Critics say outdated oil-and-gas royalty rate costing Colorado millions

Every year, the Obama administration pushes to raise the royalty rate on onshore oil-and-gas production, looking to channel more of the profits from extraction on public lands to federal and state coffers. The efforts have been unsuccessful. Today’s 12.5 percent rate hasn’t changed since the 1920s. Analysts say that low rate has cost Colorado taxpayers an estimated $300 million since Obama took office in 2008.

In a state where the general fund is predicted to run dry by 2025 and where residents have to vote to raise taxes on themselves and rarely do, hiking the onshore royalty rate seems like an easy decision to make, especially given that it can be done administratively by Interior Secretary Sally Jewell with zero involvement from gridlocked Congress.

“This is an easy revenue raiser,” said Trevor Kincaid at the Denver-based Center for Western Priorities, which released a report  about the antique royalties rate this summer. “From a position of federal deficit, of communities that need to deal with fracking and drilling, and of states with budget shortfalls, it just makes sense.”

The issue is surprisingly not partisan. Back in 2007, under the Bush administration, the Department of the Interior raised the rate for offshore drilling.

“Raising royalties is sort of a win-win,” added Western Priorities report author Gregory Zimmerman. “It’s a mystery to us why it’s not happening.”

The Interior’s Bureau of Land Management (BLM) is responsible for some 8.4 million acres in Colorado. Oil-and-gas development on that land accounts for nearly 45,000 jobs and last year generated $9.5 billion in economic activity.

The BLM acknowledged that they could raise onshore royalty rates but wouldn’t say when or if that might happen.

“The Mineral Leasing Act gives the Secretary of the Interior the authority to set the royalty rate and that is done through a formal rule,” Bev Winston, a Bureau spokesperson wrote to the Independent. “There has been discussion of changing the rate for oil (not gas), but I have nothing new on that at this time.”

Kathleen Sgamma, spokesperson for the Western Energy Alliance, said the issue is more complicated than taxpayers reaping a slightly higher percentage of the value of the resources extracted from public lands.

“Instead of being able to charge a higher royalty rate, the federal government has decided that they want to extract revenue in the form of environmental and regulatory costs,” she said, noting that while securing a permit to drill on state lands in Texas — where the royalty is a whopping 25 percent — might take a few days or weeks, a developer on federal lands could jump through years of  hoops and have the whole effort come to nothing.

“There’s paying for environmental analysis — doing a wildlife survey after cultural survey. There’s simple delay with no explanation. There’s stacks of bureaucratic paperwork,” Sgamma said. “It’s the combination of risk to investment, time being money and regulatory processes that can cost millions.”

Analysts at the CWP and Remapping the Debate, which made the chart pictured below on estimated royalties losses, disagree. They argue that differences across state royalty rates suggest that low rates are not a significant incentive to develop, nor are high rates a significant deterrent.  Further, the percentage comes out of the market value of the extracted resource, so the actual cost of the royalty would reflect broader economic trends.

Sgamma insisted that the onshore royalty program is already a good deal for taxpayers, that it may be one of the best deals the federal government has going. She said the combined revenue for royalties, land leases and bonuses (the extra developers pay when there’s a bidding war over public lands) adds up to a spectacular return on investment.

“We return $88.76 for every dollar the federal government spends managing the federal onshore program,” she concluded.

 royalties chart

[Top photo by Any Jazz]


  1. It’s not just the federal royalty rate that’s shorting Colorado. Colorado’s own exemptions, like the “stripper well” exemption make most production untaxed. The stripper well exemption was put in place when oil was $25/barrel, and extracting that oil was uneconomic. Now at $95+/barrel, those wells are extremely profitable again, yet they incur no severance tax (90 Mcf gas/day and 15 barrels oil/day). Most wells fall into the stripper well exemption within 2-3 years due to the decline curve). You can time the production and sale to ensure it stays exempt, too.

    Check out Publication DR0021 to look at the Oil and Gas Severance Tax.

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