What factors have the most impact on Alaska’s future oil and gas revenues?
Not the state’s fiscal system, Janak Mayer told the Senate Special Committee on TAPS Throughput Jan. 31. The largest revenue impact is from something over which the state has no control, he said: oil prices, followed by production rate. The Senate committee was wrapping up its throughput-focused review of the governor’s proposed tax changes as this issue of Petroleum News went to press, with the bill expected to move on to the Senate Resources Feb. 7 or Feb. 9.
Mayer, a manager in PFC Energy’s upstream practice and Tony Reinsch, senior director in the firm’s upstream practice, presented an overview of how companies make investment decisions, where Alaska fits in the portfolios of the major North Slope producers and how competitive investment is in Alaska under the state’s current production tax, Alaska’s Clear and Equitable Share, or ACES, compared to competitiveness under the governor’s tax change proposal, Senate Bill 21 (House Bill 72 is the companion bill).
PFC Energy is back for the second year, hired to advise the Alaska Legislature in oil tax change discussions.
Mayer also noted that production and price are related, as more projects will be economic — increasing production — in a period of sustained high oil prices, and conversely, in a period of sustained low prices fewer projects will be economic, decreasing production.
Current production decline is some 6 percent a year and to hold revenue flat that decline rate under the SB 21 proposal would need to drop to 1 percent, he said.
Because it removes progressivity, the governor’s proposal in SB 21 is slightly regressive — the state’s share of revenue drops somewhat as oil prices rise.
Mayer said PFC Energy was asked to look at what it would take to remove that regressivity. By adding back 0.1 percent progressivity, to a maximum 35 percent production tax, the state’s take would remain flat with rising prices. That 0.1 percent progressivity would also reduce the production decline level required to keep revenues constant from 1 percent to 2 percent.
The tinkering issueThe focus of PFC’s presentation was on how competitive Alaska is under the current fiscal system, compared to how competitive it could be under the changes proposed by the governor.
There is, however, another issue: Alaska, like Alberta, is perceived in the oil and gas industry as a jurisdiction that tinkers with its tax system and tries to micro manage.
That, PFC Energy told the committee, makes investment decisions difficult for companies.
Mayer said Alberta is characterized as having high sovereign risk because it frequently changes its oil and gas fiscal terms. The province also is seen as pulling levers in the system to attempt to manage at the micro level.
Both of those characterizations absolutely apply to Alaska, especially over the last several years, Mayer said.
In addition to instability due to fiscal system changes, the state has tended to take an approach based on pulling specific levers, he said, citing the tax credit provided for the first jack-up in Cook Inlet as an example of pulling micro levers in the fiscal system.
Changing project economicsCompanies want stability when making large capital investments with long payout periods, Mayer said. He said he could think of no better example of lack of fiscal stability in Alaska than Pioneer Natural Resources’ experience with its North Slope Oooguruk field.
The discovery and investment decision were made under ELF, Mayer said. That is the state’s former gross production tax, including an economic limit factor, hence the acronym ELF.
Oooguruk was challenged under ELF, Mayer said. (Pioneer applied for and received royalty relief for some of the leases in the project in 2005.) Although Oooguruk was a high-cost challenged project with a lot of issues, Pioneer sanctioned the project, he said.
That was in early 2006.
In the fall of 2006, during project development, the state passed PPT, the Petroleum Profits Tax, and by the time the field came into production in mid-2008, ACES or Alaska’s Clear and Equitable Share had been enacted.
The project economics were much, much more challenging under ACES than they were under ELF when the project was started, Mayer said.
Lots of potentialReinsch told committee members that industry sees a lot of potential in Alaska, but it is a very difficult operating environment and entry is difficult because there isn’t a lot of what he called “asset churn” with companies selling producing properties.
Offshore prospects are going to be very challenged, Reinsch said, citing Shell’s difficulties as an example. There is the question, he said, whether the technology is there to exploit the resource.
So while the state has many opportunities, Reinsch said he had yet to meet the oil and gas team that prefers chaos to stability when they are making multiyear investment decisions.
Minimizing tinkeringCommittee Co-Chair Mike Dunleavy asked if there were areas with minimum tinkering where companies are active.
Mayer said there were many examples, and cited two: the U.S. federal system and Australia.
There have been changes, he said, but both are systems with simple straightforward rules leaving private sector companies to compete within the system.
The Australia federal system is profit based, but the level of government take is the same at any price range, isn’t different for different types of projects and makes sure taxes are at a level to make the overall system competitive.
The U.S. federal offshore system is very regressive, with a fixed royalty, Mayer said, but is all about shedding risk from the government. Whereas typically signing bonuses, what a company pays for its leases, are so relatively small that PFC Energy doesn’t even model them, in the federal offshore those bonuses are very substantial, he said, substantial enough to impact project economics.
The federal offshore system takes risk from the public sector and puts it on the private sector, but at high oil prices the private sector can make very high returns.
Characteristics of both systems include long-term stability and an avoidance of micro managing, he said.
Co-Chair Peter Micciche wanted to know why economics are better in Texas than in Alaska, and Mayer said it’s a combination of a substantially lower cost of drilling in Texas and a substantially lower government take which produce better economics in Texas. Alaska, he said, has the burden of increasingly high costs.
The major playersIn a review of the portfolios of Alaska’s major players — BP, ConocoPhillips and ExxonMobil — Reinsch said all have faced major strategic challenges in the last few years: BP following the Macondo well disaster in the Gulf of Mexico; ConocoPhillips following its 2010 commitment to restructuring, a significant divestiture of assets and splitting the company; and ExxonMobil because of the challenge of replacing large international projects and its acquisition of XTO, which he described as almost the last play standing of material impact for ExxonMobil. XTO’s play type, however, isn’t one that makes sense for ExxonMobil, he said. They’re efficiency experts, Reinsch said, and are now into the treadmill game of drilling thousands of wells.
PFC Energy categorizes Alaska as a harvest area for both BP and ExxonMobil, but as a core area for ConocoPhillips.
Sen. Berta Gardner, the committee’s sole Democrat, asked if harvest mode didn’t mean that companies would simply take any monies from tax reductions and invest them elsewhere, to which Reinsch responded that, all things being equal, a better fiscal environment was positive for investment in an area.
Initial company reactionsThe governor’s proposal removes progressivity but also removes the 20 percent capital credit which was placed in ACES as a balance for progressivity.
In industry reactions on Feb. 5 — from the Alaska Oil and Gas Association, AOGA, and ConocoPhillips Alaska, the North Slope’s largest producer, the committee was told that removing progressivity was a positive, but removing the credits was a negative.
Kara Moriarty, the executive director of AOGA, said the organization’s members supported elimination of progressivity but were concerned with how the bill addressed tax credits. She said AOGA supported gross revenue exclusions (a 20 percent tax allowance for new oil, either from new units or new participating areas within existing units), but said the concept should be expanded to fit projects in legacy fields.
Bob Heinrich, vice president of finance for ConocoPhillips Alaska, and Scott Jepsen, the company’s vice president of external affairs, said the governor’s proposal would improve Alaska’s business climate and make the state more competitive at oil prices above $100 a barrel but didn’t do enough to encourage investment in legacy fields and didn’t encourage investment at lower oil prices.
Jepsen said the potential for additional oil production lies in the state’s legacy fields, and said taxes, along with high operating costs, are a problem for Alaska in attracting investment. He recommended eliminating progressivity and keeping the credits provided under ACES.
Heinrich said that of the billion dollars in credits frequently cited, less than half goes to producers, more than half to explorers. He also said cash margins for ConocoPhillips are “significantly less” in Alaska than in new projects in which the company is investing in the Lower 48 and said it is difficult to compare the company’s earnings in Alaska with those in the Lower 48, because in Alaska 90 percent of the company’s production is oil, whereas in the Lower 48 more than 70 percent of its production is gas and gas liquids, subject to current very low gas prices.
On a barrel of oil equivalent, which includes natural gas and natural gas liquids, there is higher net income per barrel in Alaska, he said, but not on an oil-to-oil comparison basis.
SB 21 impact at low pricesThe high Alaska tax rate impacts overall investment decisions, with ACES impacting cash flow in the long term, Jepsen said. He said Alaska is impaired in comparison to other investment opportunities because of the portion of profit taken in taxes and is just not able to attract discretionary cash for investments.
The “easy oil” on the North Slope is gone and what remains is challenged oil with complex, high-cost wells, smaller reserve targets, isolated fault blocks, satellites and viscous oil, Jepsen said.
Heinrich said that the proposed changes under SB 21 would increase the tax at lower oil prices, less than $93, and said that with high operating costs in Alaska, it doesn’t tilt the equation enough.
While SB 21 would make Alaska more competitive at prices above $100, that isn’t ConocoPhillips’ perspective on the price outlook, Heinrich said.
Jepsen noted that the potential for increased production lies primarily in legacy fields, and Heinrich said the gross revenue exclusion should be extended to legacy fields.