Governments of resource-rich countries commonly fill their coffers via royalties, taxes and other fiscal mechanisms that allow them to benefit from their national endowments. But while a well-designed fiscal regime can benefit both producers and residents, excessive government take can force producers to look elsewhere for returns, stifling investment.

When governments establish fiscal terms for oil and gas development, they are generally aiming for their “fair share”, said Irena Aggaliu, Managing Director at IHS CERA, at the USAEE/IAEE North American Conference in Anchorage, Alaska. But “there is no universal standard of what’s fair”, she said.

Fiscal regimes that seek to maximize value to the state – meaning not only that the state recovers a share of revenues from natural resource development, but also that those receipts can be sustained over time through continuous investment – must walk a fine line between short-term incentives and longer-term interests. Tax too much, and investment can fall right off a cliff.

“Fiscal terms do impact the attractiveness of project returns,” said ConocoPhillips Chief Economist Marianne Kah. The most profitable projects may still offer companies’ their required return on investment despite high government take, but a fiscal regime that does not take companies’ profit motives into account can destroy incentives to develop more marginal projects. “If the project is wildly economic, it can support higher fiscal terms. If it’s marginal, it can’t.”

Companies look at a range of factors when deciding whether to invest in an oil or gas field, and fiscal terms have the potential to either make or break a project’s economics. Kah laid out the metrics that ConocoPhillips uses to assess a project’s attractiveness.

Cost is an obvious one, and higher costs can be driven by a wide range of factors, such as complexity, remoteness, and harsh operating conditions. And the size of the resource matters, because “you want to have things that have economies of scale”, Kah said.

In some operating areas, managing health, safety and environmental issues can be very difficult and costly, and possibly even prohibitive to investment. Political risk, rule of law, government stability and legal and regulatory regimes are also major drivers of investment decisions.

Shorter cycle times improve a project’s economics, as well, “which is why something like deepwater Gulf of Mexico, that takes 10-12 years to develop, wouldn’t be as attractive, probably – unless it was really, really large – relative to say a tight oil or shale investment in the Lower 48, which we would develop in just a couple of years”, Kah said. And from a commercial standpoint, projects with easy access to markets have an advantage over those that do not.

After these and other factors are weighed and measured, a company must look at what its share of project profitability will be.

“If something is higher cost and has smaller reserve size, you won’t be able to have the same fiscal terms and support that as if you had a large reserve size and lower costs,” Kah said. “Not everything can have the same fiscal terms and remain economically attractive for investment.”

Learning the Hard Way

This question is particularly pertinent for places like Alaska and Alberta, where adoption of what companies saw as punitive fiscal regimes appear to have contributed to sharp declines in investment.

“Tax rates do matter,” Kah said. “The higher the tax rate, the less investment you’re going to get.”

Alberta unveiled a new royalty framework in 2007 that introduced higher rates. And the province found that investment in mineral lease sales – required to develop oil and gas resources – dropped off dramatically in 2009.

“For the previous decade, Alberta was hands-down leading the rest of Western Canada with respect to how much dollars were being been spent to acquire mineral leases,” said Matthew Foss, Associate Head of the Alberta Department of Energy’s Economics and Markets Branch. In 2009, “we went from 60% down to 25%. Huge.”

Alberta responded by amending its fiscal regime once again to reduce rates and progressivity – meaning that tax take rises with commodity prices – and “we became dominant once again, and we hopefully picked up some of what we had missed out on in the 2009 period”, Foss said.

Alaska seems to be undergoing a similar shift. Changes to the tax regime in 2006-7 that introduced more progressivity appear to have precipitated a decline in investment and production that has contributed to operational challenges for the state’s Trans-Alaska Pipeline Syste, (TAPS), and concerns about the sustainability of its Permanent Fund, which receives and invests a share of the state’s resource income – lease income, royalties, etc – and pays out dividends from investment earnings.

Alaska passed revisions to its fiscal regime this year in an attempt to reinvigorate oil company interest in the state. “It has improved the situation, and it is, in my opinion, going to generate additional investment – for our company that certainly is true,” Kah said. “We’re already working on moving another rig into Kuparuk.”

But Kah noted that Alaska’s improved fiscal terms may still not enable it to compete with other global opportunities. “Alaska is a high-cost region compared to other places in the Lower 48 that we’re investing in,” Kah said.

“The capital’s going to be higher in Alaska, the operating cost is going to be higher in Alaska, so if you look at the divisible income – the share that both the state and companies get to divide – it’s going to be much smaller,” Kah said. “You can’t just have competitive rates to attract investment in Alaska, you need to be able to offset or compensate for the higher costs to give the companies the same return that they would get in a place that had lower costs.”