Offshore Oil and Gas Resources: Information on Infrastructure Decommissioning and Federal Financial Risk
Released: 2017-05-17T00:00:00

Letter

Offshore Oil and Gas Infrastructure in the Gulf Varies in Size and Complexity, and Lessees Have Installed and Removed Thousands of Structures Over the Past Half Century

As we reported in December 2015, offshore oil and gas infrastructure in the Gulf varies in size and complexity, and lessees have installed and plugged or removed thousands of wells and structures over the past half century. The simplest structures are found in shallow water and include caissons and well protectors. A caisson is a cylindrical or tapered large diameter steel pipe enclosing a well conductor and is the minimum structure for offshore development. A well protector provides support to one or more wells with no production equipment and facilities. Lessees drill wells to access and extract oil and gas from geologic formations. According to an Interior publication, “exploratory” wells are drilled in an area with potential oil and gas reserves, while “development” wells are drilled to produce oil and gas from a known reserve. An exploratory well may not actually produce any oil or gas, while a successful development well produces oil or gas. Some wellheads are located on a fixed platform (typically in shallow water), while other wellheads are located on the seafloor (typically in deep water).

A more complex structure in shallow water is a fixed platform, which uses a jacket and pilings to support the superstructure, or deck. The deck is the surface where work is performed and provides space for crew quarters, a drilling rig, and production facilities. Most of the large fixed platforms have living quarters for the crew, a helicopter pad, and room for drilling and production equipment. A typical platform is designed so that multiple wells may be drilled from it. Wells from a single platform may have bottom-hole locations many thousands of feet (laterally displaced) from the surface location.

Structures in deep water rely on other methods to anchor to the ocean floor. For example, a “compliant tower” structure supports the deck using a narrow, flexible tower and a piled foundation. According to an industry publication, the flexible nature of the compliant tower allows it to withstand large wind and wave forces associated with hurricanes. Other common deep-water structures include the tension leg platform, floating production system, and spar platform. Illustrations of these structures are shown in figure 1.

In our December 2015 report, we also discussed the oil and gas infrastructure installed and removed in the Gulf over time. Figure 2 shows the annual number of wells drilled and plugged in the Gulf from 1947 through 2014. During this period, lessees drilled a total of 52,223 wells in the Gulf (including 18,447 exploratory wells and 33,776 development wells) and plugged a total of 29,879 wells (including 4,017 temporarily abandoned wells and 25,862 permanently abandoned wells).

Figure 3 shows the annual number of structures installed and removed in the Gulf from 1947 through 2014. During this period, lessees installed a total of 7,038 structures in the Gulf. In addition, starting in the 1970s, lessees began removing structures from the Gulf. Specifically, lessees removed a total of 4,611 structures from 1973 through 2014. Most of the structures installed and removed were fixed platforms and caissons installed in shallow water.

From the late 1940s through the early 1960s, lessees only drilled wells in shallow water. However, starting in the mid-1960s, lessees began drilling wells in deep water. Figure 4 shows the annual number of wells drilled and plugged in deep water in the Gulf from 1966 through 2014. During this period, lessees drilled a total of 6,468 wells (including exploratory and development wells) and plugged a total of 2,489 wells (including temporary and permanently abandoned wells) in deep water. Lessees also installed 112 structures—mostly fixed platforms, spar, tension leg platforms, and floating production systems—and removed 19 structures in deep water during this period.

From 1985 through 2014, oil production from deepwater wells has increased significantly, as shown in figure 5. While the number of wells drilled decreased in recent years, offshore production increased as lessees drilled wells in deep water that are more productive than wells in shallower water. In 2014, over 80 percent of Gulf oil production occurred in deep water, up from 6 percent in 1985. According to BSEE officials we interviewed for our December 2015 report, activities in deep water, including drilling and decommissioning, are significantly more expensive than those in shallow water because of the technology required and challenges associated with deep water, such as very high pressures at significant water and well depths.

Interior Requires Lessees to Decommission Offshore Infrastructure and Developed Procedures to Oversee the Process and Estimate the Associated Costs

As we reported in December 2015, Interior requires lessees to decommission offshore oil and gas infrastructure, and Interior’s BSEE developed procedures to oversee the decommissioning process for offshore oil and gas infrastructure and to estimate costs associated with decommissioning liabilities. According to Interior regulations, lessees must permanently plug all wells, remove all platforms and other structures, decommission all pipelines, and clear the seafloor of all obstructions created by the lease and pipeline right-of-way operations when the lessee’s facility is no longer useful for operations. Generally, lessees must permanently plug wells and remove platforms within 1 year after a lease terminates. As we reported in December 2015, BSEE referred to infrastructure that was no longer useful for operations on active leases as idle infrastructure (or “idle iron”) and infrastructure on expired leases as terminated lease infrastructure. In general, BSEE’s guidance defined idle infrastructure as follows:

A well is considered idle if it has not been used in the past 5 years for operations associated with exploration or development and production of oil or gas, and if the lessee has no plans for such operations.

A platform is considered idle if it has been toppled or otherwise destroyed, or it has not been used in the past 5 years for operations associated with exploration or development and production of oil or gas.

According to BSEE officials we spoke with as part of our December 2015 report, companies may postpone decommissioning idle wells and platforms to defer the cost of removal, increase the opportunity for resale, or reduce decommissioning costs through economies of scale and scheduling, among other reasons. However, they said that postponing decommissioning can be costly because the longer a structure is present in the Gulf the greater the likelihood it will be damaged by a storm. According to Interior documentation, decommissioning a storm-damaged structure may cost 15 times or more the cost of decommissioning an undamaged structure. In 2005, Hurricanes Katrina and Rita destroyed 116 structures and significantly damaged another 163 structures and 542 pipelines in the Gulf, according to Interior documentation. According to BSEE officials, as of April 2015, the Gulf contained 13 destroyed structures with 16 associated wells.

Storm-damaged or toppled structures present a greater risk to safety and require difficult and time-consuming salvage work. After preliminary salvage work that can take weeks, divers cut and remove structural components while crane assemblies remove the components and place them on a barge for transport and disposal. Additionally, when working in areas with strong currents and unconsolidated material, coffer dams are often constructed on the seabed to prevent material from slumping back in on the dive crews and equipment.

In December 2015, we reported that BSEE had developed procedures for overseeing the decommissioning of offshore oil and gas infrastructure and estimating costs associated with decommissioning liabilities. Under BSEE’s regulations, lessees must apply for approval before plugging wells, removing platforms or other facilities, and decommissioning pipelines. According to BSEE regional officials, they reviewed applications to ensure that they contained the required information (see table 1 below). Once this process was complete, BSEE officials approved a lessee’s application, which authorized the lessee to begin decommissioning activities.

After lessees completed all planned decommissioning, they were required to report to BSEE on the outcome of these activities so that BSEE could verify that all their decommissioning obligations had been met, including clearing the seafloor around wells, platforms, and other facilities. According to BSEE regional officials we spoke with as part of our December 2015 report, they reviewed lessee reports on decommissioning activities to ensure that the results were consistent with the information presented as part of the application process. Table 2 summarizes BSEE’s reporting requirements related to the results of decommissioning activities, as of December 2015.

In addition to reviewing lessee applications and reports, the BSEE Gulf region identified and tracked idle and terminated lease infrastructure. According to BSEE regional officials we spoke with as part of our December 2015 report, the BSEE Gulf region began identifying and tracking idle lease infrastructure in 2010 and updated a list of this infrastructure on an annual basis. BSEE began identifying and tracking terminated lease infrastructure prior to 2010, according to BSEE regional officials. At the beginning of each calendar year, BSEE regional officials obtained data from Interior’s main data system—the Technical Information Management System—on wells and structures on leases that meet the criteria for idle and terminated lease infrastructure. Based on these data, BSEE sent a list of idle and terminated lease infrastructure to each lessee, requesting a decommissioning plan and schedule for decommissioning the lessee’s inventory. According to BSEE regional officials, BSEE worked with lessees to verify the accuracy of their inventory of idle and terminated lease infrastructure, and BSEE tracked lessees’ progress in meeting their schedules.

According to BSEE regional officials we spoke with for our December 2015 report, BSEE estimated the costs associated with decommissioning liabilities by counting the number and types of wells, pipeline segments, and structures on a lease and using data on the water depth associated with this infrastructure. Using these data, BSEE then calculated the costs associated with (1) plugging and abandoning wells, (2) removing platforms and other structures, (3) decommissioning pipelines, and (4) clearing debris from the site.

In general, the cost to plug wells and remove structures increases as the water depth increases. For example, according to BSEE’s methodology at the time of our December 2015 report, its estimate of the cost to plug a dry tree well attached to a fixed structure in shallow water was $150,000, while its estimate of the cost to plug a subsea well in deep water was a minimum of about $21 million. Likewise, BSEE’s estimates of the costs to remove fixed platforms in shallow water ranged from approximately $85,000 to $4.6 million, while its estimate of the cost to remove a floating structure (and associated equipment) in deep water was a minimum of $30 million.

In our December 2015 report, we found that BSEE generally did not have access to current data on decommissioning costs but had taken steps to address this issue. Prior to December 2015, under BSEE’s regulations, lessees were not required to report costs associated with decommissioning activities to BSEE. According to BSEE regional officials, data on decommissioning costs were considered proprietary, and companies generally did not share this information with BSEE. Instead, BSEE regional officials told us that they relied on other sources of data— some of which were decades old and, as a result, likely inaccurate—to estimate costs associated with decommissioning liabilities. For example, according to BSEE regional officials, their estimates for decommissioning liabilities in shallow water were based on data provided by the oil and gas industry in 1995. However, in December 2015, BSEE issued a final rule requiring establishing new requirements for lessees to submit expense information on costs associated with plugging and abandonment, platform removal, and site clearance.

Interior Requires Lessees to Provide Financial Assurances for Decommissioning Liabilities, but Our December 2015 Report Found that Interior’s Procedures Posed Risks to the Federal Government

As we reported in December 2015, Interior’s BOEM requires financial assurances from lessees to cover decommissioning liabilities, but we found that Interior’s financial assurance procedures in place at that time posed risks to the federal government. Under The Outer Continental Shelf Lands Act, Interior has issued regulations and developed financial assurance procedures to protect the government from incurring costs if a lessee fails to meet its lease obligations, including its obligation to decommission offshore infrastructure.

Under the regulations and procedures in place at the time of our December 2015 report, BOEM regional directors could require a lessee to provide a bond —referred to as a “supplemental bond”—that covers the estimated costs of decommissioning for a lease. BSEE is responsible for estimating costs associated with decommissioning liabilities. If a lessee was unable to accomplish decommissioning obligations as required, the federal government could use the bond to cover decommissioning costs. However, where there are co-lessees or prior lessees, if BOEM determined that at least one lessee had sufficient financial strength to accomplish decommissioning obligations on the lease, BOEM might waive the requirement for a supplemental bond.

Under BOEM and BSEE regulations, lessee liability is “joint and several”—that is, each lessee is liable for all decommissioning obligations that accrue on the lease during its ownership, including those that accrued prior to its ownership but had not been performed. In addition, a lessee that transfers its ownership rights to another party will continue to be liable for the decommissioning obligations it accrued. According to BOEM officials we spoke with as part of our December 2015 report, BOEM ensured that all decommissioning obligations on offshore leases were required to be covered by either a supplemental bond or a current lessee that had the financial ability to conduct decommissioning.

Under BOEM’s financial assurance procedures in place at the time of our December 2015 report, each offshore lease with a decommissioning liability had to be covered by a supplemental bond unless BOEM determined that a lessee had the financial ability to fulfill its decommissioning obligations. BOEM staff evaluated the financial ability of a lessee to fulfill its decommissioning obligations by means of a financial strength test. BOEM’s financial strength test required a lessee to meet the following criteria: provide an independently audited financial statement indicating a net worth greater than $65 million; possess a total decommissioning liability (as determined by BSEE) of less than or equal to 50 percent of its audited net worth; possess total company liabilities of no more than 2 to 3 times the value of the adjusted net worth;, and demonstrate reliability, as shown by a record of compliance with laws, regulations and lease terms, among other factors.

According to our December 2015 report, if a lessee passed the financial strength test by demonstrating its financial ability to pay for decommissioning on its leases, BOEM waived its requirement for the lessee to provide supplemental bonds. Other responsible parties on the lease would also be waived from the requirement to provide supplemental bonds. According to BOEM officials, BOEM waived these parties as well because the waived lessee could be held responsible if another party on a lease did not fulfill its decommissioning obligations. In addition, a waived lessee might provide financial assurance in the form of a corporate guarantee of the lease obligations of a lessee on another lease.

According to our December 2015 report, after BOEM waived a lessee from the requirement to provide supplemental bonding, it monitored the financial strength of the lessee to ensure it continued to pass BOEM’s financial strength test. BOEM conducted quarterly financial reviews for the first 2 years after a lessee received a waiver and then an annual review thereafter. In addition, on a weekly basis, BOEM compared the decommissioning obligations (as determined by BSEE) of all waived lessees with the financial information provided by lessee audited financial statements. If BOEM found that a lessee no longer passed its financial strength test, BOEM conducted a more in-depth review of a lessee’s financial status by reviewing financial statements, credit ratings, and other financial information. BOEM might also conduct an unscheduled financial review if: (1) BSEE revised its estimate of a lessee’s decommissioning liability, (2) a lessee’s financial status changed as reported by credit rating agencies, or (3) a lessee did not pay the required royalties to the federal government. According to BOEM officials, these reviews could have caused BOEM to revoke a lessee’s waiver from the requirement to provide supplemental bonding. For example, in May 2015, BOEM revoked the waiver of one lessee and, according to BOEM officials, the waived lessee and related parties could have been required to provide as much as $1 billion in supplemental bonds.

However, in our December 2015 report, we found that BOEM’s financial assurance procedures posed financial risks to the federal government in several ways. In particular, under BOEM’s procedures in place at the time, less than 8 percent of estimated decommissioning liabilities in the Gulf were covered by financial assurance mechanisms such as bonds. Specifically, as of October 2015, according to BOEM officials, for an estimated $38.2 billion in decommissioning liabilities in the Gulf, BOEM held or required about $2.9 billion in bonds and other financial assurances. For $33.0 billion in decommissioning liabilities, BOEM had waived 47 lessees from the requirement to provide supplemental bonds based on BOEM’s reviews of the lessees’ financial strength, according to BOEM officials., As we have found in prior GAO reports, the use of financial strength tests and corporate guarantees in lieu of bonds pose financial risks to the federal government. Specifically, we found, in August 2005, that the financial assurance mechanisms that impose the lowest costs on the companies using them—such as financial strength tests and corporate guarantees—also typically pose the highest financial risks to the government entity accepting them. In that report, we found that, if a company passes a financial strength test but subsequently files for bankruptcy or becomes insolvent, the company in essence is no longer providing financial assurance because it may no longer have the financial capacity to meet its obligations. Such financial deterioration can occur quickly. While companies no longer meeting the financial test are to obtain other financial assurance, they may not be able to obtain or afford to purchase it. In addition, in May 2012, we found that, according to the Bureau of Land Management and the Environmental Protection Agency, corporate guarantees are potentially risky because they are not covered by a specific financial asset such as a bond. Therefore, in our December 2015 report, we concluded that BOEM’s use of the financial strength test and corporate guarantees in lieu of bonds raised the risk that the federal government would have to pay for offshore decommissioning if lessees did not.

According to BOEM officials we spoke with for our December 2015 report, BOEM recognized the financial risks associated with its financial assurance procedures and planned to revise its procedures to reduce risk. Specifically, BOEM officials told us that BOEM’s planned revisions would eliminate the use of financial strength tests to completely waive lessees from the requirement to provide supplemental bonding. Instead, BOEM planned to conduct financial reviews of lessees’ financial status and, based on those reviews, assign lessees an amount of credit that may be used to reduce required bonding associated with decommissioning liabilities on leases. Lessees would be able to apportion this credit to leases, in coordination with other responsible parties on those leases, to ensure that lease decommissioning liabilities are fully covered by apportioned credit or supplemental bonds. However, because it was unclear whether BOEM’s planned revisions would improve its procedures and the extent to which these revisions would increase the amount of bonding that lessees provide, we recommended in our December 2015 report, that BOEM complete its plans to revise its financial assurance procedures, and Interior concurred.

Since the issuance of our December 2015 report, BOEM revised its financial assurance procedures. Specifically, on July 12, 2016, BOEM issued revised procedures, effective on September 12, 2016, containing several changes to BOEM’s policy concerning additional financial security requirements for leases, pipeline rights-of-way, and rights-of-use and easement, including the use of alternative measures of financial strength. In December 2016, BOEM issued orders to sole liability lessees requiring them to provide additional security. In January 2017, BOEM delayed implementation of its revised financial assurance procedures for 6 months. The following month, BOEM withdrew its December 2016 orders to sole liability lessees, stating that these orders will be discussed as part of the six-month review process related to the financial assurance procedures. We have not evaluated the extent to which these financial assurance procedures and orders, if fully implemented, would address the concerns we have identified about the financial risks to the federal government. We will continue to monitor Interior’s actions to address our recommendations.

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

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Staff Acknowledgments

GAO staff who made key contributions to this testimony are Jason Holliday, Christine Kehr, and David Messman.

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