“We produce more oil at home than we have in 15 years.”
–President Obama, Feb. 12, 2013
Mr. President, we do produce more oil at home than we have in quite a long time. We could actually be producing a lot more than we currently are. See that decline in Federal Gulf of Mexico production from ~1.7 MMbbl/d to ~1.4 MMbbl/d since early 2010? You actually did build that.
It’s no secret in the oil patch that the recent increase in U.S. domestic oil production has occurred almost entirely on State and privately owned mineral leases in Texas and North Dakota and that production from Federal leases has been declining for most of the last four years.
The Congressional Research Service noticed the same pattern…
U.S. Crude Oil and Natural Gas Production in Federal and Non-Federal Areas
Specialist in Energy Policy
February 28, 2013
In 2012, oil prices ranged from $80 to $110 per barrel (West Texas Intermediate spot price) and remain high in early 2013. Congress is faced with proposals designed to increase domestic energy supply, enhance security, and/or amend the requirements of environmental statutes. A key
question in this discussion is how much oil and gas is produced each year and how much of that comes from federal and non-federal areas. On non-federal lands, there were modest fluctuations in oil production from fiscal years (FY) 2008-2010, then a significant increase from FY2010 to FY2012 increasing total U.S. oil production by about 1.1 million barrels per day over FY2007 production levels. All of the increase from FY2007 to FY2012 took place on non-federal lands, and the federal share of total U.S. crude oil production fell by about seven percentage points.
Natural gas prices, on the other hand, have remained low for the past several years, allowing gas to become much more competitive with coal for power generation. The shale gas boom has resulted in rising supplies of natural gas. Overall, U.S. natural gas production rose by four trillion cubic feet (tcf) or 20% since 2007, while production on federal lands (onshore and offshore) fell by about 33% and production on non-federal lands grew by 40%. The big shale gas plays are primarily on non-federal lands and are attracting a significant portion of investment for natural gas development.
Despite the new timeline for review, it took an average of 307 days for all parties to process (approve or deny) an APD in 2011, up from an average of 218 days in 2006.14 The difference however, is that in 2006 it took the BLM an average of 127 days to process an APD, while in 2011 it took BLM 71 days. In 2006, the industry took an average of 91 days to complete an APD, but in 2011, the industry took 236 days. Thus, since 2006, it took the BLM 56 fewer days to process APDs, while it took the industry 145 days longer to submit a completed application.15 The BLM stated in its FY2012 and FY2013 budget justifications that overall processing times per APD have increased because of the complexity of the process.
Some critics of this lengthy timeframe highlight the relatively speedy process for permit processing on private lands. However, crude oil development on federal lands takes place in a wholly different regulatory framework than that of oil development on private lands.16 State agencies permit drilling activity on private lands within their state, with some approving permits within ten business days of submission.
The permit delays cited by the CRS were just for the BLM (onshore) APD’s (applications for permits to drill). The CRS report did not discuss the even longer offshore delays. POE (Plan of Exploration) or DOCD (Development Operations Coordination Document) applications have to be submitted and approved before the APD. These plan documents used to be reviewed and approved in 30-60 days. Currently, the BOEMRE is taking 180 to more than 300 days to approve POE’s and DOCD’s. Quite often, the BOEMRE will even not “deem” the plan to have been received for more than 30 days. Then it can be another 30-60 days before they let the operator know if the plan is sufficiently completed for review. The 300,000 barrel per day decline can be laid squarely on the unlawful drilling moratorium in the Gulf of Mexico (yes, it was unlawful) and the subsequent “permitorium.” Back in 2007, Gulf of Mexico production was expected to reach 1.8 million bbl/day by 2013, largely on the back of the Lower Tertiary play…
This production was delayed by the moratorium and permitorium. The first field, Cascade/Chinook, has only just recently come on production. Several more fields should come on-line within the next year or two. So the Gulf may actually hit that 1.8 million bbl/day mark before the end of this decade.
In an era of high oil prices and increasing natural gas demand for power generation, it is simply insane that oil & gas production from Federal leases has been declining for most of the last four years…
It’s even more insane for this to be happening at a time when the Federal government claims that it desperately needs more revenue.
The CBO estimates that the full opening of the Outer Continental Shelf (OCS) and ANWR Area 1002 to exploration and production would quickly generate more than $35 billion per year in Federal revenue from lease bonuses and royalties…
On top of that, the BEA estimates that it would also generate more than $24 billion per year in Federal tax revenue…
That’s about $60 billion per year.
Simply allowing oil and gas companies to do their jobs could more than offset all of the real sequestration cuts (~$44 billion per year) without raising taxes on anyone.
Climate Progress and other green activists seem to be blaming geology for the decline in oil production under Federal lands. They must think that organic-rich shale deposition somehow managed to avoid Federal lands…
The shale plays have nothing to do with the decline in oil production from Federal leases. This is not an “either, or” thing. The increase in oil production from shale plays on non-Federal leases is not causing the decline in production from Federal leases.
The decline is entirely due to the drop in Gulf of Mexico production and this decline is entirely due to the moratorium and subsequent permitorium. As recently as 2010, before Macondo and the moratorium, the MMS was forecasting 1.8 million bbl/d from the Gulf by 2013…
Without the moratorium and permitorium, Gulf of Mexico oil production would likely be about 400,000 bbl/d more than it currently is. Possibly even higher, because production was recovering very quickly after the September 2009 economic crash and Hurricane Ike. While it is true that only about 10% of the current shale oil plays are being exploited on Federal lands, half of the shale gas plays in the Western U.S. are under Federally controlled lands.
Beyond that, the hydrocarbon potential under unavailable Federal lands and waters dwarfs the non-Federal shale plays. The undiscovered technically recoverable resource potential of the lower-48 OCS (Eastern Gulf of Mexico, Atlantic and Pacific), ANWR Area 1002 and other unavailable onshore Federal leases exceeds the discovered technically recoverable resource potential of the active shale oil plays by nearly 50%…
Also, the assertion that Federal leases only cover 10% of the shale oil plays misses the potential “mother-of-all” shale plays: The Green River Oil Shale of the Piceance Basin.
The vast majority of this play is under Federal control and largely unavailable for meaningful exploitation efforts…
While not a conventional oil play, the Green River Oil Shale is now technically and economically exploitable. Last fall the Interior Department announced that it would close off another 1.6 million acres to oil shale development. As it currently stands, very little of this acreage is available for leasing and then only for R&D purposes.
- Gulf of Mexico: 400,000 bbls/d shortfall due to the ongoing permitorium and more difficult lease terms.
- ANWR: 400,000 bbls/d shortfall due to failure to open Area 1002 in a timely manner.
- Green River Oil Shale: 500,000 bbls/d shortfall due to failure to effectively open Federal leases for exploitation.