Input:
	Background

		Life Cycle of Oil and Gas Wells

Oil and gas exploration and production involves disturbing lands in  several ways. For example, when operators drill oil and gas wells, they  typically remove topsoil and construct a well pad, where the drilling rig will  be located. Other equipment on-site can include generators and fuel  tanks. In addition, reserve pits are often constructed to store or dispose of  water, mud, and other materials that are generated during drilling and  production, and roads and access ways are often built to move equipment  to and from the wells.
Once wells cease production, which may occur many decades after they  are drilled, they can become inactive. Inactive wells have the potential to  create physical and environmental hazards if operators do not properly  reclaim them, a process that may involve plugging the well, removing  structures, and reshaping and revegetating the land around the wells. For  example, inactive wells that are not properly plugged can leak methane  into the air or contaminate surface water and groundwater. Well sites that  are not properly reclaimed can contribute to habitat fragmentation and soil  erosion, and equipment left on-site can interfere with agricultural land use  and diminish wildlife habitat.
Costs for well reclamation vary widely and are affected by factors such as  the depth of the well. Although BLM does not estimate reclamation costs  for all wells, it has estimated reclamation costs for thousands of wells  whose operators have filed for bankruptcy. Based on our analysis of  these estimates, we identified two cost scenarios: low-cost wells typically  cost about $20,000 to reclaim, and high-cost wells typically cost about  $145,000 to reclaim.

		BLM’s Bonding Regulations and Policies

As shown in figure 1, BLM regulations or policies outline how BLM is to  initially collect bonds from operators, review bonds, and ultimately return  the bond to the operator or use it to cover costs of reclamation.
Bonds collected from operator. BLM regulations require operators to  submit a bond to ensure compliance with all of the terms and conditions  of the lease, including, but not limited to, paying royalties and reclaiming  wells. BLM regulations generally require operators to have one of the  following types of bond coverage:  individual lease bonds, which cover all of an operator’s wells under  one lease;  statewide bonds, which cover all of an operator’s leases and  operations in one state; or nationwide bonds, which cover all of an operator’s leases and  operations nationwide. (See figure 2.)
BLM can accept two types of bonds: surety bonds and personal bonds. A  surety bond is a third-party guarantee that an operator purchases from a  private insurance company approved by the Department of the Treasury.  The operator pays a premium to the surety company that can vary  depending on various factors, including the amount of the bond and the  assets and financial resources of the operator. If operators fail to reclaim  their wells, the surety company is responsible for paying BLM up to the  amount of the bond to help offset reclamation costs.
A personal bond must be accompanied by one of the following financial  instruments:  certificates of deposit issued by a financial institution whose deposits  are federally insured, granting the Secretary of the Interior full  authority to redeem it in case of default in the performance of the  terms and conditions of the lease;  cashier’s checks; negotiable Treasury securities, including U.S. Treasury notes or  bonds, with conveyance to the Secretary of the Interior of full authority  to sell the security in case of default in the performance of the lease’s  terms and conditions; or  irrevocable letters of credit that are issued for a specific term by a  financial institution whose deposits are federally insured and meet  certain conditions and that identify the Secretary of the Interior as sole  payee with full authority to demand immediate payment in case of  default in the performance of the lease’s terms and conditions.
BLM bond reviews. BLM regulations provide flexibility to increase bonds  above minimums and require increases above minimum amounts if  operators meet certain criteria. Specifically, BLM regulations require BLM  to increase the bond amount when an operator who applies for a new  drilling permit had previously failed to reclaim a well in a timely manner.  For such an operator, BLM must require a bond in an amount equal to its  cost estimate for reclaiming the new well if BLM’s cost estimate is higher  than the regulatory minimum amount. BLM regulations also authorize  increases in the bond amount—not to exceed the estimated cost of  reclamation and any royalties or penalties owed—whenever the  authorized officer determines that the operator poses a risk due to factors  such as that the expected reclamation costs exceed the present bond.
In response to our previous recommendation in 2011 that BLM develop a  comprehensive strategy to revise its bond adequacy review policy to  more clearly define terms and conditions that warrant a bond increase,  BLM issued a bond adequacy review policy in July 2013, Instruction  Memorandum 2013-151. The policy contained directives for conducting  reviews when bonds meet certain criteria. Specifically, the 2013 bond  adequacy review policy called for field offices to, among other things,  review each bond at least every 5 years to determine whether the bond  value appropriately reflected the level of potential risk posed by the  operator. If it did not, authorized officers were to propose an increase (or  decrease) in the bond value.
In November 2018, BLM issued a revised bond adequacy review policy,  Instruction Memorandum 2019-014, which supersedes the 2013 policy.  The 2018 policy continues to call for field offices to review each bond at  least every 5 years, but it revised the point system worksheet that field  offices are to use when determining whether a bond increase (or  decrease) is warranted. Also, in response to our 2018 recommendation  that BLM ensure that the reviews of nationwide and statewide bonds  reflect the overall risk presented by operators, the 2018 policy calls for  additional coordination between BLM headquarters, state offices, and  field offices when reviewing nationwide and statewide bonds.
BLM returns or uses bond. If operators reclaim their wells, BLM returns  the bond to the operator. Many decades may pass between when BLM  collects a bond and when it is returned. If operators do not reclaim their  wells, BLM may redeem the certificate of deposit, cash the check, sell the  security, or make a demand on the letter of credit to pay the reclamation  costs. Liability for reclaiming a well on onshore federal lands can fall to  either the lease holder or the operator, and BLM may also hold past  owners or operators liable. The liability for past owners or operators  extends only to reclamation obligations that accrued before BLM  approved the transfer of their lease to a subsequent lessee. They are not  liable for reclamation and lease obligations incurred after that transfer is  approved.

	Average Bond Values Per Well Were Slightly Lower in 2018 as Compared to 2008

Based on our review of BLM data, the value of bonds held by BLM for oil  and gas operations on a per-well basis were slightly lower in 2018 as  compared to 2008. Although the total value of bonds held by BLM for oil  and gas operations was higher in 2018 than in 2008 (about $204 million  compared to about $188 million, in 2018 dollars), the average bond value  per well was slightly lower because the number of wells on federal land  was also higher in 2018 than in 2008 (96,199 wells compared to 85,330).  Specifically, in 2008, BLM held bonds worth an average of $2,207 per  well in 2018 dollars.23,  BLM held bonds worth an average of $2,122 per  well in 2018, a decrease of 3.9 percent as compared to 2008 (see table  1).
BLM bonds do not typically cover an individual well; however, we calculated the average  bond value on a per-well basis (bond amount divided by the number of wells covered by  the bond) to compare the value over time adjusted for the increased number of wells.  When reporting on all wells, we calculated the average bond value per well as the  aggregate value of all BLM bonds divided by the total number of producible well bores.  Appendix I provides additional information on our scope and methodology. category for bonds that were linked to wells in the data. We found that,  on average, as of 2018 an individual lease bond covered about 10 wells,  a statewide bond covered about 49 wells, and a nationwide bond covered  374 wells. However, some bonds cover more than the typical number of  wells and some fewer. As of 2018, individual lease bonds had the highest  average bond value per well at $2,691, and nationwide bonds had the  lowest average bond per well value at $890. Statewide bonds had an  average bond value per well of $1,592.
The share of the total value of bonds held by BLM that are individual  lease, statewide, or nationwide bonds differed in 2018 from 2008 (see  Figure 3). The share of individual lease bonds was slightly higher in 2018  as compared to 2008 (about 8 percent in 2008 and about 9 percent in  2018). In 2008, statewide bonds represented about 80 percent  (approximately $130 million) of the total value of bonds. In 2018,  statewide bonds represented about 59 percent of total bond value  (approximately $120 million), but this category still represented the largest  share of total bond value. In contrast, nationwide bonds were a lower  share of total bond value in 2008 (about 6 percent, approximately $10.2  million) than in 2018 (30 percent, approximately $61.8 million).
BLM officials told us that changes in the composition of the oil and gas  industry may have contributed to these changes in the composition of  bonds. In particular, officials said some larger companies may have  expanded their operations in recent years, sometimes acquiring smaller  companies. Large companies with expansive operations are more likely  than small companies to have nationwide bonds because such bonds can  cover operations in multiple states, which statewide and individual lease  bonds do not. Therefore, an industry shift to larger companies would tend  to increase the share of nationwide bonds.

	Bonds Held by BLM Are Insufficient to Prevent Orphaned Wells

		Bonds Do Not Provide Sufficient Financial Assurance to Prevent Orphaned Wells

Bonds do not provide sufficient financial assurance to prevent orphaned  wells for several reasons. First, BLM has identified new orphaned wells— wells whose bonds were not sufficient to pay for needed reclamation  when operators or other parties failed to reclaim them. As we reported in  May 2018, BLM does not track the number of orphaned wells over time  and so cannot identify how many wells became orphaned over specific  time frames. However, our analyses of BLM’s orphaned well lists from  different years have shown that BLM has continued to identify new  orphaned wells since 2009. We reported in January 2010 that BLM  identified 144 orphaned wells in 2009. Then, in May 2018, we reported  that BLM identified 219 orphaned wells in July 2017—an increase of 75  orphaned wells. In April 2019, BLM provided a list of 296 orphaned  wells that included 89 new wells that were not identified on the July 2017  list.
Bonds are not sufficient to prevent orphaned wells in part because they  do not reflect full reclamation costs for the wells they cover. Bonds that  are high enough to cover all reclamation costs provide complete financial  assurance to prevent orphaned wells because, in the event that an  operator does not reclaim its wells, BLM can use the bond to pay for  reclamation. On the other hand, bonds that are less than reclamation  costs may not create an incentive for operators to promptly reclaim wells  after operations cease because it costs more to reclaim the wells than the  operator could collect from its bond. We analyzed bonds that are linked to  wells in BLM’s data, and found that most of these bonds would not cover  reclamation costs for their wells. Specifically, we compared the average  bond coverage available for these wells to the two cost scenarios we  described above. About 84 percent of these bonds—covering 99.5  percent of these wells—would not fully cover reclamation costs under a  low-cost scenario (these bonds have an average value per well of less  than $20,000). Less than 1 percent of bonds—covering less than 0.01  percent of these wells—would be sufficient to reclaim all the wells they  cover if they were high cost (these bonds have an average value per well  of $145,000 or more). The remaining bonds—about 16 percent—have  average bond values per well of between $20,000 and less than  $145,000.
The majority of bond values do not reflect reclamation costs in large part  because most bonds—82 percent—remain at their regulatory minimum  values. These regulatory minimums are not reflective of reclamation  costs for a number of reasons:
Regulatory bond minimums have not been adjusted since the 1950s  and 1960s to account for inflation. As shown in figure 4, when  adjusted to 2018 dollars, the $10,000 individual lease bond minimum  would be about $66,000, the $25,000 statewide bond minimum would  be about $198,000, and the $150,000 nationwide bond minimum  would be about $1,187,000.
Bond minimums are based on the bond category and do not adjust  with the number of wells they cover, which can vary greatly. According  to BLM’s data, in 2018 the number of wells covered by a single bond  ranged from one well to 6,654 wells. On average, a single bond  covered about 68 wells. As wells are added to a bond, the total  associated reclamation cost increases even if the bond value does  not. A bond that increases with each additional well it covers and then  decreases as wells are reclaimed could increase the financial  incentive for operators to reclaim their wells in a timely manner. This  is because operators would have to contribute additional bond value  or would recover some bond value when they add or reclaim a well,  respectively. Currently, bond minimums do not automatically adjust in  this manner and therefore provide limited financial incentives for an  operator to reclaim wells in a timely manner.
Bond minimums do not reflect characteristics of individual wells such  as depth or location, but such characteristics can affect reclamation  costs, according to BLM officials. Wells are being drilled deeper than  in the past; in 1950, well depth averaged about 3,700 feet, and in  2008, it averaged about 6,000 feet. Newer wells may be drilled 10,000  feet vertically. Officials from one BLM field office told us they assume  a cost of $10 per foot of well depth to plug a well, so as wells are  drilled deeper, plugging costs typically increase proportionally.  Additionally, the location of some wells makes them more expensive  to reclaim. For example, BLM officials told us about several wells that  may cost three times more to reclaim than other nearby wells because  they are located in the middle of a river, making them hard to reach.
In addition to BLM having identified orphaned wells over the last decade,  we identified inactive wells at increased risk of becoming orphaned and  found their bonds are often not sufficient to reclaim the wells. Our  analysis of BLM bond value data and Office of Natural Resources  Revenue production data showed a significant number of inactive wells  remain unplugged and could be at increased risk of becoming orphaned.  Specifically, we identified 2,294 wells that may be at increased risk of  becoming orphaned because they have not produced since June 2008  and have not been reclaimed. Further, for a majority of these at-risk  wells, their bonds are too low to cover typical reclamation costs for just  these at-risk wells. Our analysis of oil and gas production data showed these wells have not produced oil or gas or been used in other ways,  such as serving as injection wells, since at least June 2008, when oil and  gas prices were at or near record highs. Given that the Energy  Information Administration projects oil and natural gas prices will remain  at levels significantly below the 2008 highs through 2050, it is unlikely  price will motivate operators to reopen these wells. Some of these wells  have been inactive for far longer. Since these at-risk wells are unlikely  to produce again, an operator bankruptcy could lead to orphaned wells  unless bonds are adequate to reclaim them. If the number of at-risk wells  is multiplied by our low-cost reclamation scenario of $20,000, it implies a  cost of about $46 million to reclaim these wells. If the number of these  wells is multiplied by our high-cost reclamation scenario of $145,000, it  implies a cost of about $333 million. When we further analyzed the  available bonds for these at-risk wells, we found that most of these wells  (about 77 percent) had bonds that would be too low to fully reclaim the at- risk wells under our low-cost scenario. More than 97 percent of these at- risk wells have bonds that would not fully reclaim the wells under our  high-cost scenario.
BLM has a policy for reviewing the adequacy of bonds but has not been  able to consistently secure bond increases when needed, and this policy  has not resulted in bonds that would be adequate to reclaim most wells.  BLM’s bond adequacy review policy calls for field office staff to review oil  and gas bonds at least every 5 years to determine whether the bond  amount appropriately reflects the level of potential risk posed by the  operator. However, according to BLM documentation, its offices did not  secure about 84 percent of the proposed bond increases in fiscal years  2016 and 2017. BLM officials at one field office and one state office noted  it is difficult to secure increases from bond reviews when firms are already  in difficult financial situations. In November 2018, BLM updated its bond  adequacy review policy and called for the agency to focus on securing  bond increases from operators that show the highest risk factors. BLM’s  updated policy more explicitly lays out steps to secure bond increases,  including that BLM should not approve new applications to drill from an  operator while waiting for a bond increase. The new policy also gives  BLM officials discretion to not pursue a bond increase after considering  other priorities demanding staff time and workload. It is unclear whether  the update will improve BLM’s ability to secure bond increases, as it may  not address the underlying challenge of attempting to increase bonds  from operators who are already in a difficult financial position.
While BLM’s federal oil and gas bond minimums do not sufficiently reflect  the costs of well reclamation, requirements for bond amounts for other  federal mining and energy development activities account for potential  reclamation costs to some extent. For example, for bonds for surface coal  mining and hardrock mining on federal lands, the Department of the  Interior requires bond amounts based on the full estimated cost of  reclamation. For grants of federal rights-of-way for wind and solar  energy development in designated leasing areas, BLM requires bonds  based on a minimum amount per wind turbine or per acre of solar. For  such grants in all other areas, the bonds are based on the estimated cost  of reclamation but cannot be less than the per-turbine or per-acre  amounts previously mentioned.
Additionally, some states have minimum bond requirements for oil and  gas wells on lands in the state that, unlike federal bond minimums, adjust  with the number of wells they cover or the characteristics of the wells, or  both. For example, Texas and Louisiana offer operators with wells on  lands in those states the choice of a bond based on total well depth or  based on the number of wells. Specifically, the Texas Railroad  Commission lets operators choose bonds based on either the total depth  of all wells on lands in the state multiplied by $2 per foot, or minimums  based on the number of wells covered. If operators choose the latter, the  bond for 0 to 10 wells is $25,000; the bond for 11 to 99 wells is $50,000;  and the bond for 100 or more wells is $250,000. In Louisiana, the Office  of Conservation offers operators with wells on lands in the state the  choice of a bond based on total well depth or based on the number of  wells. Louisiana further specifies a multiplier that varies depending on the  total depth of the well. For example, the bond calculation is $2 per foot for  wells less than 3,000 feet deep, $5 per foot for wells from 3,001 to 10,000  feet deep, and $4 per foot for wells 10,001 feet deep or deeper.  Operators in Louisiana can alternatively choose to follow a system based  on number of wells, with a minimum bond for 10 or fewer wells set at  $50,000, a minimum bond for 11 to 99 wells set at $250,000, and a  minimum bond for 100 or more wells set at $500,000. Pennsylvania’s  Department of Environmental Protection requires bonds for  unconventional wells that vary based on the number of wells and well  bore length.
The Mineral Leasing Act of 1920, as amended, requires federal  regulations to ensure that an adequate bond is established before  operators begin surface-disturbing activities on any lease, to ensure  complete and timely reclamation of the lease tract as well as land and  surface waters adversely affected by lease operations. The Mineral  Leasing Act of 1920 does not require that BLM set bonds at full  reclamation costs. However, the gap between expected reclamation costs  and minimum bond amounts has grown over time because the minimums  have not been adjusted since they were established in the 1950s and  1960s, whereas reclamation costs have increased due to inflation and the  changing characteristics of wells being drilled. In the absence of bond  levels that more closely reflect expected reclamation costs, such as by  increasing regulatory minimums and incorporating consideration of the  number of wells on each bond and their characteristics, BLM will continue  to face risks that its bonds will not provide sufficient financial assurance to  prevent orphaned wells. In particular, adjusting bond minimums so that  bonds more closely reflect expected reclamation costs up front could help  decrease the need for bond increases later when companies are  potentially in financial distress.

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

In addition to fulfilling its responsibility to prevent new orphaned wells, it  falls to BLM to reclaim wells that are currently orphaned, and BLM has  encountered challenges in doing so. We reported in May 2018 that 13  BLM field offices identified about $46.2 million in estimated potential  reclamation costs associated with orphaned wells and with inactive wells  that officials deemed to be at risk of becoming orphaned. There is also a  risk more wells will become orphaned in coming years, as we described  above. Based on the most recent orphaned well lists we received from  BLM, 51 wells that BLM identified in 2009 as orphaned had not been  reclaimed as of April 2019.
The Energy Policy Act of 2005 (EPAct 2005) directs Interior to establish a  program that, among other things, provides for the identification and  recovery of reclamation costs from persons or other entities currently  providing a bond or other financial assurance for an oil or gas well that is  orphaned, abandoned, or idled. One way in which BLM may be able to  accomplish this is through the imposition of user fees. In 2008, we found  that well-designed user fees can reduce the burden on taxpayers to  finance those portions of activities that provide benefits to identifiable  users. Further, according to Office of Management and Budget  guidance, it may be appropriate for an agency to request authority to  retain the fee revenue if the user fees offset the expenses of a service  that is intended to be self-sustaining.
The volume of drilling applications and inactive wells provide an  opportunity to fund reclamation costs. According to BLM data, the agency  processes more than 3,500 applications to drill each year, on average,  and has over 14,000 inactive wells. Based on our calculations, a separate  fee of about $1,300 charged at the time a drilling application is submitted  (in addition to the current drilling application filing fee, which is $10,050),  or an annual fee of less than $350 for inactive wells could generate  enough revenue to cover, in a little over a decade, the entire $46 million  potential reclamation costs field offices identified to us. In commenting  on a draft of this report, BLM stated that it does not have the authority to  seek or collect fees from lease operators to reclaim orphaned wells.   Developing a mechanism to obtain funds from operators to cover the  costs of reclamation, consistent with EPAct 2005, could help ensure that  BLM can completely and timely reclaim wells without using taxpayer  dollars.
Other federal programs, including other BLM programs, collect fees from  users to fund reclamation activities. For example, the federal government  collects fees from mining companies to reclaim abandoned mines.  Specifically, the federal abandoned mine reclamation program is funded  in part by fees on coal production. We reported in March 2018 that the  program had spent about $3.9 billion to reclaim abandoned mine lands  since the program’s creation in 1977.
Additionally, some states with oil and gas development have dedicated  funds for reclaiming orphaned wells. In Wyoming, the state’s Oil and Gas  Conservation Commission’s Orphan Well Program reclaims orphaned  wells on state or private lands for which bonds and operator liability are  unavailable or insufficient to fund reclamation. The program is funded  through a conservation tax assessed on the sale of oil and natural gas  produced in Wyoming. Through this program, the Wyoming Oil and Gas  Conservation Commission has reclaimed approximately 2,215 wells since  2014, according to a Commission official. Similarly, in Arkansas,  operators make annual payments to its abandoned well plugging fund  based on the number of wells and permits they have, on a sliding scale.  For example, at the low end, operators with one to five wells or permits  pay $100 per well, and at the high end, operators with over 300 wells or  permits pay $4,000 per operator. The Arkansas fund was used to  reclaim 136 wells in fiscal years 2016 through 2018, according to an  official with the state’s Oil and Gas Commission. Virginia’s Orphaned Well  Fund is funded through a $200 surcharge on each permit application. The  fund is administered by the Virginia Division of Gas and Oil, which  prioritizes wells to reclaim according to their condition and potential threat  to public safety and the environment.

	Conclusions

BLM oversees private entities operating thousands of oil and gas wells on  leased federal lands and has taken steps over the years to strengthen its  management of the potential liability that oil and gas operations represent  should operators not fully reclaim wells and return lands to their original  condition when production ceases. For example, the agency’s 2013 bond  adequacy review policy outlined how bonds were to be reviewed every 5  years and bond amounts adjusted depending on risks presented by  operators. However, we found average bond values were slightly lower in  2018 as compared to 2008 and BLM has not obtained bond increases for  the majority of instances in which its reviews identify that increases are  needed. Instead, most bonds are at their regulatory minimum values,  which are not sufficient to cover reclamation costs incurred by BLM.  Without adjusting bond levels to more closely reflect expected  reclamation costs—such as by considering the effects of inflation, the  number of wells covered by a single bond, and the characteristics of  those wells—BLM faces ongoing risks that not all wells will be completely  and timely reclaimed, resulting in additional orphaned wells.
Further, BLM faces a backlog of orphaned wells to reclaim—with 51  dating back at least 10 years. Unlike some other federal and state  programs that obtain funds from industry through fees or dedicated funds,  BLM does not do so for reclaiming orphaned wells. According to BLM, it  does not have the authority to seek or collect fees from lease operators to  reclaim orphaned wells. Authorizing and requiring the implementation of a  mechanism to obtain funds from oil and gas operators to cover the costs  of reclamation could help ensure BLM can completely and timely reclaim  wells.

	Matter for Congressional Consideration

Congress should consider giving BLM the authority to obtain funds from  operators to reclaim orphaned wells, and requiring BLM to implement a  mechanism to obtain sufficient funds from operators for reclaiming  orphaned wells. (Matter for Consideration 1)

	Recommendation for Executive Action

The Director of BLM should take steps to adjust bond levels to more  closely reflect expected reclamation costs, such as by increasing  regulatory minimums to reflect inflation and incorporating consideration of  the number of wells on each bond and their characteristics.   (Recommendation 1)

	Agency Comments and Our Evaluation

We provided a draft of this product to BLM for comment. In its written  comments, reproduced in appendix II, BLM concurred with the  recommendation. BLM stated that it is committed to ensuring that its field  offices continue to review oil and gas bonds at least every 5 years, or  earlier when warranted, and noted its November 2018 Instruction  Memorandum 2019-014 updated its bond review policy. BLM further  stated that, while the adjustment of bond values may not reflect the  inflation index, the policy is intended to increase bond amounts while  fostering an environment conducive to BLM’s leasing operations. As we  point out in this report, BLM has historically had difficulties securing bond  increases through bond reviews, and so additional steps may be needed  to adjust bond levels to more closely reflect expected reclamation costs.
In the draft we provided to BLM for comment, we included a  recommendation that the Director of BLM should take steps to obtain  funds from operators for reclaiming orphaned wells. BLM did not concur  with this recommendation, saying it does not have the authority to seek or  collect fees from lease operators to reclaim orphaned wells. We continue  to believe a mechanism for BLM to obtain funds from oil and gas  operators to cover the costs of reclamation for orphaned wells could help  ensure BLM can completely and timely reclaim these wells, some of  which have been orphaned for at least 10 years. We have therefore  instead made a matter for Congressional consideration.
BLM also provided technical comments, which we incorporated as  appropriate.
We are sending copies of this report to the appropriate congressional  committees, the Secretary of the Interior, and other interested parties. In  addition, the report is available at no charge on the GAO website at  http://www.gao.gov.
If you or your staff have any questions about this report, please contact  me at (202) 512-3841 or ruscof@gao.gov. Contact points for our Offices  of Congressional Relations and Public Affairs may be found on the last  page of this report. GAO staff who made key contributions to this report  are listed in appendix III.

Appendix I: Objectives, Scope, and Methodology

This report (1) describes the value of bonds for oil and gas wells in 2018  compared to 2008, and (2) examines the extent to which the Bureau of  Land Management’s (BLM) bonds ensure complete and timely  reclamation and thus prevent orphaned wells.
To describe the value of bonds for oil and gas wells in 2018 compared to  2008, we analyzed oil and gas well data from BLM’s Automated Fluid  Minerals Support System (AFMSS) as of May 2018 and data from BLM’s  Legacy Rehost 2000 (LR2000) system on bonds as of May 2018. Bond  data we reviewed included the bond category (e.g., individual lease or  nationwide) and bond value. We compared these data to data obtained  from the same systems for 2008 and reported by GAO in 2010. We  matched the May 2018 data from the two systems based on the bond  number—a variable in both systems—to identify how many wells were  covered by each bond and to determine the average bond value per well  for each bond category. To assess the reliability of AFMSS and LR2000  data elements, we reviewed agency documents, met with relevant agency  officials, and performed electronic testing. We found these data to be  sufficiently reliable for our purposes. We also interviewed BLM  headquarters officials to understand why bond composition may have  changed over time. To report on the number of bonded wells held by  BLM, we used a published BLM value for producible well bores—wells  capable of production—which should represent a lower bound on the  number of bonded wells in September 2018 because some wells may be  plugged or temporarily incapable of production but would still require a  bond if the surrounding site had not been fully reclaimed. To determine  the average value of bonds per well in 2018, we divided the total value of  all bonds held by BLM by the total number of producible well bores.
To examine the extent to which BLM’s bonds ensure complete and timely  reclamation and prevent orphaned wells, we conducted the following  analyses:
Reclamation cost scenarios: To determine whether bonds are  sufficient to cover potential reclamation costs for the wells they cover,  we identified typical high- and low-cost scenarios for well reclamation  (including plugging the well and reclaiming the surrounding well site)  and compared those scenarios to the average bond value available  per well. To determine high- and low-cost reclamation scenarios, we  analyzed BLM’s well reclamation cost estimates on proofs of claim  submitted to the Department of Justice from calendar year 2016  through May 2018. These 59 proofs of claim listed estimated  reclamation costs for 8,664 well sites. We calculated the average  reclamation cost per well for each individual proof of claim by dividing  the total dollar value claimed for reclamation liability (actual liability  plus potential liability) by the total number of wells listed in each proof  of claim document. We found the average reclamation cost estimates  for each proof of claim have a bimodal distribution, meaning that data  are clustered around two distinct cost levels, rather than clustered  around a single average cost. As a result, we determined that using  two separate measures that indicate typical values for separate  groups of low-cost and high-cost wells would provide more meaningful  statistics about cost. We therefore selected reclamation costs of  $20,000 for the low-cost reclamation scenario and $145,000 for the  high-cost scenario based on the 25th and 75th percentiles of the  distribution of average estimated reclamation cost per proof of claim,  weighted by the number of wells on each proof of claim.
Bond value per well: To determine the average bond value available  per well, we analyzed bonds listed in LR2000 that were tied to wells  listed in AFMSS using the bond number—a variable in both systems.  We found that 1,547 out of the 3,357 unique bond numbers in LR2000  had wells tied to them in AFMSS. These 1,547 bonds covered about  80 percent of the wells in AFMSS. The other 20 percent of wells in  AFMSS either did not list a bond number, or the bond number listed  was not in LR2000. For each bond in LR2000 covering wells in  AFMSS, we calculated the bond available per well as the bond value  divided by the number of wells it covers. We then compared the bond  values per well against both high ($145,000 per well) and low  ($20,000 per well) reclamation cost scenarios to identify which bonds  would be adequate to reclaim all the wells they covered under  different cost scenarios. If AFMSS bond information was incomplete, it  is possible that there are more wells covered by bonds than we were  able to identify—and therefore the bond value per well would be lower  than we found.
At-risk wells: To identify wells that may be at greater risk of becoming  orphaned and determine whether their bonds are sufficient to cover  potential reclamation costs, we used well production data from the  Office of Natural Resources Revenue’s Oil and Gas Operations  Report (OGOR) as of June 2017 and bond values from LR2000. First,  we defined wells as “at risk of becoming orphaned” if they met several  criteria. Specifically, we identified wells that (1) had recent OGOR  reports (on or after March 2017); (2) had not been used productively  from at least June 2008 through the most recent record (meaning the  well did not report producing any volume of oil or gas during this  timeframe, nor were any volume of water or materials injected into the  well during this timeframe); (3) were not being used as a monitoring  well in the most recent record, which we considered a productive use;  and (4) had not been plugged and abandoned. We selected June  2008 as the cutoff date for productivity because in June and July of  2008, oil and gas prices hit peaks that have not since been reached  again, and which the Energy Information Administration does not  expect prices to reach again through at least 2050. We believe our  analysis is a conservative estimate of wells at greater risk, in part  because we did not include wells that produced when prices were at  their peaks and stopped producing soon afterward and may be  unlikely to produce in the future unless prices reach the same peaks  again. In addition, our lower-bound estimate does not include some  coalbed methane wells that have been inactive for less than 9 years  but are unlikely to produce at current prices because of the relatively  higher cost of coalbed methane production. We also excluded wells  that reported any volume of oil or gas production or water injection  since June 2008, although some very low-producing wells may also  be at risk of becoming orphaned.
Bond value for at-risk wells: To calculate the average bond value per  at-risk well, we identified bonds listed in LR2000 that were tied to at- risk wells in AFMSS to determine the value of bonds available to  reclaim these at-risk wells if needed. We identified 2,041 of the 2,294  at-risk wells were linked to bonds. For each bond, we divided the  bond value by the number of at-risk wells it covered to determine the  bond amount per at-risk well. In cases in which an at-risk well was  linked to more than one bond, we additionally calculated the average  of the bond value per at-risk well for each bond linked to the well. To  determine the sufficiency of bonds for at-risk wells, we identified the  number of wells with an average bond value per at-risk well equal to  or greater than $20,000 (low cost reclamation scenario) or $145,000  (high cost reclamation scenario).
Orphaned wells: We compared three lists of orphaned wells based on  data provided by BLM in 2009, July 2017, and April 2019. The 2009  data are from our January 2010 report, which used Orphaned Well  Scoring Checklists that list information such as the well’s name and  location. The July 2017 data are from our May 2018 report, which  used an orphaned well list generated through a query of AFMSS by  BLM. The April 2019 list was generated through a query of an  updated version of AFMSS known as AFMSS 2. We compared the  lists to identify how many wells that were on the 2009 list remained on  the 2019 list, and how many wells that were on the 2017 list were on  the 2019 list.
To assess the reliability of the AFMSS, LR2000, and OGOR data  elements we used, we reviewed agency documents, met with relevant  agency officials, and performed electronic testing. We found these data  elements to be sufficiently reliable for our purposes. Similarly, to assess  the reliability of the 2019 orphaned well list, we reviewed agency  documents and met with relevant agency officials. Though we identified  shortcomings with data on orphaned wells, we nevertheless found these  data to be sufficiently reliable for the purpose of describing the orphaned  wells BLM has identified. To assess the reasonableness of proofs of  claim data, we interviewed relevant agency officials and reviewed agency  documents.
To understand how BLM manages bonds, we reviewed BLM’s policies  and interviewed officials from four BLM state offices and four BLM field  offices. We selected these state and field offices because, according to  AFMSS data, they were responsible for managing the largest numbers of  wells on federal land. These BLM state offices were California, New  Mexico, Utah, and Wyoming. These BLM field offices were Bakersfield,  Buffalo, Carlsbad, and Farmington. We also interviewed officials from  BLM’s headquarters office in Washington, D.C. Findings from the  selected BLM offices cannot be generalized to officials we did not  interview but provide a range of views. To understand how some states  with oil and gas development on state lands set minimum bonds and fund  orphaned well reclamation, we contacted officials from oil and gas  oversight agencies in Arkansas, Louisiana, Pennsylvania, Texas, Virginia,  and Wyoming.
We conducted this performance audit from January 2018 to September  2019 in accordance with generally accepted government auditing  standards. Those standards require that we plan and perform the audit to  obtain sufficient, appropriate evidence to provide a reasonable basis for  our findings and conclusions based on our audit objectives. We believe  that the evidence obtained provides a reasonable basis for our findings  and conclusions based on our audit objectives.

Appendix II: Comments from the Department of the Interior

Appendix III: GAO Contact and Staff Acknowledgments

	GAO Contact

	Staff Acknowledgments

In addition to the contact named above, Quindi Franco (Assistant  Director), Marietta Mayfield Revesz (Analyst-in-Charge), Marie Bancroft,  William Gerard, Cindy Gilbert, Gwen Kirby, Joe Maher, Shaundra  Patterson, Dan Royer, and Jerry Sandau made key contributions to this  report.


Input:
	Background

The Marine Corps’ Marine Helicopter Squadron One (HMX-1) currently  uses a fleet of 23 helicopters to support the President in the national  capital region, the continental United States and overseas. In April 2002,  the Navy began developing a replacement helicopter later identified as  the VH-71. Schedule delays, performance issues, and a doubling of  estimated acquisition costs from $6.5 billion to $13 billion prompted the  Navy to terminate the VH-71 program in 2009. Our prior work found that  the VH-71 program’s failure to follow acquisition best practices was a  critical factor in the program’s poor performance that led to its ultimate  termination. In the case of the VH-71, the Navy had a faulty business  case, did not perform appropriate systems engineering analysis to gain  knowledge at the right times, and failed to make necessary trade-offs  between resources and requirements even after years of development.  Because of these failures, the program was unable to achieve a stable  design and experienced significant cost growth and schedule delays.
Although the prior replacement program was terminated, the need for a  replacement helicopter remained. As a result, the Navy initiated a follow- on replacement program in 2010. In April 2012, the Secretary of Defense  approved the Navy’s plan based on the modification of an in-production  helicopter to meet Navy requirements. The VH-92A is expected to provide  improved performance, survivability, and communications capabilities,  while offering increased passenger capacity when compared to legacy  helicopters.
In May 2014, the Navy competitively awarded a contract to Sikorsky to  develop the VH-92A, which included options for production. The $2.7  billion contract includes a fixed-price incentive (firm target) Engineering  and Manufacturing Development (EMD) phase and a firm-fixed price  production phase with options for three lots for 17 helicopters, spares and  support equipment. Under the EMD phase, Sikorsky has delivered two  development test helicopters which were used in an operational  assessment that was completed in April 2019. Additionally, Sikorsky has  delivered three of four System Demonstration Test Article (SDTA)  production representative helicopters that are being used in  developmental testing and that will also be used to evaluate the VH-92A’s  operational effectiveness and suitability during the program’s Initial  Operational Test and Evaluation (IOT&E). The fourth SDTA helicopter is  to be delivered in May 2020 and will also be used to conduct IOT&E.
In June 2019, the Assistant Secretary of the Navy, Research,  Development and Acquisition (RD&A) approved the program to begin  low-rate initial production of the helicopters and authorized the program to  exercise the contract options for the first two low-rate production lots.  Shortly thereafter, the Navy exercised the Lot l option for 6 helicopters,  initial spares, and support equipment for $542 million. Those helicopters,  initial spares and support equipment are all to be delivered in calendar  year 2021. In February 2020, the Navy exercised the Lot ll option for $471  million for 6 additional helicopters and associated support equipment. All  of these helicopters and support equipment will be delivered in calendar  year 2022.
The Navy had planned for two years of low-rate initial production of 6  helicopters each year followed by one year of full-rate production for the  remaining 5 helicopters. The Navy’s acquisition strategy in support of the  production decision included a change in that plan with the re-designation  of full-rate production as a third lot of low-rate production. A key reason  for the change is that the planned full-rate production run of 5 helicopters  was too small to achieve the potential cost benefits of full-rate production,  which typically involves purchasing a sufficient number of helicopters to  decrease unit cost. This revised strategy would also enable the Navy to  award the third production lot seven months earlier than the originally  planned May 2021. Before obligating the funding available for the second  lot, the program office had to brief the Assistant Secretary of the Navy  (RD&A) on various elements of the VH-92A’s performance. The program  office is required to obtain approval from the Assistant Secretary of the  Navy (RD&A) for the procurement of the last lot (Lot lll) with a decision  brief that includes, among other things, the status of IOT&E.
Building a VH-92A helicopter involves work at three facilities. To begin the  production process, Sikorsky takes an S-92A helicopter from its  commercial production line in Coatesville, Pennsylvania and flies it to a  dedicated VH-92A modification facility in Stratford, Connecticut. Once  there, Sikorsky removes some components, such as circuit breaker  panels, engines, and main and tail rotor blades and replaces them with  VH-92A components. Additionally, Sikorsky modifies the helicopter to  accommodate VH-92A specific subsystems, including racks and wiring for  a Navy-developed mission communications system (MCS). Sikorsky then  flies the helicopter to a dedicated facility in Owego, New York where it  integrates the MCS, installs the executive cabin interior, paints the  helicopter, and conducts final testing before delivering the helicopter to  the government. See figure 1 for a depiction of modifications of the  commercial S-92A helicopter to the VH-92A presidential helicopter.

		Prior GAO Work on VH- 92A Acquisition

We have reported annually on the Navy’s effort to replace the current  fleet of presidential helicopters since 2011. Our reports highlighted, in  part, the extent to which the Navy used the lessons learned from the  failed VH-71 program—the need to balance requirements, costs, and  schedule and the importance of establishing a knowledge-based program  that is aligned with acquisition best practices—in its new effort. For  example, our 2011 report found that while the replacement program was  early in its development cycle, the Navy’s initial efforts appeared to reflect  the intent to pursue a best practices aligned knowledge-based  acquisition.
Following the program’s entry into the EMD phase of acquisition in April  2014, we found that the Navy’s reliance on mature technologies, selection  of an existing helicopter for use in the program, and award of a fixed-price  incentive type contract reduced risk. As to be expected with a major  system development effort, however, we found the program still faced a  number of technical challenges. In four reports issued from 2016 to 2019,  we found that the Navy continued making progress in developing the VH- 92A helicopter while managing design, integration and technical  challenges. Some key technical risk and challenges that we previously  identified are summarized in table 1. We discuss the current status of the  Navy’s efforts to address these challenges later in the report.

	Estimated Program Costs Have Decreased by 10 Percent

In April 2019, the Navy estimated that the VH-92A would cost about $4.9  billion to develop and produce and about $15.6 billion to operate and  support the helicopters through fiscal year 2062. Overall, the Navy’s  $20.5 billion estimate reflects a 10-percent reduction from the program’s  2014 baseline estimate (see table 2).
The Navy and contractor officials worked together to remain within the  program’s April 2014 cost baseline, in part, by keeping requirements  stable, limiting the design changes, and taking advantage of cost saving  initiatives. For example, the Navy has not added any key performance  requirements to the fixed-price incentive contract since it was awarded in  2014. The Navy has, however, implemented a small number of design  changes to add an additional cockpit display and increase the height of  the upper portion of the forward aircraft door. Previously, we found that  cost saving initiatives included leveraging the Federal Aviation  Administration’s airworthiness certification process, optimizing work  processes, and reducing the movement of helicopters between contractor  sites.
In addition, the Navy attributes the reduction in cost to support the VH- 92A fleet to using a planned maintenance interval concept as the basis  for its April 2019 cost estimate. Program officials explained that the April  2014 baseline estimate was based on the approach used to maintain the  current fleet of VH-3D and VH-60N presidential helicopters. For these  helicopters, the contractor carries out depot-level maintenance by  disassembling, inspecting, and reassembling them at its maintenance  depot. However, for the VH-92A, the Navy intends to perform depot-level  maintenance itself through scheduled inspections at its own presidential  helicopter support facility, which was designed to support this approach.  As a result, the Navy expects to be able to support the VH-92A fleet in a  more cost-effective manner while ensuring the availability of the  helicopter to perform its mission.

	Upcoming Initial Operational Test and Evaluation Will Demonstrate Extent to Which Technical Issues Have Been Addressed as Program Approaches End of Development

The program has made progress addressing technical risks and  performance challenges we discussed in prior reports and deficiencies  confirmed during the April 2019 operational assessment. According to  program officials, solutions for these performance shortfalls, except for  the landing zone suitability issue, have been developed and successfully  tested during integrated testing and will be evaluated during the 3-month  IOT&E test scheduled to begin in June 2020. The program is pursuing  options to achieve landing zone suitability that include possible changes  in operational procedures, helicopter design, and lawn surface  treatments. If design modifications are required, they will not be  implemented until after IOT&E. As a result, the Navy may not be able to  fully demonstrate that the VH-92A helicopter meets all its key  requirements until after the test program is complete. Further, IOT&E  results may also identify additional issues that may require additional  design or software changes. Depending on the severity of the issues, the  Navy may need additional time to test and incorporate changes into the  helicopter, including those helicopters currently in production.

		VH-92A Program Is Addressing Performance Shortfalls Previously Identified in Testing

The program office has mitigated or reduced risk on some technical  issues we discussed in prior reports. For example, according to program  documents, the program has mitigated the risk in the following areas:  helicopter start procedures, electromagnetic environment effects/  electromagnetic pulse and cybersecurity. The Navy assessed these  capabilities during earlier developmental test and during the operational  assessment, which concluded in April 2019; subsequently, the Navy  approved the program to enter into production. However, the operational  assessment confirmed other known performance shortfalls—specifically  those associated with the MCS—that, if not corrected, could prevent the  program from meeting certain operational requirements.
The MCS replaces the communications suite currently used by the in- service fleet and provides VH-92A passengers, pilots, and crew with  simultaneous short- and long-range secure and non-secure voice and  data communications capabilities. As such, its performance is critical for  the VH-92A to meet its mission. To conduct its operational assessment,  the Navy used two development test helicopters and a developmental  version of MCS software with known performance and capability  limitations. The operational assessment confirmed these MCS-related  performance limitations, including dropped communication connections.  Navy officials noted that these and other MCS-related performance  shortfalls could, if not addressed, reduce the helicopter’s availability to  perform its transport mission and lower overall reliability, among other  operational requirements.
Overall, the operational assessment confirmed 24 MCS-related  performance limitations. According to program officials, they have  incorporated or identified fixes to 22 of the 24 issues, which they are now  testing on SDTA helicopters. In turn, these fixes are expected to be  incorporated into MCS software that will be tested during IOT&E.  According to program officials, the remaining two MCS issues are related  to bandwidth and an unreliable off-aircraft network configuration affecting  on-aircraft system performance. According to those officials, the VH-92A  is already equipped with a wide-band line-of-sight system that provides  high bandwidth, though with coverage limitations. The program is  conducting market research on how to provide the helicopter with  increased bandwidth with increased coverage.
The remaining two issues were assessed earlier as having a serious (but  not critical) impact to mission accomplishment. In addition to the MCS  deficiencies, the helicopter experienced problems with other components  during the April 2019 operational assessment. For example, the mission  and maintenance data computer repeatedly sent out false warning  alarms/notifications, which affected the reliability and required the aircrew  to spend extra time troubleshooting or switch to a backup helicopter. A  software update to help address this issue is planned for the computer  prior to IOT&E.
The program is also still working to demonstrate the ability of the  helicopter to meet a key system capability requirement to land the  helicopter without damaging landing zones (including the White House  South Lawn). For landing zone suitability, the program’s objective has  been to assess the downwash and exhaust effects on the landing zone.  In a September 2018 training event, the Navy found that VH-92A’s  exhaust damaged a landing zone. Program officials stated that the  training event did not represent a typical operational scenario since the  lawn was exposed to the helicopter’s exhaust for a longer period than it  would be under normal operating conditions. The program is studying  solutions to minimize risk of landing zone damage including possible  changes in operational procedures, helicopter design, and lawn surface  treatments. For example, the contractor developed a prototype design  change to the helicopter’s auxiliary power unit to deflect exhaust. Flight  testing of the prototype design change was conducted in March 2020 with  analysis of the results expected in April 2020. Navy officials stated the  contractor is also conducting testing to determine if changes in helicopter  and/or engine operating procedures can mitigate the risk of landing zone  damage. According to both program officials and contractor  representatives, a decision on potential solutions will be made prior to  IOT&E. If design modifications are required, they will not be implemented  until after IOT&E.

		Program Schedule Has Slipped Further but Remains within the Original Approved Schedule Thresholds

Initial operational testing of the VH-92A, which will be used to evaluate  operational effectiveness and suitability of the helicopter, training system,  support equipment, upgraded MCS software and other changes  implemented to address previously identified issues, is now scheduled to  be conducted between June and September 2020. As such, IOT&E will  be conducted about 3 months later than we reported in 2019, but is  expected to be completed by the threshold (latest acceptable) date in the  Navy’s April 2014 baseline. Program officials attributed the 3-month delay  to the need to develop MCS hardware and software changes that are  currently being tested. Should IOT&E demonstrate that efforts to address  the MCS performance issues or other previously identified issues are  insufficient—or if the testing identifies new issues that result in the  program being unable to meet its operational requirements—then the  program may need to identify, test and incorporate changes into the VH- 92A’s design and into the helicopters already in production, further  delaying the program and increasing associated costs. As previously  noted, the first delivery of the helicopters ordered under the first  production option is scheduled to begin in April 2021.
As a result of the revised IOT&E test schedule, the program office has  also delayed the initial operational capability (IOC) milestone, which  clears the helicopter to enter service, by 3 months to January 2021. This  new date represents a total delay of 6 months from the original date but  still remains within the IOC threshold date established in April 2014.  Figure 2 compares the program’s 2019 schedule with the 2014 baseline  schedule and the 2018 schedule we reported on last year.
Program officials acknowledged that if there is a delay in the program that  results in the program breaching a schedule threshold established in its  acquisition baseline, they would need to submit a program deviation  report to the Assistant Secretary of the Navy (RD&A). In turn, the program  may need to keep certain staff in place longer than originally planned,  potentially increasing program costs. However, program officials told us  that the program can cover any additional costs with existing funding.  Further, Navy officials stated that should IOC be delayed, the Navy will  continue to use its existing fleet of presidential helicopters as the VH-92A  transitions into the HMX-1 fleet. Navy officials indicated that the transition  process will be gradual, and that the existing fleet is sufficiently funded  until HMX-1 completes the transition.

	Agency Comments

We are not making any recommendations in this report. We provided  DOD with a draft of this report. DOD provided technical comments, which  we incorporated as appropriate.
We are sending copies of this report to the appropriate congressional  committees, the Secretary of Defense and the Secretary of the Navy. In  addition, the report is available at no charge on the GAO website at  http://www.gao.gov.
If you or your staff have any questions about this report, please contact  me at (202) 512-4841 or DiNapoliT@gao.gov. Contacts points for our  Offices of Congressional Relations and Public Affairs may be found on  the last page of this report. GAO staff who made key contributions to this  report are listed in appendix l.

Appendix l: GAO Contact and Staff Acknowledgments

	GAO Contacts

	Staff Acknowledgments

In addition to the contact above, Bruce H. Thomas, Assistant Director;  Marvin E. Bonner; Bonita J.P. Oden; Alexander Webb; Peter Anderson;  Robin Wilson; and Marie Ahearn made key contributions to this report.

Related GAO Products

Presidential Helicopter: Program Continues to Make Development  Progress While Addressing Challenges. GAO-19-329. Washington, D.C.:  April 11, 2019.*  Presidential Helicopter: VH-92A Program Is Stable and Making Progress  While Facing Challenges. GAO-18-359. Washington, D.C.: April 30,  2018.*  Defense Acquisitions: Assessments of Selected Weapon Programs.  GAO-17-333SP. Washington, D.C.: March 30, 2017.*  Presidential Helicopter: Program Progressing Largely as Planned.  GAO-16-395. Washington, D.C.: April 14, 2016.*  Presidential Helicopter Acquisition: Program Established Knowledge- Based Business Case and Entered System Development with Plans for  Managing Challenges. GAO-15-392R. Washington, D.C.: April 14, 2015.*  Presidential Helicopter Acquisition: Update on Program’s Progress toward  Development Start. GAO-14-358R. Washington, D.C.: April 10, 2014.
Department of Defense’s Waiver of Competitive Prototyping Requirement  for the VXX Presidential Helicopter Replacement Program.  GAO-13-826R. Washington, D.C.: September 6, 2013.
Presidential Helicopter Acquisition: Program Makes Progress in  Balancing Requirements, Costs, and Schedule. GAO-13-257.  Washington, D.C.: April 9, 2013.
Presidential Helicopter Acquisition: Effort Delayed as DOD Adopts New  Approach to Balance Requirements, Costs, and Schedule.  GAO-12-381R. Washington, D.C.: February 27, 2012.
Defense Acquisitions: Application of Lessons Learned and Best Practices  in the Presidential Helicopter Program. GAO-11-380R. Washington, D.C.:  March 25, 2011. *GAO issued these reports on the VH-92A program in response to a provision in National  Authorization Defense Act of 2014.