GOM REVENUE SHARING-1 Lease sales drive gulf OCS revenues

March 2, 2015
The Gulf of Mexico (GOM) Energy Security Act of 2006 (GOMESA) provides for sharing offshore lease revenues in the GOM Outer Continental Shelf (OCS).

Mark J. Kaiser
Center for Energy Studies
Louisiana State University
Baton Rouge

The Gulf of Mexico (GOM) Energy Security Act of 2006 (GOMESA) provides for sharing offshore lease revenues in the GOM Outer Continental Shelf (OCS).

The second phase of GOMESA begins in 2017 and specifies that 37.5% of qualified revenues from OCS leases issued after 2007-subject to a cap of $375 million/year-will be shared with gulf producing states, coastal political subdivisions within those states, and the federal Land and Water Conservation Fund. Qualified revenues are generated through bonus bids and royalty on awarded and producing leases (Fig. 1).

This three-part series estimates the range of future GOMESA Phase II qualified revenues without specifically forecasting GOM hydrocarbon futures-a difficult task given inherent market uncertainties and the time frame of Phase II, which extends beyond midcentury.

The series describes, instead, what amount of qualified revenues will be generated and how much of them will be shared.

What is shared is determined simply by applying the legislative requirements. The amount of qualified revenues generated, however, is more difficult to assess. Speculative but reasoned bounds can be established to help guide regulators and state agencies in their short, mid, and long-term planning.

This first article reviews lease sales, the engine of OCS activity, and describes the leasing process and revenue components. It analyzes 20 years of lease-sale data, including the amount of acreage available, bid on, and awarded.

Parts two and three qualify and model the individual components of OCS revenue and forecast qualified revenue streams for GOMESA Phase II.

GOMESA overview

Phase I of GOMESA revenue sharing began in fiscal year 2007 and covered the 181 Area and the 181 South Area in the eastern gulf.1 The second phase will cover the 181 Area and the 2002-07 GOM western and central planning areas.2 The expanded geographic coverage associated with Phase II means that more qualified revenue will be generated and shared.

Qualified revenues derive from OCS leases awarded during 2007-16 and all leases awarded 2017-57. In 2017, revenues accrue to states from royalty on leases awarded during 2007-16 that produce after 2016 and rents from leases awarded 2007-16 that are active in 2017 and beyond (Fig. 2). Bonus payments generated from 2007-16 are not included as part of qualified revenues.

In 2017, GOMESA Phase II qualified revenues include bonuses on all leases awarded, as well as all rents and royalties from those leases, through 2057. Phase II specifies 37.5% of qualified revenues from OCS leases will be distributed to gulf producing states subject to a cap of $375 million/year.

The Outer Continental Shelf Lands Act (OCSLA) is the key statute governing federal offshore oil and gas leasing and development.3 It directs the US Department of the Interior to maintain a 5-year leasing program that takes into consideration economic, social, and environmental values, satisfies the National Environmental Policy Act, and gathers input from federal agencies, governors of affected states, and programs developed under the Coastal Zone Management Act.

The OCS leasing program is two-tiered. In addition to the 5-year program planning cycles, there is the planning and execution of actual lease sales.

The program determines the size, timing, and location of sales, and requires public comment and an environmental impact study. For a lease sale to be held, it must be included in an approved 5-year program.

Lease sales, available acreage

Area-wide leasing is broken up into three planning areas: Western (WGOM), Central (CGOM), and Eastern (EGOM).

The 2007-12 leasing program included 11 lease sales in the GOM (Table 1). The 2010 WGOM and 2011 CGOM lease sales were cancelled because of the Macondo oil spill and clean-up.

The 2012-17 program includes 12 scheduled lease sales mostly in the WGOM and CGOM (Table 2). Sales in the EGOM planning area only include areas not currently subject to moratoria under GOMESA.

During 1954-82, oil and gas companies nominated areas for leasing in the GOM. Lease terms were for 5 years and the royalty rate was 16.67% for all water depths. In 1983, area-wide leasing was introduced and all unleased blocks in a program area were made available at the time of sale.

Planning areas are subdivided into named areas, and each area is divided into 3-mile by 3-mile (5,760 acre) blocks for lease. Lease blocks may be smaller if they are hemmed in by federal-state, international, or Universal Transverse Mercator Zone boundaries.

Available acreage consists of leases that have expired or been terminated, canceled, or relinquished. Acreage that has never been leased or that is not currently active or under appeal or deferred by legislative authority is available as well (Fig. 3).

Lease terms, bid process

Active leases have primary and secondary terms. The primary term is the period a lease may be kept active even though there is no production. The secondary term of the lease continues as long as the lease is producing in paying quantities.

Primary-term lengths vary. For most of the GOM's leasing history, primary terms have been 5 years in water depths shallower than 400 m, 8 years in water 400-800 m deep, and 10 years in water deeper than 800 m. In recent auctions, drilling activity on the lease has been used to determine the length of the primary term.

Final-sale notice provides the final terms and conditions for a lease sale, including the date, time, and location for the sale, and a list of the companies qualified to participate.3 The final notice of sale is published in the Federal Register 30 days before the sale is to be held. The notice includes where and when bids must be submitted, and the place, date, and hour the bids will be opened. It describes also the areas offered for lease, the lease form, stipulations, terms, and conditions of sale.

Companies submit sealed bids to the US Bureau of Ocean Energy Management (BOEM) up to the day before the sale. All bids are opened and read the day of the sale. High bidders are identified for each block and must submit a 1⁄5-bonus-bid deposit by the following day. Leases are not awarded at sale.

To prevent major oil and gas companies from dominating lease bidding, joint bids involving two or more majors were banned in 1975. Qualified joint bidders are defined now as those operators with production less than 1.6 million b/d of oil equivalent worldwide for all affiliated companies and subsidiaries.

During the post-auction period, high bids are rejected if they fail to meet minimum bid amount or other legal requirements, such as the joint-bid agreement. Fair market values are estimated for each tract, and leases are either accepted or rejected.

Leases are awarded to the high bidder if fair market value is received, the bid is legally valid, and the US Department of Justice and US Fair Trade Commission approve the sale.

After the final lease sale is approved, the successful bidder must execute the lease and remit the remaining 4/5 of the bonus bid and the first year's rent to BOEM. Failure to do this condemns the lease and the bidder forfeits the bonus deposit.

Bonuses, rents, royalties

Bonuses represent the cash consideration paid by the lessee for exclusive rights to explore, drill, and produce hydrocarbons on the tract for the term of the lease. The amount of the bonus depends on several variables, such as:

• Expected resources.
• Proximity to proved discoveries.
• Oil and gas prices.
• Forecast oil and gas futures.
• Expected levels of competition.
• Joint-bid arrangements.
• Capital budgets.
• Bidding strategies.
• Play concepts.
• Risk aversion.

The lessee is not obligated to drill a well, but it is required to make designated rental payments during the primary term, which begins immediately after the acreage is awarded.

Paid annually, rent maintains the lease during the primary term and is paid until the lease produces, expires, or is relinquished. If there is no development by the end of the primary term, the lease reverts to the government and is offered to the market in a future lease sale.

The first lease sales in the GOM under area-wide leasing had a $3/acre rent, which increased to $5/acre in 1987-95 sales.

During 1996-98, rent was set at $7.5/acre in water deeper than 200 m, and in 2005 increased to $6.25/acre (<200 m) and $9.5/acre (>200 m).

In 2009, rents increased to $7/acre in water shallower than 200 m and $11/acre in water deeper than 200 m in years 1-5 of the lease.

Leases issued after 2009 expire if the operator does not drill during the first 5 years of the lease. If the operator drills during this time, the primary term extends to its full duration and rents increase to $16/acre for the remaining years.

Once production starts, rentals cease and royalties commence during the secondary term. Royalties represent the landowner's share of production paid on the gross value of production less the cost of transportation and processing fees.

Historically, area-wide leasing stipulated a 16.67% royalty rate in water shallower than 400 m and a 12.5% royalty rate in water deeper than 400 m. In 2007, royalty rates across all water depths were set at 16.67%, and were increased to 18.75% in 2008.

OCS revenue engines

Acreage available, bid on, and awarded is the engine of OCS activity. The link among these average types is the precursor to OCS revenue generation.

The amount of acreage available in a lease sale depends on the number of unleased blocks in the planning area at the time of sale and reflects the cumulative historic activity and drilling success in the region.

Since 1994, the amount of acreage available for bid has been between 20-40 million acres in the CGOM and 17-28 million acres in WGOM (Fig. 4).

The amount of acreage available varies from year to year as blocks are relinquished or reach the end of their primary term and as acreage is removed or retained due to successful bidding and production.

Changes in available acreage are usually less than 10%/year, but in some years a large number of blocks may be captured or revert to the government (Fig. 5).

There have been changes of as much as 30%/year on occasion. Historically, the portion of acreage bid on has fluctuated from 1-20%. Over the past 20 years, the CGOM has averaged 10% and WGOM 7% (Fig. 6). The CGOM has a higher average percentage of acreage bid on due in part to the perception that it is a more proven, productive region with less risk.

Water depth impact

On average, 97% of acreage bid on is awarded. For modeling purposes, acreage bid on and awarded are considered identical (Fig. 7).

In recent years, operator interest in the GOM has fallen due to declining return on investment in shallow water and lower quality (recycled) acreage. Large company lease holdings also may be a factor.

Since 1994, 49.8 million acres were awarded in the CGOM and 30.8 million acres were awarded in the WGOM (Fig. 8). In the CGOM, 58% of the awarded acreage was in water deeper than 400 m, compared with 69% in the WGOM (Fig. 9, Table 3).

A large amount of deepwater acreage was awarded in 1996-98 in both the CGOM and WGOM and again in 2007-08 in the CGOM. Over the past decade, the decline in shallow water acreage leased in the WGOM has been pronounced.

The proportion of acreage leased in the CGOM and WGOM are causally related because similar capital budgets, economic conditions, and outlooks generally hold for bid strategies that occur during the year (Fig. 10). The proportion of acreage awarded in the CGOM and WGOM is less closely related because of the bid review process and other factors.

References

1. US Department of the Interior, US Minerals Management Service, "Federal Register Final Rules: Allocation and Disbursement of Royalties, Rentals, and Bonuses-Oil and Gas, Offshore," Vol. 73, No. 247, Dec. 23, 2008.

2. US Department of the Interior, US Bureau of Ocean Energy Management, 30 CFR Part 519. RIN 1012-AA11, US Office of Natural Resources Revenue 30 CFR Part 1219, 17948-17964, "Federal Register Proposed Rules: Allocation and Disbursement of Royalties, Rentals, and Bonuses-Oil and Gas, Offshore," Vol. 79, No. 6, Mar. 31, 2014.

3. US Department of the Interior, US Minerals Management Service, "Oil and gas leasing procedures and guidelines, Gulf of Mexico OCS Region," OCS Study MMS 2001-076, 2001, pp.150

The author
Mark J. Kaiser ([email protected]) is professor and director, research and development, at the Center for Energy Studies at Louisiana State University. His primary research interests are related to cost, fiscal, and regulatory studies in the oil and gas industry. Kaiser holds a PhD in engineering from Purdue University.