between $500 and 
$1,200. Finally, according to a BLM official, a second round of 
testing on Wafer V-Cones has recently been completed and BLM is 
assessing whether any revisions to its current approval conditions for 
the meters are warranted. 

Truck-Mounted Coriolis Meters. Because BLM does not centrally approve, 
review, or track approved variances to measurement regulations, it was 
unaware if truck-mounted Coriolis meters had been inconsistently 
approved. In December 2008, BLM headquarters issued a memo stating 
that it knew of at least one field office that was allowing a truck-
mounted Coriolis meter to measure federal oil for sales. Since 
Coriolis meters are not positive displacement meters, which are the 
only meters currently addressed by BLM's oil measurement regulations, 
they must receive a variance from the local authorized officer if used 
in that jurisdiction. The BLM memo requested that, in order to 
identify the extent of the use of truck-mounted meters for oil 
measurement, all field offices provide BLM headquarters data on the 
make of the meter, the number of facilities from which oil is loaded, 
the accuracy of specifications, the cost, and the field offices' 
staffs' impression of its performance versus that of manual tank 
gauging. 

Flow Conditioners. BLM's absence of a formal policy addressing flow 
conditioners is leading to inconsistent field office decisions on the 
use of flow conditioners. Flow conditioners--devices placed within the 
upstream portion of the meter run to both stabilize the gas flow and 
allow for a shorter meter run--are not addressed by current gas 
measurement regulations. Accordingly, a variance from the authorized 
officer is necessary prior to installing flow conditioners in the 
field. However, according to BLM officials from all seven field 
offices we visited, operators have installed them without approved 
variances. According to one BLM petroleum engineer, operators may have 
begun using them believing that because BLM allowed a similar 
technology--straightening vanes--that BLM would also allow flow 
conditioners. However, BLM field offices are now taking an 
inconsistent approach for retroactively approving them. For example, 
an official in one field office told us that the office's engineers 
were planning to hold a meeting to discuss a strategy for addressing 
flow conditioners, whereas an official in another field office told us 
that management was not encouraging staff to examine the issue. 
Furthermore, while an official from one BLM field office told us that 
when petroleum engineer technicians identify unauthorized use of flow 
conditioners in the field, they will issue an incident of 
noncompliance, while an official in another field office told us that 
they do not--reasoning that the problem is because of BLM's out-of-
date measurement policies, not the operators' use of flow 
conditioners. To date, BLM does not have a national policy on flow 
conditioners and has not completed any independent testing on flow 
conditioners' effects on measurement, though one BLM official has been 
reviewing data from studies. 

[End of section] 

Appendix IV: Analysis of the Department of the Interior's (Interior) 
Hiring, Training, and Retaining of Critical Measurement Staff: 

Interior has had challenges in hiring, training, and retaining staff 
for many of its critical measurement positions. The following section 
provides additional detail on the Bureau of Land Management's (BLM) 
petroleum engineers, BLM petroleum engineer technicians, BLM 
production accountability technicians, Offshore Energy and Minerals 
Management's (OEMM) petroleum engineers, and OEMM inspectors. 

BLM Petroleum Engineers. BLM has struggled to hire qualified staff to 
fill the petroleum engineer positions in its field offices and to 
provide those it does hire with adequate training to improve their 
knowledge, skills, and abilities; moreover, BLM continues to 
experience high turnover in these positions. According to BLM data 
obtained from BLM's Human Capital office, for the seven field offices 
we reviewed, approximately 60 percent of the staff in the petroleum 
engineer position had a degree in petroleum engineering. Others 
currently serving as petroleum engineers held degrees in other areas, 
including chemical engineering, mechanical engineering, and civil 
engineering. Additionally, one petroleum engineer told us that oil and 
gas measurement is not typically covered in courses in engineering 
school and, thus, engineers did not necessarily have detailed 
backgrounds in oil and gas measurement or production verification 
activities. According to some BLM petroleum engineers, hiring 
qualified staff can be challenging, as both BLM and oil and gas 
companies are hiring from the same pool of applicants, but oil and gas 
companies are able to offer their engineers much higher compensation 
than BLM. 

BLM has not provided consistent and formal training for recently hired 
petroleum engineers, nor is there a requirement for any continuing 
education. According to a BLM training coordinator, BLM has offered 
training to petroleum engineers once since 1999. In 2007, BLM held a 5-
day course that focused on how to process drilling permits and review 
commingling agreements, among other topics. During that course, the 
training coordinator noted, it was clear that some petroleum engineers 
required remedial training in some areas and course instructors 
arranged for several tutorials to be held in the evening to review 
selected engineering concepts. The training coordinator further stated 
that there is a definite need for more petroleum engineer training, 
but no funding had been available for such training in recent years. 
According to the training coordinator, the lack of consistent formal 
training for petroleum engineers could have significant impacts on the 
decisions these petroleum engineers make, limit their ability to 
perform certain functions, and limit their understanding of how their 
decisions can affect overall production accountability within BLM. 
Regarding concerns over decision making, some current petroleum 
engineers noted that they had serious concerns about how prior 
petroleum engineers had made decisions. According to one petroleum 
engineer, because of some past decisions on commingling and allocation 
agreements, it was unlikely production verification staff could 
correctly verify the allocation of volumes, raising uncertainty as to 
whether federal oil and gas were being properly measured and reported. 
Furthermore, one petroleum engineer stated that she was not entirely 
aware of what activities the petroleum engineer technicians are 
conducting in the field, and that taking the petroleum engineer 
technician courses would provide BLM petroleum engineers with greater 
insight into measurement and other issues that are addressed on a 
daily basis. The lack of training for petroleum engineers can also 
limit what functions they may perform. A petroleum engineer told us 
that without the training that petroleum engineer technicians receive, 
petroleum engineers are unable to issue an Incident of Noncompliance 
themselves. Rather, they must work through other staff to have it 
issued. Several petroleum engineers also told us they would benefit 
from ongoing training, in part, to keep up with the rate at which 
technology and processes change in oil and gas fields. 

In addition, BLM has experienced high rates of turnover in the 
petroleum engineer position. We analyzed Interior data from fiscal 
year 2004 through July 2009 for the eight field offices we reviewed 
and found that they had overall turnover rates between 33 percent and 
100 percent. For example, the Buffalo, Wyoming, field office, which 
had an overall turnover rate of 80 percent between fiscal years 2004 
and 2008, employed a total of five petroleum engineers, but during 
that time period, four individuals in that position either left BLM, 
relocated to another field office, or moved to another position within 
BLM. Overall, we found that seven of the eight field offices we 
reviewed had overall turnover rates of 50 percent or greater during 
this time period. According to several petroleum engineers, these high 
turnover rates have resulted in the loss of knowledge, skills, and 
abilities petroleum engineers accumulate through on-the-job training 
and force BLM to repeatedly hire new, often inexperienced petroleum 
engineers (see table 10). 

Table 10: Total Turnover Rates for Petroleum Engineers, Fiscal Years 
2004-2008: 

Field office: Buffalo; 
Turnover percentage: 80; 
Total number of employees in position, FY2004-08: 5; 
Total employees leaving position, FY2004-08: 4; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 1 of 3; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 1 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 1 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 1 of 2; 
Average number of employees in position, FY2004-08: 2. 

Field office: Carlsbad; 
Turnover percentage: 75; 
Total number of employees in position, FY2004-08: 4; 
Total employees leaving position, FY2004-08: 3; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 1 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 1 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 3; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 1 of 3; 
Average number of employees in position, FY2004-08: 2. 

Field office: Farmington; 
Turnover percentage: 50; 
Total number of employees in position, FY2004-08: 8; 
Total employees leaving position, FY2004-08: 4; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 1 of 6; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 6; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 2 of 6; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 5; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 1 of 5; 
Average number of employees in position, FY2004-08: 6. 

Field office: Glenwood Springs; 
Turnover percentage: 50; 
Total number of employees in position, FY2004-08: 2; 
Total employees leaving position, FY2004-08: 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 1 of 1; 
Average number of employees in position, FY2004-08: 1. 

Field office: White River; 
Turnover percentage: 100; 
Total number of employees in position, FY2004-08: 2; 
Total employees leaving position, FY2004-08: 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 1 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 1 of 1; 
Average number of employees in position, FY2004-08: 1. 

Field office: Pinedale; 
Turnover percentage: 100; 
Total number of employees in position, FY2004-08: 2; 
Total employees leaving position, FY2004-08: 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 1 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 1 of 1; 
Average number of employees in position, FY2004-08: 1. 

Field office: Roswell; 
Turnover percentage: 80; 
Total number of employees in position, FY2004-08: 5; 
Total employees leaving position, FY2004-08: 4; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 5; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 5; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 2 of 5; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 3; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 2 of 3; 
Average number of employees in position, FY2004-08: 4. 

Field office: Vernal; 
Turnover percentage: 33; 
Total number of employees in position, FY2004-08: 6; 
Total employees leaving position, FY2004-08: 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 2 of 3; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 0 of 4; 
Average number of employees in position, FY2004-08: 3. 

Source: GAO analysis of Interior data. 

Note: We calculated the total turnover rate by (1) counting the number 
of individual petroleum engineers who separated from BLM, plus those 
who changed locations, plus those who changed from the petroleum 
engineer position to another position within that office; (2) dividing 
that by the number of individual petroleum engineers employed in each 
BLM office from fiscal years 2004 through 2008. For those individuals 
who changed jobs or locations, we did not determine whether they 
changed jobs or locations because of a management decision, as opposed 
to the employees' own decision. 

[End of table] 

Petroleum Engineer Technicians. BLM has also faced challenges in 
hiring, training, and retaining petroleum engineer technicians--staff 
critical for inspecting oil and gas sites and ensuring that oil and 
gas are measured and reported accurately--over the past 5 years. 
According to BLM staff we spoke with, all nine field offices we 
reviewed have had difficulty in recruiting staff for petroleum 
engineer technician positions. Officials in those offices provided 
several reasons, including higher salaries in the private sector 
compared with BLM salaries, and the high cost of living in several of 
the areas where BLM has offices, including Glenwood Springs, Colorado; 
and Pinedale, Wyoming. 

Our review of BLM's petroleum engineer technician training program 
identified several areas where BLM is experiencing challenges. Once 
BLM hires a petroleum engineer technician, BLM has a five-step 
training process for ensuring that staff have the knowledge and skills 
to understand standard industry practices and BLM's regulatory 
requirements. These five steps include the following: 

1. Successful completion of BLM's Oil and Gas Compliance Certification 
School, which includes six 2-week training modules over the course of 
9 months on topics including oil and gas measurement, reviewing 
production records, and technical aspects of drilling and plugging oil 
and gas wells. 

2. On-the-job training developed and conducted by the petroleum 
engineer technician's state office. 

3. Passing a technical review exam, which successfully demonstrates 
the petroleum engineer technician's skills and knowledge in performing 
a field inspection. 

4. Official Certification by the State Director, based on the 
recommendation by the National Lead for Certification and Training. 

5. Maintain basic competency through successfully completing the 
Compliance Certification course once every 5 years. 

However, until fiscal year 2010, BLM was limited in its ability to 
provide timely training, as it was unable to accommodate all petroleum 
engineer technicians who attempted to complete step 1, or enroll in 
the annual training course. This led to a training backlog for newly 
hired staff. A BLM official provided several reasons for not being 
able to accommodate the additional demand, including the need to limit 
the course to 25 people to ensure effective instruction in the field, 
and a lack of instructors for a second session for each of the 
modules. As a result of the backlog, however, petroleum engineer 
technicians who were unable to attend the training remained limited in 
their ability to independently complete production inspections. 
Rather, according to some senior petroleum engineer technicians, they 
had to devote additional time to providing on-the-job training and 
supervising new petroleum engineer technicians, which had the added 
effect of limiting the senior petroleum engineer technicians' ability 
to complete their own inspections. According to a BLM training 
coordinator, fiscal year 2010 is the first time that BLM does not have 
a backlog since this six-module training course has been offered. 
Moreover, because BLM has experienced difficulty in recruiting 
individuals with prior oil and gas training, many newly hired staff 
have been unable to complete the six pass/fail modules. According to 
BLM data, only 61 percent of petroleum engineer technicians initially 
enrolled in the course eventually pass (see table 11). 

Table 11: Overview of Course Petroleum Engineer Technician Attendees 
by Fiscal Years 2003-2008: 

Fiscal year: 2003/2004; 
Number of students selected for module 1: 25; 
Number of students attending module 1: 25; 
Number of students completing modules 1 - 6: 16. 

Fiscal year: 2005; 
Number of students selected for module 1: 25; 
Number of students attending module 1: 25; 
Number of students completing modules 1 - 6: 24. 

Fiscal year: 2006; 
Number of students selected for module 1: 20; 
Number of students attending module 1: 17; 
Number of students completing modules 1 - 6: 13. 

Fiscal year: 2007; 
Number of students selected for module 1: 25; 
Number of students attending module 1: 22; 
Number of students completing modules 1 - 6: 16. 

Fiscal year: 2008; 
Number of students selected for module 1: 25; 
Number of students attending module 1: 25; 
Number of students completing modules 1 - 6: 19[A]. 

Fiscal year: 2009; 
Number of students selected for module 1: 25; 
Number of students attending module 1: 19; 
Number of students completing modules 1 - 6: TBD. 

Fiscal year: Total; 
Number of students selected for module 1: 145; 
Number of students attending module 1: 133; 
Number of students completing modules 1 - 6: 88. 

Fiscal year: Percentage; 
Number of students selected for module 1: 100; 
Number of students attending module 1: 92; 
Number of students completing modules 1 - 6: 61. 

Source: BLM. 

[A] Two students did not pass Modules 2 and/or 3 and will attend 
modules in fiscal year 2009 to raise their scores to a passing grade. 

[End of table] 

Another area where BLM has been unable to meet its training policy 
standards is in ensuring that certified petroleum engineer technicians 
are provided maintenance training. According to BLM's petroleum 
engineer technician Certification Policy, staff must demonstrate their 
continued competence in completing inspections once every 5 years. 
According to a BLM official, this is necessary as industry practices 
and technologies change over time and additional training may be 
necessary. BLM created a course specifically for this purpose; 
however, it has not been offered since 2002, meaning that under BLM's 
own policy, some staff may be out of compliance. 

Finally, turnover of petroleum engineer technician staff at the field 
office level continues to be high. In reviewing BLM data for petroleum 
engineer technicians who completed all six training modules, many of 
the petroleum engineer technicians have either moved on to other 
positions within BLM or left the agency altogether. Specifically, of 
the petroleum engineer technicians who completed the training modules, 
7 percent have taken positions in other areas within BLM and another 
13 percent have left BLM. The combined result of this are that BLM has 
foregone expenditures for recruiting, hiring, and training staff 
approximately 20 percent of the time (see table 12). 

Table 12: Overview of Course Petroleum Engineer Technician Attendees 
by Fiscal Years 2003-2008: 

Fiscal year: 2003/2004; 
Students completing modules 1 - 6: 16; 
Petroleum Engineer Technicians who moved to other BLM jobs: 0; 
Petroleum Engineer Technicians who left BLM after completing modules 
1 - 6: 3. 

Fiscal year: 2005; 
Students completing modules 1 - 6: 24; 
Petroleum Engineer Technicians who moved to other BLM jobs: 1; 
Petroleum Engineer Technicians who left BLM after completing modules 
1 - 6: 4. 

Fiscal year: 2006; 
Students completing modules 1 - 6: 13; 
Petroleum Engineer Technicians who moved to other BLM jobs: 4; 
Petroleum Engineer Technicians who left BLM after completing modules 
1 - 6: 2. 

Fiscal year: 2007; 
Students completing modules 1 - 6: 16; 
Petroleum Engineer Technicians who moved to other BLM jobs: 1; 
Petroleum Engineer Technicians who left BLM after completing modules 
1 - 6: 2. 

Fiscal year: 2008; 
Students completing modules 1 - 6: 19[A]; 
Petroleum Engineer Technicians who moved to other BLM jobs: 0; 
Petroleum Engineer Technicians who left BLM after completing modules 
1 - 6: 0. 

Fiscal year: Total; 
Students completing modules 1 - 6: 88; 
Petroleum Engineer Technicians who moved to other BLM jobs: 6; 
Petroleum Engineer Technicians who left BLM after completing modules 
1 - 6: 11. 

Source: BLM. 

[A] Two students did not pass Modules 2 and/or 3 and will attend 
modules in fiscal year 2009 to raise their scores to a passing grade. 

[End of table] 

Furthermore, our analysis of petroleum engineer technician turnover 
data at the field office level indicates that five of the nine field 
offices we reviewed had an overall turnover rate in excess of 50 
percent between fiscal years 2004 and 2008. Moreover, some of this 
turnover occurred in field offices that have very high oil and gas 
production. For example, the Pinedale, Wyoming, field office which, in 
recent years, has had more production of federal gas than any other 
field office, had an overall turnover rate of 83 percent between 
fiscal years 2004 and 2008. Specifically, during this period, the 
Pinedale, Wyoming, field office employed 12 petroleum engineer 
technicians in that position, but during that time 10 individuals in 
that position either left BLM, relocated to another field office, or 
moved to another position within BLM. According to staff in the 
Pinedale, Wyoming, field office, turnover has added to already 
existing challenges in verifying production (see table 13). 

Table 13: Total Turnover Rates for Petroleum Engineer Technicians, 
Fiscal Years 2004-2008: 

Field office: Buffalo; 
Turnover percentage: 30; 
Total number of employees in position, FY2004-08: 20; 
Total employees leaving position, FY2004-08: 6; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 1 of 12; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 12; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 2 of 13; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 2 of 14; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 1 of 15; 
Average number of employees in position, FY2004-08: 13. 

Field office: Carlsbad; 
Turnover percentage: 47; 
Total number of employees in position, FY2004-08: 19; 
Total employees leaving position, FY2004-08: 9; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 1 of 10; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 1 of 9; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 4 of 9; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 1 of 10; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 2 of 12; 
Average number of employees in position, FY2004-08: 10. 

Field office: Farmington; 
Turnover percentage: 54; 
Total number of employees in position, FY2004-08: 37; 
Total employees leaving position, FY2004-08: 20; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 1 of 22; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 3 of 25; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 7 of 24; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 3 of 21; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 6 of 22; 
Average number of employees in position, FY2004-08: 23. 

Field office: Glenwood Springs; 
Turnover percentage: 67; 
Total number of employees in position, FY2004-08: 3; 
Total employees leaving position, FY2004-08: 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 2 of 3; 
Average number of employees in position, FY2004-08: 3. 

Field office: Hobbs; 
Turnover percentage: 22; 
Total number of employees in position, FY2004-08: 9; 
Total employees leaving position, FY2004-08: 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 2 of 8; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 6; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 6; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 6; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 0 of 6; 
Average number of employees in position, FY2004-08: 6. 

Field office: White River; 
Turnover percentage: 55; 
Total number of employees in position, FY2004-08: 11; 
Total employees leaving position, FY2004-08: 6; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 1 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 2 of 3; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 1 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 2 of 7; 
Average number of employees in position, FY2004-08: 3. 

Field office: Pinedale; 
Turnover percentage: 83; 
Total number of employees in position, FY2004-08: 12; 
Total employees leaving position, FY2004-08: 10; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 1 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 1 of 6; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 2 of 6; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 3 of 5; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 3 of 5; 
Average number of employees in position, FY2004-08: 5. 

Field office: Roswell; 
Turnover percentage: 57; 
Total number of employees in position, FY2004-08: 7; 
Total employees leaving position, FY2004-08: 4; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 4; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 4; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 1 of 4; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 1 of 4; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 2 of 5; 
Average number of employees in position, FY2004-08: 4. 

Field office: Vernal; 
Turnover percentage: 17; 
Total number of employees in position, FY2004-08: 18; 
Total employees leaving position, FY2004-08: 3; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 1 of 13; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 1 of 14; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 1 of 13; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 15; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 0 of 15; 
Average number of employees in position, FY2004-08: 14. 

Source: GAO analysis of Interior data. 

Note: We calculated the total turnover rate by (1) counting the number 
of individual petroleum engineer technicians who separated from BLM, 
plus those who changed locations, plus those who changed from the 
petroleum engineer technician position to another position within that 
office; (2) dividing that by the number of individual petroleum 
engineer technicians employed in each BLM office from fiscal years 
2004 through 2008. For those individuals who changed jobs or 
locations, we did not determine whether they changed jobs or locations 
because of a management decision, as opposed to the employees' own 
decision. 

[End of table] 

BLM Production Accountability Technicians. BLM's production 
accountability technician position has experienced several of the same 
challenges that both petroleum engineer and petroleum engineer 
technician positions have. Production accountability technicians in 
five of the seven field offices we visited generally stated that there 
had been difficulties in hiring production accountability technicians. 
According to these staff, production accountability technicians are 
hired at a pay level below that of petroleum engineer technicians. 
Also, the low salary has made it difficult for BLM to attract people 
with the necessary skills to perform the responsibilities of the job. 

Moreover, BLM has not provided production accountability technicians 
with sufficient training once they are hired. Production 
accountability technician work is technically complicated in that they 
review and corroborate oil and gas quality and volume data from a 
variety of sources. These sources include data generated by electronic 
flow computers, gas analysis reports, calibration reports, and monthly 
production records. Because their reviews are conducted on a case 
level, the total number of wells reviewed may be in the hundreds. 
According to a BLM training coordinator, BLM has offered three 
production accountability technician training sessions over the past 5 
years; one in 2004, another in 2006 and, most recently, in 2009. This 
most recent session was 3 days which, according to the training 
coordinator, was not long enough to cover all the relevant material. 
Additionally, we found during our site visits that in some instances, 
little training or guidance is provided to production accountability 
technicians upon being hired. In one instance, a production 
accountability technician was hired by a field office that previously 
did not have other production accountability technicians. According to 
the production accountability technician, she learned most of her job 
responsibilities on the job with little oversight. In another field 
office, a production accountability technician who had been employed 
for over 3 years and had not yet received formal training reported 
having only recently completed her first gas audit. 

Finally, our analysis of production accountability technicians shows 
that eight of the nine field offices we reviewed had an overall 
turnover rate of 50 percent or more between fiscal years 2004 thorough 
2008. Also, similar to the petroleum engineer and petroleum engineer 
technician turnover rates for the Pinedale, Wyoming, field office, the 
production accountability technician turnover rate in that field 
office was high, as well, with an overall turnover rate of 100 percent 
between fiscal years 2004 and 2008 (see table 14). Specifically, the 
Pinedale, Wyoming, field office employed a total of three production 
accountability technicians in that position; but during that time, 
three individuals in that position either left BLM, relocated to 
another field office, or moved to another position within BLM. 

Table 14: Total Turnover Rates for Production Accountability 
Technicians, Fiscal Years 2004-2008: 

Field office: Buffalo; 
Turnover percentage: 75; 
Total number of employees in position, FY2004-08: 8; 
Total employees leaving position, FY2004-08: 6; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 3 of 4; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 3 of 5; 
Average number of employees in position, FY2004-08: 3. 

Field office: Carlsbad; 
Turnover percentage: 67; 
Total number of employees in position, FY2004-08: 3; 
Total employees leaving position, FY2004-08: 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 1 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 1 of 2; 
Average number of employees in position, FY2004-08: 2. 

Field office: Farmington; 
Turnover percentage: 63; 
Total number of employees in position, FY2004-08: 8; 
Total employees leaving position, FY2004-08: 5; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 3; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 1 of 4; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 3; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 2 of 5; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 2 of 5; 
Average number of employees in position, FY2004-08: 4. 

Field office: Glenwood Springs; 
Turnover percentage: 0; 
Total number of employees in position, FY2004-08: 1; 
Total employees leaving position, FY2004-08: 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 0 of 1; 
Average number of employees in position, FY2004-08: 1. 

Field office: Hobbs; 
Turnover percentage: 50; 
Total number of employees in position, FY2004-08: 4; 
Total employees leaving position, FY2004-08: 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 2 of 4; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 0 of 2; 
Average number of employees in position, FY2004-08: 2. 

Field office: White River; 
Turnover percentage: 50; 
Total number of employees in position, FY2004-08: 2; 
Total employees leaving position, FY2004-08: 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 1 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 0 of 1; 
Average number of employees in position, FY2004-08: 2. 

Field office: Pinedale; 
Turnover percentage: 100; 
Total number of employees in position, FY2004-08: 3; 
Total employees leaving position, FY2004-08: 3; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 1 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 2 of 2; 
Average number of employees in position, FY2004-08: 1. 

Field office: Roswell; 
Turnover percentage: 100; 
Total number of employees in position, FY2004-08: 1; 
Total employees leaving position, FY2004-08: 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 1 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 0 of 0; 
Average number of employees in position, FY2004-08: 1. 

Field office: Vernal; 
Turnover percentage: 50; 
Total number of employees in position, FY2004-08: 2; 
Total employees leaving position, FY2004-08: 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 1 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 2; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 0 of 2; 
Average number of employees in position, FY2004-08: 1. 

Source: GAO analysis of Interior data. 

Note: We calculated the total turnover rate by (1) counting the number 
of individual production accountability technicians who separated from 
BLM, plus those who changed locations, plus those who changed from the 
production accountability technician position to another position 
within that office; (2) dividing that by the number of individual 
production accountability technicians employed in each BLM office from 
fiscal years 2004 through 2008. For those individuals who changed jobs 
or locations, we did not determine whether they changed jobs or 
locations because of a management decision, as opposed to the 
employees' own decision. 

[End of table] 

OEMM Petroleum Engineers. Offshore, OEMM's ability to hire high-
quality applicants for offshore engineers was described as very 
difficult in the past; however, according to one OEMM official, the 
recent economic downturn has increased the number and quality of the 
candidates applying for these positions. However, the official added 
that retaining individuals within the unit who approve measurement 
applications can be challenging, because of the difficult nature of 
the work and the lure of other opportunities within or outside MMS. 

OEMM petroleum engineers who review measurement applications at the 
regional level, according to an OEMM official, are not required to 
receive specific training or to meet a minimum level of proficiency in 
measurement issues. Unlike BLM, OEMM does not have a specific training 
course for its petroleum engineer staff who review applications for 
oil and gas measurement. However, OEMM petroleum engineer staff 
receive individualized training for their work reviewing measurement, 
commingling, and allocation applications from oil and gas producers. 
This training includes classes provided both by OEMM and by external 
vendors, such as universities and private providers of measurement 
training. Training plans are assigned to OEMM engineers on a case-by- 
case basis, and generally fit the needs of the particular engineering 
staff member. In addition, a large portion of OEMM petroleum engineers 
in the Gulf of Mexico region hold degrees in petroleum engineering, 
according to OEMM officials. For the three district offices we 
reviewed that were in the Gulf of Mexico region, production 
measurement applications are reviewed at the regional level by a staff 
of seven petroleum engineers. Of those, five of the seven petroleum 
engineers hold petroleum engineering degrees, either at the Bachelor's 
or the Master's level. In OEMM's Pacific region, geoscientists handle 
measurement approvals. 

According to OEMM officials and human capital data we reviewed, the 
petroleum engineering staff who review offshore measurement do not 
appear to have turnover rates that are impeding program operations. We 
found that the overall turnover rates for petroleum engineers for the 
OEMM Gulf of Mexico and Pacific regional offices--which handle 
measurement approvals at the regional level of the four district 
offices we reviewed--had overall turnover rates of 30 percent or less 
(see table 15). 

Table 15: Total Turnover Rates for OEMM Petroleum Engineers[A] who 
Approve Measurement, Fiscal Years 2004-2008: 

Regional office: Gulf of Mexico region; 
Turnover percentage: 30; 
Total number of employees in position, FY2004-08: 10; 
Total employees leaving position, FY2004-08: 3; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 8; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 1 of 7; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 2 of 6; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 7; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 0 of 7; 
Average number of employees in position, FY2004-08: 7. 

Regional office: Pacific region; 
Turnover percentage: 0; 
Total number of employees in position, FY2004-08: 1; 
Total employees leaving position, FY2004-08: 0; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 1; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 0 of 1; 
Average number of employees in position, FY2004-08: 1. 

Source: GAO analysis of Interior data. 

Note: We calculated the total turnover rate by (1) counting the number 
of individual OEMM petroleum engineers who separated from OEMM, plus 
those who changed locations, plus those who changed from the petroleum 
engineer position to another position within that office; (2) dividing 
that by the number of individual petroleum engineers employed in each 
OEMM office from fiscal years 2004 through 2008. For those individuals 
who changed jobs or locations, we did not determine whether they 
changed jobs or locations because of a management decision, as opposed 
to the employees' own decision. 

[A] In OEMM's Pacific region, geoscientists handle measurement 
approvals. 

[End of table] 

OEMM Inspectors. Inspectors in three of the four district offices we 
spoke with told us hiring new inspectors has been difficult. Not only 
does OEMM compete with the private sector, but there is also a long 
medical testing process for inspectors, which must be passed before 
inspectors can be hired on a permanent basis. This process can take 
from four to six months and involves rigorous training to prepare for 
possible helicopter accidents. This training is considered to be so 
critical that until inspectors successfully complete the medical 
testing--which involves being dropped into a tank of water to simulate 
an accident--they cannot conduct inspections. According to the 
inspectors we spoke with, a few individuals were unable to pass the 
medical testing and were, therefore, delayed prior to becoming 
inspectors. New inspectors who do not pass the test the first time can 
be delayed for several months until they can pass the test. 

Offshore inspectors at OEMM district offices do not have a required, 
standardized measurement training curriculum. While OEMM inspectors 
are required to take a minimum of 60 hours of training every 2 years, 
including courses on safety and other basic issues, they are not 
required to take specialized training in measurement issues. OEMM 
officials in each of the four OEMM district offices we reviewed told 
us that measurement issues are complex, and that new inspectors can 
take from several months to 18 months, to become proficient at 
measurement inspections, depending on their level of prior experience 
and expertise. Some inspectors also told us that there is generally at 
least one inspector in the district office with more knowledge of 
measurement issues than the other inspectors and this inspector would 
be able to assist the others in addressing measurement issues in the 
field, which is done on an informal basis. In discussions with OEMM 
inspectors and officials, we were told that inspectors have the option 
of training in a variety of issues, such as platform operations, 
drilling, completion, and measurement issues. Furthermore, the 
inspectors told us that the training provided to new inspectors should 
depend on their experience. OEMM provides its inspectors with training 
through either on-the-job training, internal courses, or external 
courses, such as those offered by the University of Oklahoma's 
International School of Hydrocarbon Measurement or by private experts. 
Starting in 2009, one OEMM region, the Gulf of Mexico region, 
developed an internal measurement training presentation and gave it to 
inspectors at all district offices in the Gulf of Mexico region. At 
another OEMM regional office, an official told us that inspectors in 
their office do not have a standardized curriculum and that external 
measurement training is offered on an individual basis. Finally, OEMM 
inspectors told us that the time experienced inspectors spend training 
new inspectors reduces the amount of time that otherwise would be 
spent conducting inspections. 

In addition, OEMM does not evaluate the extent of new inspectors' 
knowledge of measurement issues. During our discussions with offshore 
inspectors, we were told that new OEMM inspectors often have 
experience as offshore platform operators, which often involves some 
knowledge of measurement issues. OEMM officials also explained that, 
until the early 1990s, OEMM measurement inspections in the Gulf of 
Mexico region were performed by a measurement inspection team, based 
out of the regional office, of petroleum engineers who review and 
approve measurement systems. However, OEMM delegated the measurement 
inspection responsibilities to the district offices in order to cut 
costs, because the cost of flying to offshore platforms is cheaper and 
less time-intensive from the various district offices than flying from 
the regional office. While many of these measurement inspectors 
continue to be employed in OEMM district offices, OEMM does not 
formally identify the extent to which inspectors are proficient in 
measurement or identify what skills, experience, and training are 
necessary for this proficiency. Without a formal curriculum for 
measurement issues or a formal plan to ensure that inspectors are 
proficient in measurement, OEMM's seven district offices are at risk 
for not having the necessary measurement expertise to identify 
problems on offshore platforms. 

Finally, we conducted an analysis of overall turnover rates for OEMM 
inspection staff for fiscal years 2004 through 2008 for the four 
district offices that we reviewed. This data shows that there was an 
overall turnover rate of between 27 and 44 percent for those 5 years 
(see table 16). For example, the California district office had an 
overall rate of 44 percent turnover, based on the four inspectors who 
left the position over those 5 years; the Lake Jackson, Texas, 
district office had an overall rate of 27 percent turnover. While 
turnover among OEMM inspectors generally occurred at lower rates than 
for BLM offices, offshore inspection staff and supervisors told us 
that turnover can still have a disruptive impact on their work. 
Inspectors in one district office told us that they had lost three 
experienced inspectors in fiscal years 2009 and 2010,[Footnote 63] due 
to significant pay differences between private industry and OEMM. 

Table 16: Total Turnover Rates for OEMM Inspectors, Fiscal Years 2004- 
2008: 

District office: New Orleans; 
Turnover percentage: 42; 
Total number of employees in position, FY2004-08: 19; 
Total employees leaving position, FY2004-08: 8; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 1 of 13; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 13; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 2 of 13; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 3 of 14; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 2 of 13; 
Average number of employees in position, FY2004-08: 13. 

District office: Lake Jackson; 
Turnover percentage: 27; 
Total number of employees in position, FY2004-08: 11; 
Total employees leaving position, FY2004-08: 3; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 9; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 11; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 2 of 11; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 0 of 9; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 1 of 9; 
Average number of employees in position, FY2004-08: 10. 

District office: Lake Charles; 
Turnover percentage: 41; 
Total number of employees in position, FY2004-08: 17; 
Total employees leaving position, FY2004-08: 7; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 2 of 15; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 0 of 13; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 13; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 1 of 13; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 4 of 14; 
Average number of employees in position, FY2004-08: 14. 

District office: California; 
Turnover percentage: 44; 
Total number of employees in position, FY2004-08: 9; 
Total employees leaving position, FY2004-08: 4; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2004: 0 of 7; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2005: 2 of 9; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2006: 0 of 7; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2007: 1 of 7; 
Total employees leaving position, FY2004-08 (of the number employed in 
that fiscal year): 2008: 1 of 6; 
Average number of employees in position, FY2004-08: 7. 

Source: GAO analysis of Interior data. 

Note: We calculated the total turnover rate by (1) counting the number 
of individual inspectors who separated from OEMM, plus those who 
changed locations, plus those who changed from the inspector position 
to another position within that office; (2) dividing that by the 
number of individual inspectors employed in each OEMM district office 
from fiscal years 2004 through 2008. For those individuals who changed 
jobs or locations, we did not determine whether they changed jobs or 
locations because of a management decision, as opposed to the 
employees' own decision. 

[End of table] 

MMS's Liquid Verification System and Gas Verification System Staff. 
MMS added about 10 additional staff to work on its Liquid Verification 
System and Gas Verification System programs in fiscal year 2009, after 
relocating the Gas Verification System discrepancy resolution function 
from the OEMM New Orleans office to its MMS Lakewood, Colorado, 
office. According to a MMS official in charge of the Liquid and Gas 
Verification systems, the training provided to technicians is specific 
to their work, which focuses on resolving detected volume 
discrepancies between reported volumes and the volumes shown on meter 
statements that MMS' computer system automatically detects. In recent 
years, the Liquid and Gas Verification systems have detected a number 
of discrepancies, some of which MMS staff have not yet been able to 
resolve, creating a backlog. Since MMS added additional staff to the 
Liquid and Gas Verification systems program, MMS is showing progress 
in eliminating its backlog of discrepancies and has a goal of 
eliminating this backlog by mid-2010. 

Turnover of Liquid and Gas Verification system program staff for 
fiscal years 2004 through 2008 remained low, however, staffing levels 
were low during this period as well, with one person each assigned to 
the Liquid Verification system and Gas Verification system, 
respectively. The workload for resolving discrepancies identified by 
both systems was greater than the staffing levels were able to 
maintain, and a large backlog of exceptions developed (see table 17). 

Table 17: Number of Liquid Verification System (LVS) and Gas 
Verification System (GVS) analysts, Fiscal Years 2004-2009: 

Fiscal year: 2004; 
LVS analysts: 1; 
GVS analysts: n/a. 

Fiscal year: 2005; 
LVS analysts: 1; 
GVS analysts: 1. 

Fiscal year: 2006; 
LVS analysts: 1; 
GVS analysts: 1. 

Fiscal year: 2007; 
LVS analysts: 1; 
GVS analysts: 1. 

Fiscal year: 2008; 
LVS analysts: 2; 
GVS analysts: 1. 

Fiscal year: 2009; 
LVS analysts: 5; 
GVS analysts: 9. 

Source: GAO analysis of Interior data. 

[End of table] 

[End of section] 

Appendix V: Production Verification Tools and Practices Used by 
Selected States, Companies, and Other Countries: 

We identified four oil and gas production verification tools and 
practices used by other states, private companies, and other countries 
that are not widely employed by Interior, including (1) establishing 
uncertainty thresholds for oil and gas measurement, (2) using 
electronic tools to monitor oil and gas production, (3) requiring 
senior oil and gas company officials to annually attest to the 
controls for oil and gas measurement, and (4) balancing volumes of oil 
and gas systemwide. 

Some Countries Rely on Established Thresholds for Oil and Gas 
Measurement Uncertainty at Critical Points to Ensure Measurement is 
Reasonably Accurate: 

While Interior has established measurement uncertainty limits for 
onshore gas, several countries have established standards for both oil 
and gas, providing greater assurance that oil and gas are accurately 
measured. Measurement uncertainty is determined through a calculation 
that incorporates the uncertainty for each component of the 
measurement system, thereby resulting in an overall uncertainty 
measurement. These components may include the meter, meter 
calibration, and sample gathering and analysis, among others. For 
example, to calculate the measurement uncertainty for gas at a single 
point, accuracies for the meter device, transducers, calibration, 
electronic flow computer calculations, and gas sampling are combined 
to determine the overall uncertainty. So, according to research 
conducted by Alberta, Canada's regulatory agency, a typical 
uncertainty calculation for natural gas at a delivery point might look 
like the following: 

Primary measurement device - gas meter uncertainty: = 1.00%. 

Primary measurement device - gas meter uncertainty: Secondary device- 
(transducer) uncertainty; = 0.5%. 

Primary measurement device - gas meter uncertainty: Secondary device 
calibration; = 0.5%. 

Primary measurement device - gas meter uncertainty: Tertiary device 
(electronic flow computer) uncertainty; = 0.2%. 

Primary measurement device - gas meter uncertainty: Gas Sampling and 
analysis uncertainty; = 1.5%. 

Primary measurement device - gas meter uncertainty: Combined 
uncertainty [A]; = 1.95%. 

[A] The combined uncertainty equals the square root of [(1.0)^2 + 
(0.5)^2 + (0.5)^2 + (0.2)^2 + (1.5)^2] 

[End of table] 

Similarly, uncertainty calculations may be applied to oil. To 
calculate the overall uncertainty for oil, uncertainty data for the 
oil meter, meter proving uncertainty, and the basic sediment and water 
determination are combined to determine the overall uncertainty. Our 
review of selected other regulatory agencies indicate that uncertainty 
standards have been incorporated into their measurement guidance. 
Specifically, four of the other entities we reviewed have measurement 
uncertainty standards (see table 18). 

Table 18: Establishment of Uncertainty Standards in Selected Entities' 
Measurement Guidance: 

Gas: 
OEMM: No; 
BLM: Yes; 
Alberta: Yes; 
Norway: Yes; 
Labrador/Nova Scotia: Yes; 
United Kingdom: Yes. 

Oil: 
OEMM: No; 
BLM: No; 
Alberta: Yes; 
Norway: Yes; 
Labrador/Nova Scotia: Yes; 
United Kingdom: Yes. 

Source: GAO analysis. 

[End of table] 

As we mentioned, Interior has only established uncertainty standards 
for onshore gas measurement. This standard was established through 
Notices to Lessees issued by BLM state offices addressing electronic 
flow computers issued between 2004 and 2008, though the standard was 
referenced in both the 1994 and 1998 gas measurement draft 
regulations. The BLM state policies generally say that, for meters 
measuring more than 100 thousand cubic feet (mcf) per day on a monthly 
basis, the electronic flow computer should be installed, operated, and 
maintained to achieve an overall measurement uncertainty of +/-3 
percent or better. According to a BLM official, BLM arrived at the 3 
percent threshold around 1990, when it reasoned that an appropriate 
threshold would approximate the worst-case conditions allowed for a 
chart recorder under its gas measurement regulations. Until 2006, 
however, BLM staff could not easily enforce this requirement because 
manually calculating uncertainties is technically difficult. It was 
not until BLM--in conjunction with an independent flow measurement 
lab--developed an uncertainty calculator that BLM staff were able to 
more easily calculate gas measurement uncertainties. OEMM has not 
established uncertainty thresholds for oil or gas and staff 
acknowledged that they were not entirely comfortable with the 
application of uncertainty standards at this time. Rather, they rely 
on operators following regulations that should provide reasonably 
accurate measurement--though the accuracy is not specifically 
quantified in any policy or regulation. 

Our review of four other regulatory jurisdictions found that they all 
had established measurement uncertainty standards for both oil and 
gas. Specifically, Norway; the United Kingdom; and the provinces of 
Labrador/Nova Scotia, and Newfoundland, Canada, have adopted a 1 
percent measurement uncertainty for gas produced offshore, whereas 
Alberta, Canada, established a 2 percent measurement uncertainty limit 
for its onshore gas--1 percentage point lower than BLM's standard for 
onshore gas. Additionally, each of the other jurisdictions established 
measurement uncertainty standards for oil--ranging from a low of 0.25 
percent for the United Kingdom and certain Canadian provinces, to a 
high of 1.00 percent for low volume custody transfer points in Alberta 
(see table 19). 

Table 19: Entities Where Percentage Uncertainty Standards Are 
Incorporated Into Measurement Guidance: 

Gas sales/custody transfer point; 
OEMM - offshore: N/A; 
BLM - onshore: 3.00; 
Alberta - onshore: 2.00; 
Norway - offshore: 1.00; 
Labrador/Nova Scotia/Newfoundland-offshore: 1.00; 
United Kingdom - offshore: 1.00. 

Oil sales/custody transfer point - low volume; 
OEMM - offshore: N/A; 
BLM - onshore: N/A; 
Alberta - onshore: 1.00; 
Norway - offshore: 0.30; 
Labrador/Nova Scotia/Newfoundland-offshore: 0.25; 
United Kingdom - offshore: 0.25. 

Oil sales/custody transfer point - high volume; 
OEMM - offshore: N/A; 
BLM - onshore: N/A; 
Alberta - onshore: 0.50; 
Norway - offshore: 0.30; 
Labrador/Nova Scotia/Newfoundland-offshore: 0.25; 
United Kingdom - offshore: N/A. 

Source: GAO analysis. 

[End of table] 

According to documents and discussions with regulatory officials in 
other countries, they adopted measurement uncertainty standards in 
their countries for several reasons. For example, Norwegian regulators 
told us that, previously, they approved all measurement designs, which 
was both time-consuming and costly. In 1991, the regulations were 
revised so that regulatory officials would not approve, but provide 
consent to the company-proposed measurement system. To assist industry 
in determining what types of measurement methods would be sufficient, 
Norway incorporated uncertainty limits for oil and gas measurement. 
Alberta's Energy Resources Conservation Board first established 
uncertainty standards in 1972, when it concluded the need to establish 
production accuracy standards for pooled oil and gas. The standards 
have evolved since they were established, but still require that 
measurement at delivery or sales points meet the highest accuracy 
standards because volumes determined at those points have a direct 
impact on royalty determination. 

Oil and Gas Companies and Some States Use Electronic Tools to Monitor 
Oil and Gas Production: 

Some oil and gas companies and state regulators use electronic tools 
not widely used by Interior for federal leases including: (1) using 
integrated software to monitor production in real time, (2) using 
electronic tools to document inspections in the field, and (3) using 
similar software packages to facilitate audits between purchasers and 
sellers. 

Oil and Gas Companies Use Integrated Software Tools to Monitor Oil and 
Gas Production in Real Time: 

Each of the eight production operators and gas pipeline companies that 
we spoke with during the course of our review use sophisticated 
electronic Supervisory Control and Data Administration (SCADA) systems 
of electronic sensors and computer software to track production and 
transportation of oil and natural gas. According to these company 
officials, SCADA systems enable them to monitor the amount of oil and 
gas produced and transported on a daily, hourly, or an instantaneous 
basis. In addition, SCADA systems provide the ability to be 
automatically alerted if there are problems with production, such as 
an interruption of production or damaged metering equipment. 

SCADA systems typically gather information about oil and gas 
production from electronic sensors in the field that measure oil or 
gas volumes, such as electronic flow computers on gas meters or 
special electronic sensors within oil tanks. They then collect and 
transmit that information through a variety of means, such as direct 
line of sight radio transmissions or transmissions via a cellular 
network. These production data are then compiled by computers at 
production operators' and transporters' offices and compiled by 
computers. The computers that receive this data can then use software 
packages to calculate, display, and report the oil and gas volumes 
that are flowing through various points of measurement. 

SCADA systems allow production companies to carry out their production 
activities more efficiently. For example, onshore wells often produce 
liquid oil and gas that can be sold in association with underground 
wastewater, which must be disposed. While the gas is sent down a 
pipeline, the liquid oil and water are stored in tanks that must be 
drained periodically by trucks; the trucks then deliver the oil to 
refineries and the water to wastewater disposal facilities. Without a 
SCADA monitoring system installed in the oil and wastewater tanks, 
onshore production companies would not know when their tanks are full 
enough to be pumped out, otherwise they would need to send trucks to 
pump the tanks out whether or not they were full--resulting in wasted 
driving time and additional trips. However, if a SCADA system were 
installed in oil and wastewater tanks, companies could wait to send 
trucks until the tanks are full enough to be pumped out. 

SCADA systems allow companies to report their oil and gas measurement 
data more easily. According to company officials we spoke with, 
software packages are available that can receive and interpret SCADA 
data, as well as automatically prepare standard reports on oil and gas 
production and transportation for a variety of time frames--such as 
daily, monthly, and annually. One software maker we spoke with told us 
that their systems are capable of producing reports in a variety of 
electronic formats for use by the entities that receive the reports. 

Some States Use Electronic Tools for Inspections and to Collect and 
Report Production Data: 

Some of the state governments in our review used software tools to 
inspect oil and gas wells in their state.[Footnote 64] For example, 5 
of the 10 states that we reviewed told us that their inspectors used 
software tools on laptop computers to complete their inspections, 
either for production accountability or for other inspections, such as 
checking whether the well is producing, or to ensure that 
environmental damage was not occurring. For example, in New Mexico, 
inspectors enter data into notebook computers in the field when they 
perform inspections, using the state's Risk-Based Data Management 
System (RBDMS).[Footnote 65] This system minimizes the amount of work 
required to capture environmental and groundwater inspection data in 
the field and then uploads that data to other computer systems. 
According to New Mexico state officials, two BLM field offices have 
purchased laptops from New Mexico equipped with the RBDMS system in 
order to evaluate them for use by BLM inspectors. 

Finally, all of the states in our review publicly provided production 
information on the Web for oil and gas production data for wells in 
their state, including wells producing on state, private, and federal 
leases. For example, Louisiana's Strategic Online Natural Resources 
Information System provides geospatial information showing the 
production of wells by location. The Wyoming Oil and Gas Conservation 
Commission provides information about oil and production on its Web 
site,[Footnote 66] which can be retrieved by searching for individual 
oil and gas wells, by geographic location, or by the name of the 
production operator. For more information on the production 
accountability practices of state governments, see appendix VI. 

Companies Audit One Another More Easily by Using Similar Software 
Packages: 

Additionally, oil and gas companies routinely perform audits of 
measurement systems. This process can be completed more quickly and 
easily when they use similar software packages and data formats. 
According to industry officials at six of the eight companies we 
reviewed, audits of oil and gas companies are a common activity in the 
oil and gas industry; for example, many contracts between production 
operators and pipeline transporters include clauses that allow the 
transfer of data and audits. For example, according to an oil and gas 
auditor, oil and gas companies audit the transportation pipeline 
companies that purchase or deliver oil and gas they produce to ensure 
that the volumes they are producing are accurate. In addition, private 
companies can also conduct internal audits of their own systems, which 
provide company management with reasonable assurance that their own 
measurement and production verification systems are working adequately. 

Similar software packages enable many private companies to complete 
their audits more quickly, according to several of the companies we 
spoke with. When companies use similar data and analytical tools, then 
the companies are able to use their software tools to more quickly 
interpret measurement data. For example, officials from one company 
told us that similar software tools allow the companies auditing its 
measurement to share or swap data from meters that measure the same 
flow--so that the auditing company can easily determine whether there 
are any problems. 

In addition, similar software packages allow the audited company to 
provide both the edited data that they reported and the "raw," 
unedited data. Editing raw meter data for reporting purposes is also a 
common part of reporting oil and gas measurement because many 
irregularities are possible in unedited data--such as a temporary 
electronic failure, interruptions in data due to meter servicing, 
intermittent production, or other problems. However, it is common for 
the private companies in our review to make available the raw, 
unedited data for audit and examination by other companies. Although 
there can be many different formats for raw data and because there are 
many different manufacturers of meters and SCADA systems, software 
packages exist that can interpret different data formats. In addition, 
one software company official we spoke with told us that meter 
manufacturers are moving toward a common data format. 

Canada's Alberta Province Requires Senior Oil and Gas Company 
Management to Attest to Internal Controls over Measurement and 
Reporting, with a Goal of Providing Greater Assurance of Measurement 
and Reporting Accuracy: 

Canada's Alberta province Energy Resources Conservation Board (ERCB), 
the agency that regulates Alberta's oil and gas development, has 
recently established a requirement that oil and gas operators' senior 
executives must annually attest to the state of their compliance with 
ERCB measurement and reporting requirements. According to ERCB's 
Enhanced Production Audit Program (EPAP) officials, Alberta's Auditor 
General's 2004 to 2005 annual report raised concerns about ERCB's 
inability to provide an appropriate level of assurance over the 
accuracy of oil and gas measurement and the completeness of oil and 
gas production volumes submitted by operators. According to EPAP 
officials, up to this time, ERCB had relied on conducting substantive 
audits for a small number of facilities each year. According to these 
officials, substantive audits typically include activities such as 
conducting site visits to inspect the measurement infrastructure, 
verifying the meter volume calculations, and reviewing operator-
reported oil and gas production volumes. According to ERCB staff, 
these substantive audits are labor intensive and can take up to 4 
months to complete. Furthermore, EPAP officials told us that ERCB does 
not have sufficient staffing levels to audit a representative sample 
of facilities each year. To respond to the Auditor General's findings, 
ERCB staff studied various approaches that would: (1) not require 
significant additional operating funding; (2) lead to increased levels 
of assurance over ERCB measurement and reporting requirements; and (3) 
lead to increased levels of compliance through continuous improvement. 

ERCB examined several alternatives, including requiring operators to 
conduct sufficient self-audits, before arriving at the adopted 
approach, which requires operators' senior executives to submit an 
annual declaration attesting to the state of their internal controls 
designed to ensure compliance with ERCB measurement and reporting 
requirements. During the development of this program, ERCB held at 
least 16 meetings with oil and gas operator representatives over 8 
months to receive input on the EPAP design and on the wording of the 
new ERCB directive. EPAP officials explained that this approach would 
lead to both continuous improvement in measurement and reporting 
accuracy and would not require additional ERCB operating resources. 
One specific issue EPAP officials expect this approach to address is 
increasing senior executive involvement with addressing measurement 
and reporting issues with operators. EPAP officials told us that 
operator's own production accountants or measurement specialists would 
regularly identify production or measurement reporting problems, but 
operators' senior executives would not take corrective actions. EPAP 
officials said that requiring senior executives to sign a statement 
attesting to the level of assurance over compliance with ERCB 
measurement and reporting requirements, similar to the financial 
requirements included in the Sarbanes-Oxley law, may lead to increased 
interest from senior executives. 

EPAP was to begin the implementation phase in January 2010. This phase 
is scheduled to end in December 2010, according to EPAP officials. The 
implementation phase provides time for operators to evaluate their 
internal controls and to strengthen its controls. Beginning in 2011, 
ERCB will require that all operators in Alberta submit their annual 
declaration. The penalty for not submitting a declaration is to be 
considered a significant noncompliance action. The initial effect of 
this noncompliance is that the operator will receive more scrutiny 
from the ERCB and will likely receive more action items as a result. 
Failure by the operator to respond to action items that arise from 
this scrutiny can result in the operator's name being published on the 
ERCB Web site and, eventually, all future applications being submitted 
by the operator will receive increased levels of review, significantly 
slowing the approval process. According to ERCB staff, this increased 
level of review and the publication of the operators' name on the ERCB 
Web site will have a larger impact on an operator's operations than a 
financial penalty because delays in approving applications, including 
drilling permits, directly affect an operator's revenue stream. 
According to ERCB officials, ERCB will track the performance of EPAP 
by: 

(1) tracking the number of operators who submit their annual 
declarations; 

(2) determining whether field inspectors find more or fewer 
noncompliances at facilities; 

(3) determining whether or not operator data accuracy and completeness 
improve over time; 

(4) determining whether the number of operator voluntary self- 
disclosures increase or decrease over time; and: 

(5) determining whether the number of action items increase or 
decrease over time. 

Many Entities Rely on Volume Balancing to Verify Production: 

Verifying oil and gas volumes through volume balancing is a commonly 
used practice employed by many entities, including private oil and gas 
companies, foreign countries, and some state and federal entities. 
Volume balancing involves totaling the volumes of oil and gas produced 
from a variety of upstream meters and, then, comparing that total to 
the volume measured at a downstream meter. An illustration of system 
balancing is shown below (see figure 11). 

Figure 11: Volume Balancing Diagram Illustrating Gas Volumes Entering 
and Leaving a System: 

[Refer to PDF for image: illustration] 

The illustration depicts gas being routed through different channels 
into the Gas Processing Plant, then to a Pipeline for delivery to 
consumers. 

Source: GAO. 

[End of figure] 

Private Companies Use Balancing to Manage Their Everyday Operations: 

Many private oil and gas companies use volume balancing to manage 
their everyday operations. For example, pipeline transportation 
companies use oil and gas balancing routinely to help manage their 
pipeline networks, enabling them to know how much gas they are 
transporting at any time and giving them the ability to detect leaks 
and other problems. According to officials at the pipeline companies 
we spoke with, balancing can be done on a daily, hourly, or other 
basis; and they are generally able to balance volumes within 1 to 2 
percent. SCADA systems also assist private pipeline companies in 
balancing their volumes. 

Balancing also enables companies to use larger gas meters with greater 
accuracy to balance the volumes of smaller gas meters with less 
accuracy. According to officials at Interior and at private companies, 
smaller gas meters closer to the well head are usually more likely to 
have greater uncertainty because well head flow may be intermittent, 
they may operate at lower pressures, or liquids may be present in the 
gas stream, among other reasons. However, larger meters further 
downstream of the well heads, which measure gas from several streams 
at one time, are generally more accurate because flow is less 
intermittent at higher pressures, and because liquids are more likely 
to be separated out by separation equipment, which is more economical 
to install further downstream. The greater accuracy of meters 
downstream was noted by a BLM official, who told us that gas meters 
closer to the well head generally measure 1 or 2 percent less gas 
volume than meters downstream. 

Volume Balancing Is Used for Production Verification by Foreign 
Governments and Private Companies: 

Foreign countries and private companies also use volume balancing to 
track and verify production. Specifically, representatives we spoke 
with from the United Kingdom and Canada told us that they compare 
reports from local natural gas pipeline companies against reports from 
the larger pipeline companies that deliver the gas to consumers. 
According to officials from the Canadian province of Alberta, their 
ability to access information from several different gas producers and 
private pipeline transportation companies allow them to perform 
balancing. A United Kingdom official told us that their Department of 
Energy and Climate Change compares oil and gas balances monthly in 
order to find discrepancies. The official noted that it was typical to 
find that more liquid oil is measured on well head meters than in the 
larger meters that gather production from several oil wells; they 
noted that the opposite was true for natural gas, where offshore 
meters generally measure less gas than is measured by larger meters 
downstream, usually by a factor of 1 percent or less. 

Interior Offshore and Some State Governments Conduct Volume Balancing 
on a Limited Basis: 

In the United States, Interior conducts one activity for commingled 
offshore oil and gas that amounts to a limited form of volume 
balancing. State government officials in three states told us that 
they incorporate some balancing activities into their audits. OEMM 
requires offshore producers who are commingling their production with 
state oil and gas production to report their production separately in 
a production allocation schedule report. This report enables OEMM to 
compare the volumes that are reported by individual leases against the 
total production of all leases reported by the operators. In addition, 
four U.S. state governments we reviewed also perform volume balancing 
during audits for commingled leases. Generally, state officials told 
us that they do not perform "field-wide" balancing of oil and gas 
systems on a regular basis. 

[End of section] 

Appendix VI: Production Verification and Accountability Practices of 
Selected States as Reported by State Officials: 

We reviewed the production verification practices of the 10 states 
where the most oil and gas is produced on state, federal, and private 
lands; we found that these states use some of the same production 
verification practices as the federal government does offshore and 
onshore. For example, 5 of the 10 states regularly inspected oil and 
gas meters for measurement issues, but of those that do, they 
generally employ fewer inspectors than the federal government. 
However, states do engage in practices that the federal government 
does not; for example, 5 of the states that we reviewed equipped 
inspectors with electronic devices in the field; 2 of these states 
also provided wireless access to these inspectors. Table 20 presents a 
summary of information reported by state officials and documents 
regarding their states' production verification practices. 

Table 20: Summary of Production Verification Practices in 10 States as 
Reported by State Officials: 

Number of state agencies that oversee oil and gas measurement; 
Alaska: 2; 
California: 1; 
Colorado: 2; 
Kansas: 2; 
Louisiana: 2; 
New Mexico: 2; 
Oklahoma: 2; 
Texas: 2; 
Utah: 3; 
Wyoming: 3. 

Point of measurement: 

Policies require operators to report location of royalty meters; 
Alaska: Yes; 
California: No; 
Colorado: No; 
Kansas: a; 
Louisiana: Yes; 
New Mexico: No; 
Oklahoma: Yes; 
Texas: No; 
Utah: No; 
Wyoming: No. 

Inspections: 

Inspectors regularly inspect meters and site security; 
Alaska: Yes; 
California: Yes; 
Colorado: Yes; 
Kansas: No; 
Louisiana: No; 
New Mexico: No; 
Oklahoma: No; 
Texas: Yes; 
Utah: No; 
Wyoming: Yes. 

Inspectors regularly witness tank gauging; 
Alaska: N/A; 
California: Yes; 
Colorado: Yes; 
Kansas: No; 
Louisiana: No; 
New Mexico: No; 
Oklahoma: No; 
Texas: Yes; 
Utah: No; 
Wyoming: No. 

Inspectors regularly witness meter calibrations; 
Alaska: Yes; 
California: Yes; 
Colorado: Yes; 
Kansas: No; 
Louisiana: No; 
New Mexico: No; 
Oklahoma: No; 
Texas: Yes; 
Utah: No; 
Wyoming: No. 

Inspectors regularly inspect orifice plates in gas meters; 
Alaska: Yes; 
California: Yes; 
Colorado: Yes; 
Kansas: No; 
Louisiana: No; 
New Mexico: No; 
Oklahoma: No; 
Texas: Yes; 
Utah: No; 
Wyoming: No. 

Inspectors regularly inspect oil quality sampling (grind out); 
Alaska: Yes; 
California: Yes; 
Colorado: Yes; 
Kansas: No; 
Louisiana: No; 
New Mexico: No; 
Oklahoma: No; 
Texas: Yes; 
Utah: No; 
Wyoming: No. 

Number of regular measurement inspectors (full-time equivalent); 
Alaska: 5; 
California: 1.2; 
Colorado: 1; 
Kansas: 0; 
Louisiana: 0; 
New Mexico: 0; 
Oklahoma: 0; 
Texas: 8; 
Utah: 0; 
Wyoming: 4. 

Approximate number of wells or meters examined per year by State; 
Alaska: 2,000; 
California: 250; 
Colorado: 30-40; 
Kansas: [A]; 
Louisiana: 1-2; 
New Mexico: 0; 
Oklahoma: 0; 
Texas: 3,000; 
Utah: 200; 
Wyoming: 420. 

Inspectors use computer laptops or other handheld electronic devices 
in the field; 
Alaska: Yes; 
California: No; 
Colorado: No; 
Kansas: Yes[B]; 
Louisiana: No; 
New Mexico: Yes[B]; 
Oklahoma: No; 
Texas: Yes; 
Utah: No; 
Wyoming: Yes. 

Inspectors have wireless electronic data access in the field; 
Alaska: No; 
California: No; 
Colorado: No; 
Kansas: Yes[B]; 
Louisiana: No; 
New Mexico: Yes[B]; 
Oklahoma: No; 
Texas: Yes; 
Utah: N/A; 
Wyoming: No. 

Agencies collect real-time production data of oil and gas production 
or gathering; 
Alaska: No; 
California: No; 
Colorado: No; 
Kansas: No; 
Louisiana: No; 
New Mexico: No; 
Oklahoma: No; 
Texas: No; 
Utah: No; 
Wyoming: No. 

Comparison of production reports and royalty payment records; 
Alaska: Yes; 
California: Yes; 
Colorado: Yes; 
Kansas: [A]; 
Louisiana: No; 
New Mexico: Yes; 
Oklahoma: No; 
Texas: Yes; 
Utah: Yes; 
Wyoming: Yes. 

Volume measurement standards: 

Electronic flow computers referenced by regulation; 
Alaska: Yes; 
California: No; 
Colorado: Yes; 
Kansas: No; 
Louisiana: No; 
New Mexico: No; 
Oklahoma: Yes; 
Texas: No; 
Utah: No; 
Wyoming: No. 

Most recent year of most recent API standards cited for oil meters; 
Alaska: 1998; 
California: 1960; 
Colorado: 2005; 
Kansas: N/A; 
Louisiana: 2004; 
New Mexico: N/A; 
Oklahoma: N/A; 
Texas: 2007; 
Utah: N/A; 
Wyoming: 2004. 

Most recent year of most recent API standards cited for gas meters; 
Alaska: 1998; 
California: c.1950; 
Colorado: 2007; 
Kansas: N/A; 
Louisiana: 1936; 
New Mexico: N/A; 
Oklahoma: 2006; 
Texas: N/A; 
Utah: None; 
Wyoming: N/A. 

Source: GAO and state regulatory officials. 

[A] This information was not provided by the state officials we spoke 
with. 

[B] Kansas and New Mexico inspection staff do not regularly conduct 
measurement inspections; however, their health and safety inspectors 
use computer laptops and remote data in the field. 

[End of table] 

[End of section] 

Appendix VII: GAO Contacts and Staff Acknowledgments: 

GAO Contact: 

Frank Rusco (202) 512-3841 or ruscof@gao.gov: 

Staff Acknowledgments: 

In addition to the contact named above, Jon Ludwigson, Assistant 
Director; Lee Carroll; Melinda Cordero; Nancy Crothers; Glenn C. 
Fischer; Cindy Gilbert; and Barbara Timmerman made key contributions 
to this report. Also contributing to this report were Maria Vargas and 
Muriel Forster. 

[End of section] 

Related GAO Products: 

Energy Policy Act of 2005: Greater Clarity Needed to Address Concerns 
with Categorical Exclusions for Oil and Gas Development under Section 
390 of the Act. [hyperlink, http://www.gao.gov/products/GAO-09-872]. 
Washington, D.C.: September 26, 2009. 

Federal Oil And Gas Management: Opportunities Exist to Improve 
Oversight. [hyperlink, http://www.gao.gov/products/GAO-09-1014T]. 
Washington, D.C.: September 16, 2009. 

Royalty-In-Kind Program: MMS Does Not Provide Reasonable Assurance It 
Receives Its Share of Gas; Resulting in Millions in Forgone Revenue. 
[hyperlink, http://www.gao.gov/products/GAO-09-744]. Washington, D.C.: 
August 14, 2009. 

Mineral Revenues: MMS Could Do More to Improve the Accuracy of Key 
Data Used to Collect and Verify Oil and Gas Royalties. [hyperlink, 
http://www.gao.gov/products/GAO-09-549]. Washington, D.C.: July 15, 
2009. 

Strategic Petroleum Reserve: Issues Regarding the Inclusion of Refined 
Petroleum Products as Part of the Strategic Petroleum Reserve. 
[hyperlink, http://www.gao.gov/products/GAO-09-695T]. Washington, 
D.C.: May 12, 2009. 

Oil and Gas Management: Federal Oil and Gas Resource Management and 
Revenue Collection In Need of Stronger Oversight and Comprehensive 
Reassessment. [hyperlink, http://www.gao.gov/products/GAO-09-556T]. 
Washington, D.C.: April 2, 2009. 

Oil and Gas Leasing: Federal Oil and Gas Resource Management and 
Revenue Collection in Need of Comprehensive Reassessment. [hyperlink, 
http://www.gao.gov/products/GAO-09-506T]. Washington, D.C.: March 17, 
2009. 

Department of the Interior, Minerals Management Service: Royalty 
Relief for Deepwater Outer Continental Shelf Oil and Gas Leases--
Conforming Regulations to Court Decision. [hyperlink, 
http://www.gao.gov/products/GAO-09-102R]. Washington, D.C.: October 
21, 2008. 

Oil and Gas Leasing: Interior Could Do More to Encourage Diligent 
Development. [hyperlink, http://www.gao.gov/products/GAO-09-74]. 
Washington, D.C.: October 3, 2008. 

Oil and Gas Royalties: MMS's Oversight of Its Royalty-in-Kind Program 
Can Be Improved through Additional Use of Production Verification Data 
and Enhanced Reporting of Financial Benefits and Costs. [hyperlink, 
http://www.gao.gov/products/GAO-08-942R]. Washington, D.C.: September 
26, 2008. 

Mineral Revenues: Data Management Problems and Reliance on Self- 
Reported Data for Compliance Efforts Put MMS Royalty Collections at 
Risk. [hyperlink, http://www.gao.gov/products/GAO-08-893R]. 
Washington, D.C.: September 12, 2008. 

Oil and Gas Royalties: The Federal System for Collecting Oil and Gas 
Revenues Needs Comprehensive Reassessment. [hyperlink, 
http://www.gao.gov/products/GAO-08-691]. Washington, D.C.: September 
3, 2008. 

Oil and Gas Royalties: Litigation over Royalty Relief Could Cost the 
Federal Government Billions of Dollars. [hyperlink, 
http://www.gao.gov/products/GAO-08-792R]. Washington, D.C.: June 5, 
2008. 

Strategic Petroleum Reserve: Improving the Cost-Effectiveness of 
Filling the Reserve. [hyperlink, 
http://www.gao.gov/products/GAO-08-726T]. Washington, D.C.: April 24, 
2008. 

Mineral Revenues: Data Management Problems and Reliance on Self- 
Reported Data for Compliance Efforts Put MMS Royalty Collections at 
Risk. [hyperlink, http://www.gao.gov/products/GAO-08-560T]. 
Washington, D.C.: March 11, 2008. 

Strategic Petroleum Reserve: Options to Improve the Cost-Effectiveness 
of Filling the Reserve. [hyperlink, 
http://www.gao.gov/products/GAO-08-521T]. Washington, D.C.: February 
26, 2008. 

Oil and Gas Royalties: A Comparison of the Share of Revenue Received 
from Oil and Gas Production by the Federal Government and Other 
Resource Owners. [hyperlink, http://www.gao.gov/products/GAO-07-676R]. 
Washington, D.C.: May 1, 2007. 

Oil and Gas Royalties: Royalty Relief Will Cost the Government 
Billions of Dollars but Uncertainty Over Future Energy Prices and 
Production Levels Make Precise Estimates Impossible at this Time. 
[hyperlink, http://www.gao.gov/products/GAO-07-590R]. Washington, 
D.C.: April 12, 2007. 

Royalties Collection: Ongoing Problems with Interior's Efforts to 
Ensure A Fair Return for Taxpayers Require Attention. [hyperlink, 
http://www.gao.gov/products/GAO-07-682T]. Washington, D.C.: March 28, 
2007. 

Oil and Gas Royalties: Royalty Relief Will Likely Cost the Government 
Billions, but the Final Costs Have Yet to Be Determined. [hyperlink, 
http://www.gao.gov/products/GAO-07-369T]. Washington, D.C.: January 
18, 2007. 

Strategic Petroleum Reserve: Available Oil Can Provide Significant 
Benefits, but Many Factors Should Influence Future Decisions about 
Fill, Use, and Expansion. [hyperlink, 
http://www.gao.gov/products/GAO-06-872]. Washington, D.C.: August 24, 
2006. 

Royalty Revenues: Total Revenues Have Not Increased at the Same Pace 
as Rising Oil and Natural Gas Prices due to Decreasing Production 
Sold. [hyperlink, http://www.gao.gov/products/GAO-06-786R]. 
Washington, D.C.: June 21, 2006. 

Oil and Gas Development: Increased Permitting Activity Has Lessened 
BLM's Ability to Meet Its Environmental Protection Responsibilities. 
[hyperlink, http://www.gao.gov/products/GAO-05-418]. Washington, D.C.: 
June 17, 2005. 

Mineral Revenues: Cost and Revenue Information Needed to Compare 
Different Approaches for Collecting Federal Oil and Gas Royalties. 
[hyperlink, http://www.gao.gov/products/GAO-04-448]. Washington, D.C.: 
April 16, 2004. 

[End of section] 

Footnotes: 

[1] GAO, Data Management Problems and Reliance on Self-Reported Data 
for Compliance Efforts Put MMS Royalty Collections at Risk, 
[hyperlink, http://www.gao.gov/products/GAO-08-893R] (Washington, 
D.C.: Sept. 12, 2008). 

[2] Subcommittee on Royalty Management, Royalty Policy Committee, 
Report to the Royalty Policy Committee: Mineral Revenue Collection 
from Federal and Indian Lands and the Outer Continental Shelf 
(Washington, D.C., 2007). 

[3] The Glenwood Springs, Colorado, field office relocated to Silt, 
Colorado, on September 8, 2009. 

[4] Representatives from the Roswell, New Mexico, BLM field office and 
the Hobbs, New Mexico, BLM field station were included in our 
discussion with Carlsbad, New Mexico, BLM field office staff. 

[5] Pub. L. No. 66-146, 41 Stat. 437 (1920). 

[6] Pub. L. No. 94-258, 90 Stat. 303 (1976). 

[7] 67 Stat. 462 (1953) codified at 43 U.S.C. § 1331 et seq. 

[8] Pub. L. No. 104-58, 109 Stat. 563 (1995). 

[9] MMS's Minerals Revenue Management, a separate directorate from 
OEMM, is responsible for collecting, accounting for, and distributing 
revenues associated with offshore and onshore oil, gas, and mineral 
production from leased federal and Indian lands. This directorate is 
located in Lakewood, Colorado. 

[10] Pub. L. No. 104-113, 110 Stat. 775 (1996). Many regulations 
establish or incorporate technical standards. The National Technology 
Transfer and Advancement Act requires all federal agencies and 
departments to use technical standards developed or adopted by 
voluntary consensus standards bodies unless the agency determines that 
use of such standards is contrary to law or impractical, and provides 
an explanation to the U.S. Office of Management and Budget (OMB) of 
that determination. OMB must report to Congress annually on instances 
in which agencies submitted such explanations for not using voluntary 
consensus standards. 

[11] The representative sample is spun for 5 minutes in a centrifuge 
to determine the water and sediment content of the oil. 

[12] Wafer V-Cone meters work similarly to orifice meters in that they 
measure the differential pressure. While the manufacturer claims that 
wet gas measurement is possible with these meters, this has never been 
substantiated by BLM. Multiphase meters are designed to measure both 
oil and gas simultaneously and are still being studied and improved by 
industry. MMS has allowed the use of multiphase meters for offshore 
measurement in some instances. 

[13] BTU is the amount of heat energy needed to raise the temperature 
of one pound of water by one degree Fahrenheit. 

[14] Both types of samples are drawn by attaching a sample bottle to a 
tap attached to a sample probe in the meter run and collecting a 
volume of gas into a bottle designed for this purpose. 

[15] Pub. L. No. 97-451, 96 Stat. 2447 (1983). 

[16] 30 U.S.C. §1718(c). 

[17] Upon the request of companies, BLM and OEMM can administratively 
combine contiguous federal, state, or private leases into units to 
more efficiently explore and develop an oil or gas reservoir and to 
lessen the surface disruption caused by the building of roads and the 
installation of pipelines and production equipment. 

[18] In OEMM's Pacific region, discrepancies are handled within the 
region, instead of by other MMS staff. 

[19] BLM's regulations are implemented and supplemented by onshore oil 
and gas orders which go through the rule making process and are 
binding on lessees and operators. The use of the term regulations 
throughout this report encompasses orders. 

[20] American Petroleum Institute, Manual of Petroleum Measurement 
Standards, Chapter 14--Natural Gas Fluids Measurement, Section 3-- 
Concentric, Square-Edged Orifice Meters, Part 2--Specification and 
Installation Requirements, Fourth Edition, Washington, D.C., Apr. 
2000; reaffirmed Mar. 2006. 

[21] 30 C.F.R. § 250.198. 

[22] 61 Fed. Reg. 60019 (Nov. 26, 1996). 

[23] Subcommittee Report to the Royalty Policy Committee, Washington, 
D.C., December 2007. 

[24] Office of the Inspector General, U.S Department of the Interior, 
Evaluation of Royalty Recommendations Made to the Department of the 
Interior Fiscal Year 2006 - February 2009, (CR-EV-MOA-0003-2009, 
Washington, D.C., Apr. 2009). 

[25] The term variance is not used by OEMM in the Gulf of Mexico 
region, but OEMM officials told us that it refers to the same process. 

[26] A Coriolis meter is a type of meter that can measure fluids by 
measuring the mass of a fluid traveling past a fixed point per unit 
time. In this particular application, a Coriolis meter was mounted on 
the back of a truck. 

[27] Flow conditioners are devices placed within the upstream portion 
of the meter run to both stabilize the gas flow and allow for a 
shorter meter run, which is necessary for orifice meters to accurately 
measure the gas. 

[28] BLM, Instruction Memorandum No. 2007-022: Policy for Approving 
Variances Allowing the Use of "Wafer V-Cone Meters" at Federal and 
Indian Points of Measurement (Nov. 16, 2006). 

[29] BLM, Instruction Memorandum No. 2009-027: The Feasibility Use of 
Truck Mounted Meters for Oil Measurement Onshore (Nov. 26, 2008). 

[30] 30 C.F.R. § 250.1203(e) 

[31] Under current law, operators are required to have all data 
associated with the meter for six years, and are required to provide 
this information to Interior, regardless of who owns the meters. 30 
U.S.C. §1713. 

[32] Oil and gas pipelines may be subject to oversight by federal and 
state entities, depending on the nature of the pipeline. Interstate 
pipelines are regulated by the U.S. Department of Transportation for 
safety issues, and the U.S. Federal Energy Regulatory Commission for 
the transmission and sale of natural gas for resale in interstate 
commerce. Intrastate pipelines, such as gathering systems located on 
federal leases are, in some instances, overseen to some extent by 
state regulators. 

[33] Measurement points are meter locations which measure oil or gas 
that are reported on the operator-reported monthly production report. 

[34] A commingling request is a request made by the lease operator to 
mix together oil or gas from separate leases prior to measurement. 

[35] Wyoming BLM, Instruction Memorandum No. WY-2003-036: Policy 
Clarification Regarding BLM's Point of Measurement (May 30, 2003). 

[36] [hyperlink, http://www.gao.gov/products/GAO-08-893R]. 

[37] OEMM offices responsible for the outer continental shelf in the 
Pacific and Alaska regions were able to inspect all measurement 
locations; they have a limited number of platforms. 

[38] About 980 out of the approximately 2,900 active royalty meters in 
the Gulf of Mexico are found on measurement locations where more than 
1,000 barrels per day of oil (or, for gas, the energy equivalent) are 
produced. 

[39] Record reviews are a more in-depth and manual version of what 
MMS's Liquid Verification System and Gas Verification System do for 
offshore oil and gas production. 

[40] We did not include data from the White River, Colorado, field 
office, because the Interior Office of the Inspector General is 
currently evaluating the reliability of the inspection data from that 
office. 

[41] An OEMM official told us that for fiscal years prior to 2008, 
OEMM could not precisely identify the number of meters that inspectors 
were required to witness. In addition, for fiscal years prior to 2008, 
the official told us that inspectors may not have recorded every meter 
witnessing. 

[42] In the Cobell class-action lawsuit--concerning the government's 
management of Native American trust funds, a U.S. District Court 
Judge, on December 5, 2001, ordered Interior to disconnect from the 
internet all information technology systems that house or provide 
access to individual Indian trust data. Specifically, Interior's IT 
systems were impacted multiple times since 2001. According to BLM's 
database manager, the shutdown dates were: (1) December 2001 through 
May 2002, (2) June 2003 through September 2003, (3) March 2004, and 
(4) April 2005 through October 2005 for the federal data and August 
2008 for Indian data. 

[43] We did not include the results of our analysis for the White 
River, Colorado, field office as the Interior Office of the Inspector 
General is currently evaluating the reliability of the office's 
inspection data. 

[44] BLM, Instruction Memorandum No. 2009-186: Policy for Verifying 
Heating Value of Gas Produced From Federal and Indian Leases (July 28, 
2009). 

[45] Pub. L. No. 97-255, 96 Stat. 814 (1982). FMFIA was repealed as 
part of the general revisions to Title 31, U.S. Code. The key 
provisions of FMFIA were codified at 31 U.S.C. § 3512 (c), (d). 

[46] GAO, Standards for Internal Control in the Federal Government, 
[hyperlink, http://www.gao.gov/products/GAO/AIMD-00-21.3.1] 
(Washington, D.C.: Nov. 1999). 

[47] OEMM's Gulf of Mexico region oversees approximately 99 percent of 
all offshore production, with the remaining offshore production 
occurring within the Pacific and Alaska regions. 

[48] [hyperlink, http://www.gao.gov/products/GAO/AIMD-00-21.3.1]. 

[49] [hyperlink, http://www.gao.gov/products/GAO/AIMD-00-21.3.1]. 

[50] Some field offices with larger numbers of petroleum engineer 
technicians include supervisory petroleum engineer technician 
positions, which help manage other petroleum engineer technicians and 
are, in turn, evaluated by the field office managers. 

[51] This nongeneralizable sample consisted of a review of 43 out of 
3,556 available files to select from between fiscal years 2004 and 
2008 for the four field offices we reviewed. Because we did not 
conduct a random sample, our analysis does not indicate the prevalence 
or extent of this problem. This applies to both the field offices 
whose files we reviewed, as well as the 26 field offices whose files 
we did not review. 

[52] Because OEMM only retains inspection file hard copies for the two 
most recent fiscal years, we were unable to review files from fiscal 
years 2004-2006. This nongeneralizable sample consisted of a review of 
20 out of a total of 562 available hard copy inspection files for 
fiscal years 2007 and 2008 for the two OEMM district offices we 
reviewed. Because our sample was not random, our analysis does not 
indicate the prevalence or extent of the completeness of the files, or 
the subsequent database documentation, of the OEMM district office 
hard copy files we did not review. This applies to both the two 
district offices whose files we reviewed, as well as the five district 
offices whose files we did not review. 

[53] In OEMM's Pacific region, geoscientists handle measurement 
approvals. 

[54] [hyperlink, http://www.gao.gov/products/GAO/AIMD-00-21.3.1]. 

[55] 30 U.S.C. § 1711(b)(2). 

[56] The Hobbs, New Mexico, field station does not employ any 
petroleum engineers. 

[57] For the purposes of our analysis, we considered turnover to be 
any staff person who left BLM or OEMM, relocated to another BLM field 
office or OEMM district or regional office, or switched positions 
within BLM or OEMM. Additionally, some of the field offices we 
examined had low numbers of staff in the positions we analyzed which 
results in high turnover rates when limited numbers of staff move from 
their positions. 

[58] Pub. L. No. 106-469, 114 Stat. 2029, 2041 (2000), codified at 42 
U.S.C. § 6217. 

[59] Specifically, the judge presiding over the case ordered the 
shutdown of all of Interior's IT systems several times over the course 
of 4 years, delaying many IT projects. 

[60] The results we obtained from these discussions are not 
generalizable to all BLM field offices. 

[61] Our site visit to the Rawlins, Wyoming, BLM field office was a 
scoping visit. We did not administer our semistructured interview 
guide to staff in this office. 

[62] Representatives from the Roswell, New Mexico, BLM field office 
and the Hobbs, New Mexico, BLM field station were included in our 
discussion with Carlsbad, New Mexico, BLM field office staff. 

[63] These inspectors were not counted in Table 16 because our method 
identified these staff as part of the "turnover" count for FY 2009 and 
FY 2010. 

[64] We interviewed state regulatory officials and reviewed oil and 
gas measurement regulations for: Alaska, California, Colorado, Kansas, 
Louisiana, New Mexico, Oklahoma, Texas, Utah, and Wyoming. 

[65] RMDMS is software created by the Ground Water Protection Research 
Foundation, with assistance from the Department of Energy. RBDMS is 
now used by 20 states and is intended to help state agencies to 
improve regulatory decision making, make oil and gas information more 
readily available to industry, increase environmental compliance, and 
reduce the regulatory barriers to oil and gas production. 

[66] The address of the Wyoming Oil and Gas Conservation Commission 
Web site is [hyperlink, http://wogcc.state.wy.us]. 

[End of section] 

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