A Department of Interior (DOI)-commissioned report disputes General Accountability Office (GAO) claims that DOI has been falling down on the job in its collection of revenues from oil and natural gas producers and that those revenues are among the lowest in the world. It also casts some doubt on the Bureau of Land Management’s (BLM) proposal to raise the onshore royalty rate to 18.75%.

Interior commissioned energy consultant IHS Cambridge Energy Research Associates (CERA) to do the report in response to a GAO study in September 2008, which concluded that the U.S. government’s “take” of revenues from oil and natural gas production is one of the lowest in the world. It recommended that Interior Department undertake s broad review of its federal oil and gas fiscal system to determine whether it is collecting an appropriate share of royalties from producers (see NGI, Sept. 15, 2008).

“The fact that the recent studies show that the government take [of cash flow from production] in the deepwater U.S. Gulf of Mexico is relatively low and U.S. federal oil and gas regions are attractive places to invest…indicates that the federal oil and gas fiscal system may not strike a proper balance between maintaining competitive investment conditions and providing an appropriate share of revenues to the public from oil and gas sold on public lands and waters,” The GAO, the investigative arm of Congress, said at the time.

A government “take” is the percentage of the cash flow that the government receives from oil or natural gas production, including royalties, bonus bids and taxes. A government percentage take declines as a project’s profitability increases and increases as profitability declines, (i.e. government takes eat up more of the profits of smaller wells). “Such systems increase the marginal cost of development and often deter the development of marginal wells,” the report said.

In mid-2007, the GAO also reported that U.S. royalties on oil and natural gas production were lower than a number of state and foreign jurisdictions (see NGI, June 11, 2007). It concluded that the the United States receives a lower government take from the production of oil in the Gulf of Mexico [GOM] than do states — such as Colorado, Wyoming, Texas, Oklahoma, California and Louisiana — and many foreign governments.

“The [GAO] finding, however, appears to be based on a ranking of government take rather than an analysis of the bid adequacy procedures or an accounting of the amounts received via signature bonuses and income tax. Based on the ranges of the GOM government take [primarily royalties] reported by the GAO, we have concluded that the specific GOM takes did not include signature bonuses or account for exploration risk.

“Studies that factored in risk and present value in the mid-1980s and late 1990s report the U.S. OCS [Outer Continental Shelf] government take closer to 77% [of the cash flow from an oil and gas field]. If not accounted for in the government take statistic, a significant source of revenue accruing to the U.S. government is being overlooked,” said IHS CERA, which presented the 318-page study to Interior last fall. Questions about the report were raised at a recent Senate Energy and Natural Resources hearing.

“On a global perspective, the North American jurisdictions in general, and the federal fiscal systems in particular, reap most of the rewards [from producers] and share very little revenue risk compared with the majority of the [foreign and some state] jurisdictions included in the study,” IHS CERA said.

A government “take” is the percentage of the cash flow that the government receives from oil or natural gas production, including royalties, bonus bids and taxes. A government percentage take declines as a project’s profitability increases and increases as profitability declines, (i.e. government takes eat up more of the profits of smaller wells). “Such systems increase the marginal cost of development and often deter the development of marginal wells,” the report said.

The average government take in the U.S. GOM shelf (79%) is higher than the worldwide average of 72% and the offshore average of 74%. It ranks at the top of the fiscal terms index for the offshore based on several factors, including government take, internal rate of return (IRR), profit to investment ratio, revenue risk, fiscal stability and progressivity/regressivity.

The IHS CERA study compared 29 oil and gas upstream fiscal systems with respect to government share of profits, rates of return and other measures of profitability, revenue risk and fiscal system stability.

Contrary to the GAO report in 2007, the IHS CERA reports ranks the U.S. GOM shelf second in terms of the fiscal terms index behind Venezuela heavy oil, while the Texas onshore is sixth; U.S. Alaska onshore, eighth; GOM deepwater, 11th; Wyoming gas, 16th; and Louisiana onshore, 21st. This means the U.S.government gets more onshore and offshore revenue from producers than many other countries.

In ranking of the fiscal terms index of offshore systems alone, the U.S. GOM shelf was first. The “combination of low IRR and high government take and a highly regressive fiscal system is likely to result in loss of competitive edge for the GOM.”

And “compared with all onshore jurisdictions covered in this study, the North American jurisdictions, including Wyoming federal lands, allocate the least degree of risk to the government. As with onshore fiscal systems, under the GOM fiscal systems the risk is allocated to the investor; however the impact is not as harsh as in onshore U.S. jurisdictions because of the lack of severance and property taxes offshore,” the report said.

At a Senate hearing last Wednesday, BLM Director Bob Abbey said the agency had not made a final decision on whether to hike the onshore royalty rate to 18.75% from its existing 12.50%. It’s unclear whether the agency’s inaction is connected to the conclusions reached in the IHS CERA report.

“Let me just reassure the members of this committee that that decision has not been reached. We’re continuing to look at the full range of statistics that we have been able to compile,” Abbey said during a hearing of the Senate Appropriations Committee’s Subcommittee on Interior and Environment.

As part of the decision-making process, “we have analyzed what many of the states are charging relative to royalties,” as well as the royalty rates of other countries, he said. The Government

“I am glad to hear you make [the] statement that a conclusion has not been reached,” said Sen. Lisa Murkowski of Alaska, the ranking Republican on the subcommittee. She questioned the wisdom of proposals that would hike the federal royalty rate, as well as impose new inspection and permitting fees, saying they would drive producers from public lands to state and private lands.

Abbey said he didn’t know when the agency would make a determination on the onshore royalty rate. “There are a lot of factors that we [have to take] into consideration relative to what we will ultimately propose for any royalty rate increase.”

While this by no means is an assurance that a royalty rate increase is off the table, it’s good news for producers.

Abbey did not indicate when the BLM’s proposed rule on hydraulic fracturing (fracking) on public lands would be issued, but he did say that the rule would likely overlap with state regulation in only one area — disclosure of chemical fluids. The BLM rule would have two other components, addressing well bore integrity and water management, he noted.

He was asked to respond to a U.S. Geological Survey (USGS) report that estimated that some aquifers in the Bakken Shale play were losing about 1-2 feet per year due to increased energy production. Abbey referred the question to the USGS, but said “I will…give acknowledgment to the industry for they understand the potential impact and certainly the long-term impacts of continuing the operations that are currently taking place with the amount of water. And they are doing, or at least proposing to do, a better job of reusing water and actually treating water on-site.”

The $48 million to be recovered from an inspection fee proposed in the FY 2013 budget will go towards conducting closer inspections of fracking operations, according to Abbey. “Fracking is not new by any means. About 90% of the wells that are being drilled today on public lands are using the fracturing technology.”

In the offshore James Watson, director of the Bureau of Safety and Environmental Enforcement (BSEE), said he was not going to sacrifice safety and the environment to speed up the processing of permits.

“A lot of attention has been paid to our permitting pace, and I sympathize with those persons who depend on these permits for their jobs…We have issued hundreds of deepwater and shallow water permits over this past year. However those who believe that the pace of permitting should be automatically the same as before Deepwater Horizon are ignoring the lessons of that disaster,” Watson said.

“I’m not about the number of days it takes. I’m still about safety and environmental protection.” Still he noted that the average time to process a permit fell from 97 days between last March and September 2011 to about 62 days currently. This, he believes, is due to two factors. “I think there’s been a combination of efforts by industry to provide more comprehensive, better prepared applications than a year ago. And on the BSEE side, I think we’re better at doing these new safety standards.”

While industry has criticized Interior’s sluggish permitting pace, “I haven’t heard any disparaging remarks about our competencies,” said Watson.

Because of the fees on industry, Watson said BSEE has been able to increase its number of inspectors to 91 from 61 this year, and to add about 10% more engineers needed to process permits. His target is 150 inspectors and 230 engineers.

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