Options for Increasing Federal Income From Crude Oil and Natural Gas on Federal Lands
In this report, CBO analyzes how the government manages access to oil and natural gas on federal lands and eight policy options that could modestly increase federal income from oil and gas leasing without significantly reducing production.
The production of oil and natural gas in the United States has increased rapidly over the past decade. As of 2014, domestic production of crude oil had grown to about half of total consumption, and domestic production of natural gas represented almost 95 percent of total consumption. Domestic oil and gas production occurring on federal lands or in federal waters off the coast of the United States represented about one-fifth of total U.S. production in 2014.
Federal lands and waters (referred to collectively as federal lands in this report) are managed by the Department of the Interior (DOI), which allows private firms to compete for the right to produce oil and gas in those areas. The firms that receive those rights make payments to the federal government, which distributes some of the money to states; over the 2005–2014 period, those payments averaged $11 billion per year. (The firms’ payments—which are income to the government—are recorded in the federal budget as offsetting receipts, which reduce outlays.) Two types of approaches could be used to increase federal income from oil and gas on federal lands. One approach is to increase the amount of land available for oil and gas production. A second approach, and the one considered in this report, is to revise the rules governing access to the oil and gas resources.
How Does the Government Currently Manage Access to Crude Oil and Natural Gas on Federal Lands?
The Department of the Interior, charged with ensuring that the United States receives a fair return for the oil and gas underlying federal lands, uses a three-stage process (or fiscal regime) to manage private firms’ access to those lands.
- Leasing. The federal government makes a set of approved parcels available for private leasing and uses an auction to identify the firm willing to pay the most for the right to explore and develop each parcel. The winning firm makes a onetime payment (its bonus bid) in exchange for exclusive access to explore the parcel.
- Exploration. Having leased a parcel, the federal government charges an annual rental fee for each year the lease is held without production of oil or gas.
- Production. For those parcels that produce oil or gas, the federal government collects royalty payments, which represent a share of the value of the extracted resources.
The maximum length of the exploration period is specified in the lease; once a parcel enters production, the lease continues in effect until production ends, which may be decades later.
For development of onshore oil and gas, the Department of the Interior operates under terms set by the Mineral Leasing Act of 1920, as amended, which have remained largely unchanged since 1987. Since that time, the minimum bid in auctions for access to federal lands has been $2 per acre, the rental fee has been $1.50 per acre for the first five years of the 10-year lease term and $2 per acre for the second five years, and the royalty rate has been 12.5 percent of production value.
Between 2003 and 2012, the federal government leased about 25,000 parcels (averaging 1,000 acres in size), about half of which were leased for less than $10 per acre, including about 4,000 parcels that received no bids and were leased noncompetitively for no fee. Most leased parcels have no exploratory drilling or production during the lease term. For parcels leased between 1996 and 2003, all of which have reached the end of their 10-year exploration period, only about 10 percent of onshore leases issued competitively and 3 percent of those issued noncompetitively entered production.
For development of offshore oil and gas resources, the Outer Continental Shelf Lands Act gives the Department of the Interior significant flexibility to adjust the leasing terms. DOI currently sets terms for each lease that are designed to encourage exploration and production. In the leasing stage, the department establishes a minimum bid based on the relative cost of exploration and development; if the highest bid is found to be below estimates of a fair (market-based) return to taxpayers, it is rejected. In the exploration stage, the rental fee is higher for parcels in deep water, reducing slightly a leaseholder’s incentive to wait to see whether additional information becomes available before undertaking costly exploratory drilling. (The effect is slight because the fee is very small relative to drilling costs.) For the production stage, DOI has set a royalty rate of 12.5 percent for offshore parcels near Alaska and recently increased the royalty rate to 18.75 percent for newly leased parcels in the Gulf of Mexico; the difference reflects the higher cost of development off the coast of Alaska.
How Much Income Has the Government Collected From Oil and Gas Leasing?
All told, the gross income (before payments to states) from onshore oil and gas resources averaged $3.0 billion annually from 2005 to 2014, comprising the following amounts:
- About $230 million per year in bonus bids,
- $50 million per year in fees for nonproducing leases, and
- $2.7 billion per year in royalties from production.
Total gross income from offshore oil and gas resources averaged $8.0 billion per year over the 2005–2014 period:
- Lease auctions generated about $1.8 billion,
- Rental fees generated about $230 million, and
- Royalties from production yielded about $6.0 billion.
Production from parcels and associated royalty payments can continue for many years, and thus leases issued in any given year represent only a small share of annual royalty income. In 2013, about 6 percent of royalty income from onshore oil and gas came from parcels that were leased in the previous 10 years; in contrast, about half came from parcels that were leased more than 50 years earlier. For offshore resources, about 8 percent of royalty income in 2013 came from parcels that were leased in the previous 10 years, and the majority came from parcels that were leased more than 20 years earlier (see figure below).
Some of the income collected by the federal government in the three-stage process is shared with the governments of the states where (or nearest to where) the oil and gas were extracted. The states’ shares of the income averaged almost 40 percent between 2005 and 2014.
How Could Lawmakers Change the Process to Increase Federal Income?
CBO analyzed eight ways in which lawmakers could change the fiscal terms for oil and gas development on federal lands so as to increase federal income (see table below). Some of the options would change qualitative features of the leasing process, such as auction formats and rules, whereas others would affect quantitative features, such as minimum bids or royalty rates. The specific versions of the quantitative options analyzed here for illustrative purposes are relatively modest, so as not to put federal lands at a competitive disadvantage relative to state-owned or privately owned lands. Smaller or larger versions of those options would yield smaller or larger increases in federal income. (Decreases in production that could result from larger changes would affect more than federal income and raise issues outside the scope of this report, such as possible environmental benefits or concerns about national security.)
For onshore resources, CBO considered the following approaches:
- Lawmakers could direct DOI to adopt an alternative form of auction that would encourage more intense competition between firms; greater competition would probably generate a small increase in the winning bids.
- The prohibition against setting lease-specific fiscal terms could be lifted, allowing DOI to set terms that were more advantageous for the government when there was greater certainty that parcels contained oil or gas reserves.
- Policymakers could instruct DOI to raise the minimum bid, the fee on nonproducing leases, or the royalty rate for all leases.
The options considered here would generate increases of between $50 million and $200 million in net income (after payments to states) over 10 years, CBO estimates. Reductions in production would be small or even negligible over that period or later.
For offshore resources, there are fewer policy options that DOI is not already considering. One such option, designed to increase competition, would require firms to nominate parcels before they can be scheduled for auction, as is the case for onshore parcels. Other policies would impose a new fee on nonproducing leases or adopt a royalty rate that increased if the price of oil or gas rose. Those policies, at commonly discussed magnitudes, would boost net income by amounts ranging from less than $25 million over 10 years to $500 million over that period, CBO estimates. Effects on production would be negligible.
One important factor affecting CBO’s estimates of budgetary effects over 10 years is the long lag time between leasing a parcel and beginning production from that parcel. The effects on net income of some options—for example, those that would change royalty rates—could be significantly larger outside of the 10-year period generally used for budget estimates, depending on future prices and other market conditions. But attempts to estimate budgetary effects beyond 10 years are hindered by greater uncertainty about those future conditions.