Statement of Abigail Ross Hopper
Bureau of Ocean Energy Management
U.S. Department of the Interior
Senate Committee on Energy and Natural Resources
May 19, 2015
Chairman Murkowski, Ranking Member Cantwell, and members of the Committee, as the Director of the Bureau of Ocean Energy Management (BOEM) I am pleased to appear before you today to discuss S. 1276, the Offshore Energy and Jobs Act of 2015, S. 1278, the Alaska Outer Continental Shelf Lease Sale Act, and S. 1279, the Southern Atlantic Energy Security Act.
Taken together, these three bills would require lease sales offshore Alaska, in the South Atlantic and in the eastern Gulf of Mexico without Secretarial discretion to determine whether those areas are appropriate for leasing through balanced consideration of factors such as resource potential, State and local views and concerns, and the maturity of infrastructure needed to support oil and gas development, including response capabilities in the event of an oil spill. They would divert offshore energy development revenue from the Treasury, reducing the net return to taxpayers and adding to the federal deficit. We understand that the Department of Justice has constitutional concerns regarding S.1279 that they will convey separately. Accordingly, the Administration opposes these bills.
Today's hearing covers 26 individual bills that significantly affect a wide range of the Administration's energy programs and policies. Because the text for those bills was not made available to the Department until last week, the Administration has not had adequate time to conduct an in-depth analysis and the Department has not had adequate time to develop the detailed, thorough testimony that is appropriate for a hearing on these matters. I will therefore focus my testimony on the Administration's views on two broad themes presented in S. 1276, S. 1278, and S. 1279: revenue sharing and the Department's offshore oil and gas leasing program. My testimony will also address S. 1224, the Condensate Act, and S. 1280, the United States Exploration on Idle Tracts Act. Finally, in addition to my testimony, the Department will provide the Committee a statement for the record on the remaining bills subject to this hearing related to energy development on public lands onshore and other Departmental equities.
The Administration is committed to promoting safe and responsible domestic oil and gas production as part of a broad energy strategy that will protect consumers and reduce our dependence on foreign oil. The Department of the Interior manages the federal waters of the Outer Continental Shelf (OCS) that provide resources critical to the Nation's energy security; is responsible for collecting and distributing revenue from energy development; and ensures that the American taxpayer receives a fair return for development of those federal resources.
The Administration is mindful of the long-held view that coastal states should share the benefits of energy development that takes place offshore. Although coastal states clearly enjoy significant economic benefits from offshore development, there is also significant revenue that can be generated from offshore leasing and production in which coastal states assert an interest. Congress has addressed the interests of the coastal states in two ways. First, in 1953, the passage of the Submerged Lands Act, allowed coastal states to claim a seaward boundary up to three geographical miles from their coastlines (9 miles for Texas and the Gulf Coast of Florida). Second, in 1986, through the amendment of section 8(g) of the Outer Continental Shelf Lands Act (OCSLA), the Secretary of the Interior provides to coastal states 27 percent of all revenues collected on federal oil and gas leases within three miles of the seaward state boundary established pursuant to the Submerged Lands Act.
The Administration is committed to ensuring that American taxpayers receive a fair return from the sale of public resources and that taxpayers throughout the country benefit from the development of offshore energy resources owned by all Americans. As an alternative to multiple revenue sharing programs that benefit individual States and administration of a costly and cumbersome revenue allocation formula, the Administration proposes to work with Congress on legislation to redirect revenue sharing payments allocated by the Gulf of Mexico Energy Security Act of 2006 (GOMESA) to four Gulf of Mexico coastal States. The Administration proposes to redirect these payments, which are set to expand substantially starting in 2017, to programs that provide broad natural resource, watershed, and conservation benefits to the Nation; help the Federal government fulfill its role of being a good neighbor to local communities; and support other national priorities.
The Department takes seriously its responsibility to the public for the stewardship of our nation's natural resources and public assets that generate royalty revenue from federal leases. Revenue generated from leases on the federal OCS is directed to the U.S. Treasury and is used to fund federal conservation programs through contributions to the Land and Water Conservation Fund (LWCF) and the Historic Preservation Fund. The Administration strongly supports the core values of the LWCF and agrees that a portion of the proceeds from the sale of a public asset should be reinvested in something of lasting value for all Americans.
Previous and current revenue sharing proposals would ultimately reduce the net return to taxpayers from development of the federal resources generated on the OCS and would add to the federal deficit. Additional revenue sharing programs would likely result in a further reduction of billions of dollars in deposits to the Treasury. For these reasons, the Administration opposes new or expanded offshore revenue sharing.
Expansion of the Five Year Program
The OCSLA requires the Secretary to propose a schedule of offshore oil and gas lease sales every five years. This is referred to as the “Five Year Program.” As specified by Section 18 of the OCSLA, preparation and approval of an oil and gas Five Year Program is based on the Secretary of the Interior's consideration of eight factors, which include balancing the potential for environmental damage, discovery of oil and gas, and adverse impact on the coastal zone, to determine the size, timing, and location of lease sales.
With the current Program ending in mid-2017, BOEM is preparing the 2017–2022 OCS Oil and Gas Leasing Program. In June 2014, the Department published a Request for Information and Comments (RFI) and received approximately 500,000 comments. On January 29, 2015, the Department published the 2017–2022 OCS Oil and Gas Leasing Draft Proposed Program (DPP) for public comment. BOEM simultaneously published a Notice of Intent to Prepare a Draft Programmatic Environmental Impact Statement (PEIS), which will analyze the potential environmental effects of the Program. Twenty-three EIS scoping meetings were held in communities on the Atlantic coast, the Gulf of Mexico, and Alaska during the 60-day comment period. BOEM received over one million comments and is committed to integrating the critical information received during the comment period into the scientific, environmental, and social analysis that informs our decision-making. The Department expects to publish the Proposed Program and Draft PEIS in early 2016; the Department will invite public comment on both of these documents. Publication of the Proposed Final Program and Final PEIS will occur before the current program expires in 2017.
The 2017-2022 DPP includes potential lease sales in eight planning areas that contain nearly 80% of estimated undiscovered technically recoverable oil and gas resources on the U.S. OCS. In total, the 2017-2022 DPP schedules 14 potential lease sales for the 2017–2022 Program—10 sales in the Gulf of Mexico, one in the Atlantic, and three off the coast of Alaska. OCSLA Section 18 allows for proposed areas and sales in the DPP to be removed but not added to the program without restarting the program preparation process at the stage in which the sale or area was not included. For example, if an area was not included in the Draft Proposed Program (DPP), a new DPP would need to be developed to accommodate its inclusion. Even if the Eastern Gulf of Mexico moratorium as described in GOMESA were modified or lifted, no additional sales could be held in that area, nor could the sale area be expanded. Similarly, no additional sales in the Arctic or the Atlantic may be added to the 2017-2022 Five Year Program.
While Section 18 does not allow the Department to expand a Five Year Program without restarting the program preparation process, Congress has the ability to mandate additional sales via the legislative process. Such legislation would mandate that the Department of the Interior conduct lease sales in OCS Planning Areas without regard for the balanced consideration of factors under Section 18 of the OCS Lands Act, such as resource potential; equitable sharing of developmental benefits and environmental risks; the maturity of infrastructure needed to support oil and gas development, including emergency response; and input from local, state and federal stakeholders.
S. 1224, the Condensate Act
S.1224, the Condensate Act, would direct the Secretary of Energy to develop a standard definition of the term “condensate” and advise relevant Federal agencies to adopt that definition for purposes of clarifying energy policy. The bill would further require agencies within the Department of the Interior to consider condensate as a separate commodity. Therefore, in addition to the views outlined below, the Department defers to the Department of Energy with respect to the provisions directed to that Agency.
BOEM currently defines condensate as a very high-gravity (i.e., greater than 50 deg. API) liquid; it may exist in a dissolved gaseous state in the subsurface but liquefy at the surface. Both crude oil and condensate are reported jointly as oil in BOEM's Assessments of Undiscovered Technically Recoverable Oil and Gas Resources on the OCS. BOEM geoscientists and engineers conduct resource assessments in frontier areas that lack the empirical data necessary to define the condensate yield as a separate input into their Geologic Resource Assessment software model. Instead, assessors rely on the overall oil and gas volumes associated with analogue fields that are reported through publicly available industry sources and third party data service providers who do not report condensate separately from oil. This method instills confidence in BOEM's estimates of oil and gas as a whole and can be validated by information that is readily available. Therefore, without having any specific condensate data from analog fields, reporting condensate volumes separately in our undiscovered resource assessments may construe a false sense of precision and is not practical given the paucity of information. This proposed legislation is more applicable to reporting condensate in reserve estimates where empirical drilling and production information can be utilized. BOEM is willing to work with other federal agencies to define a working definition of condensate for the purpose of clarifying energy policy in the United States but is opposed to adopting a separate reporting convention for condensate in its assessment of Undiscovered Oil and Gas resources on the OCS.
The bill would increase uncertainty in U.S. Geological Survey (USGS) undiscovered petroleum resource assessments, especially estimates of natural gas liquids. The challenge is the lack of access to production data for condensate in hydrocarbon liquids (e.g., natural gas plant liquids vs. lease condensate, etc.). Industry, state, and national databases upon which USGS relies to estimate natural gas liquids do not include condensate as a separate item. If required to report condensate as part of USGS undiscovered resource assessments, USGS would have to report very uncertain condensate results alongside more reliable natural gas liquid estimates, for which abundant data are available. USGS also notes that, should a new definition be developed, inclusion into new assessments would be a multi-year process as data conforming to the new definition become available. USGS is open to working with stakeholders to develop a harmonized schema for classification and implementation of any new definition.
The Department's Office of Natural Resources Revenue (ONRR) foresees no significant impacts from proposed S. 1224 on its mission to collect, disburse, and verify Federal and Indian energy and other natural resource revenues. ONRR's production reporting and royalty reporting systems currently allow industry to report condensate separately from oil. If a definitive definition of condensate is developed, ONRR will instruct industry on the associated reporting requirements.
S. 1280, the United States Exploration on Idle Tracts Act
S.1280 directs the Secretary of the Interior to issue regulations establishing an annual production incentive fee for onshore and offshore oil and gas leases within 180 days after enactment of the bill. For offshore leases, the fee would be $4 for each acre of land from which oil and gas is produced for less than 90 days for each of the third, fourth, and fifth years of the lease. For the sixth year, this fee would be increased to $6 per acre, and $8 for the seventh year of the lease and every year thereafter. BOEM currently has in place a sliding-rental rate structure that prescribes increased rental rates per acre, per year, the longer a lease is held until production begins or until relinquishment. Use of a sliding scale rental system is designed to encourage exploration earlier in the lease term. In general, if a lease is drilled within the first five years of its initial period, escalating rentals can be avoided through either a discovery or through relinquishment. BOEM does not have any fees associated with incentivizing continued production on producing leases.
In the case of onshore leases, the fee would be $4 for each acre of land from which oil and gas is produced for less than 90 days for the first three years of the lease. This fee would be raised to $6 per acre in the fourth year of the lease, and $8 per acre in the fifth and every year thereafter.
Currently, the Bureau of Land Management collects annual rental rates onshore for both competitive and noncompetitive leases that are $1.50 per acre in the first five years and $2.00 per acre each year thereafter. Once the lease produces a paying quantity of oil or gas, rental payments cease and the leaseholder begins payment of royalties.
The Department supports incentivizing the diligent development of oil and gas leases. In lieu of S. 1280, the Department prefers its legislative proposal submitted through the 2016 President's Budget Request to establish a per-acre fee for all new leases that accrues each year that a lessee fails to drill a well as part of the Department of the Interior's Federal Oil and Gas Reforms package. The legislative proposal has been a component of the President's budget request since 2012, and recommends a fixed per acre fee to provide a financial incentive for leaseholders to bring their leases into production or relinquish them so that the tracts may be re-leased and developed by other parties. This fee would be in addition to rental rates charged by BOEM and BLM, thereby preserving the flexibility of each bureau to adjust rates as needed in future leases in order to continue to encourage appropriate diligent development by leaseholders. BLM is currently assessing whether to adjust the existing oil and gas rental rates. As with the current rental rates, the new fee would cease upon establishment of production and payment of royalties.
It is important to the Department and my bureau that we explore ways to move towards greater energy security via safe and responsible domestic oil and gas production while ensuring that the American taxpayer receives a fair return for development of those federal resources. I look forward to working with the committee and answering any questions you may have.