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Production revenues to continue to grow Revenue fall forecast pairs declining production forecast with increasing prices for increased state oil and gas revenues through FY 2012 Kristen Nelson Petroleum News
North Slope crude oil volumes may be going down, but prices are going up, producing increasing state oil revenues.
That was the bottom line from the Alaska Department of Revenue’s fall forecast. While it was gloomy on the subject of oil production — with projected volumes down from the spring forecast (see story in the Dec. 18 issue) — the department is forecasting increasing prices for Alaska North Slope crude oil, and as a result, increasing revenues.
Unrestricted petroleum revenue was $7.049 billion in the last fiscal year, 2011; it is forecast to be $8.215 billion in the current fiscal year, 2012, and then drop to $7.496 billion in FY 2013, $7.019 billion in FY 2014 and $6.314 billion in FY 2015.
Alaska North Slope crude oil production, which averaged 603,000 barrels per day in FY 2011, is forecast to drop to 574,000 bpd in FY 2012, 555,000 bpd in FY 2013, rebounding slightly in FY 2014 to 561,000 bpd and then dropping again in FY 2015 to 538,000 bpd.
The growth in unrestricted petroleum revenue, while production is dropping, is the result of the price.
The ANS wellhead value (ANS West Coast price less marine costs, the trans-Alaska oil pipeline tariff and other deductions and adjustments) is growing: From $87.32 per barrel in FY 2011 to a projected $100.61 per barrel this fiscal year, $100.91 in FY 2013, dropping to $100.25 in FY 2014 and to $99.61 in FY 2015.
Compare that to FY 2002, when the ANS wellhead value was $17.04 a barrel.
Price forecasting Estimates for oil revenues are based on crude oil prices, lease expenditures, transportation charges and crude oil production, Revenue said in its fall forecast (available online at www.tax.alaska.gov) that its oil price forecast is compiled from several sources, including a state price forecasting session, the New York Mercantile Exchange futures market (as of late October), oil market analysts’ forecasts and the U.S. Energy Information Administration.
In the short term, prices are influenced by inventory levels, economic fluctuations, infrastructure constraints and geopolitical and weather-related events, the department said. Fluctuations in the value of the U.S. dollar and changes in sentiments of trading buying and selling oil futures and options contracts also affect the price of oil, as does OPEC, the Organization of the Petroleum Exporting Countries, which tries to keep oil prices within a band by increasing and decreasing supply.
“In the long run,” the department said, “fundamental economic factors of supply and demand ultimately drive oil prices,” and predicting future prices requires an understanding of long-term economic growth, the demand for refined products, global crude reserves and “the economics and politics of recovering those reserves.”
Revenue said its price forecast for West Texas Intermediate and ANS “reflects a consensus view of stable oil demand growth and modest supply increases in the short and medium term. In the long term, the forecast reflects stabilizing oil demand growth that puts pressure on world oil production and tightens oil markets.”
WTI vs. ANS The differential between West Texas Intermediate and ANS crude oil prices has been a negative $2.50, with ANS selling at a $2.50 discount to WTI, but, the department said, because of a “divergence in price between WTI and other world crude oils, this assumption is no longer reasonable.”
The price of WTI began to diverge from other world crude oils in January 2011, a divergence most experts attribute to growing supply in Midwest and Western Canada and logistical constraints around Cushing, Okla., the delivery location of WTI, the department said.
Imports from Canada have increased 17 percent in the last three years and North Dakota production has more than doubled, flooding the Midwest and Cushing supply lines.
Revenue said that insufficient pipeline capacity “pushed WTI out of sync with other world markets.”
Long-term solutions to the problem aren’t expected to kick in until 2013 or 2014, but recent plans to reverse the Seaway pipeline in the second quarter of 2012 to take crude out of Cushing caused a sharp narrowing between WTI and other crudes.
Revenue said the Seaway announcement was made after its oil price forecast was completed, and is not reflected in the department’s forecast. The department said it assumes the ANS-WTI differential will return to its historical long-term average of negative $2.50 by FY 2017.
Lease expenditures In fiscal year 2011, unaudited lease expenditures reported to the department included $2.6 billion in operating expenditures and $2.3 billion in capital expenditures, Revenue said. Expenditures forecast for FY 2012 are $2.6 billion in operating expenditures and $2.7 billion in capital expenditures. Lease expenditures for FY 2013 are projected at $2.4 billion in operating expenditures and $3.1 billion in capital expenditures.
“For FY 2012 and 2013, we are forecasting higher capital expenditures with the majority of the increase occurring in currently undeveloped areas of the state,” the department said. Revenue said it included exploration and development plans by several newcomers to the state, “despite the speculative nature of those plans.”
Revenue said it is forecasting “a modest increase in tanker transportation costs per barrel” to maintain the integrity of the fleet.
Tariffs on the trans-Alaska oil pipeline are expected to escalate “as production declines and operating costs are spread over fewer units.
No undiscovered oil Revenue said it does not include undiscovered oil in its crude oil production forecasts, so the Arctic National Wildlife Refuge, most of the National Petroleum Reserve-Alaska and the federal outer continental shelf are excluded.
Most known heavy and viscous oil is also excluded, including all of the approximately 20 billion barrels from the Ugnu formation, “although one operator has initiated a pilot project at Milne Point to evaluate new technology termed CHOPS (Cold Heavy Oil Production with Sand), and another operator is evaluating thermal recovery technology for Ugnu at Kuparuk.”
More than 97 percent of viscous oil from the West Sak field is also excluded from the forecast, along with more than 93 percent of the heavy oil at Schrader Bluff.
“We exclude these resources, both known and unknown, in order to avoid speculation and to reduce the uncertainty typically associated with the commercialization, timing and magnitude of resource development.”
Oil that is included falls into three categories: that currently being produced; potential oil from projects under development; and potential production possible from projects under evaluation.
Revenue said it anticipates possible new developments on both state and federal lands in the next 10 years, with most of the opportunities to add production on state lands from “expanded heavy/viscous oil development (Orion), continued satellite development at Alpine (Nanuq and Alpine West fields), and continued developments at Oooguruk and Nikaitchuq.”
Revenue said Point Thomson production is forecast based on public statements.
“Production at the Umiat field is expected to begin within approximately five years.”
The department also listed Liberty development as under way, with “anticipated production starting in FY 2016.”
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