Alaska exploration and production efforts have only scratched the surface of the state's significant oil and gas resources, Alaska Department of Natural Resources (DNR) Commissioner Dan Sullivan told Rigzone in a recent interview.
Alaska, which is twice the size of Texas at 586,412 square miles and the least densely populated U.S. state, not only has significant conventional oil and natural gas resources but unconventional resources as well. The state's resources include tens of billions of barrels of heavy oil, shale oil and viscous oil, and hundreds of trillions of cubic feet of shale gas, tight gas and gas hydrates.
The U.S. Geological Survey (USGS) estimates Alaska's North Slope to hold more oil than any other Arctic nation, with an estimated 40 billion barrels of conventional oil and over 200 trillion cubic feet (Tcf) of conventional natural gas. Alaska's Cook Inlet contains significant, undiscovered, technically recoverable resources that include 19 Tcf of gas, 600 million barrels of oil and 46 million barrels of natural gas liquids.
While there is no question about the size of resources underground in Alaska, the state is relatively underexplored compared to most hydrocarbon basins, with 500 exploration wells drilled on Alaska's North Slope to date versus 19,000 exploration wells drilled in Wyoming. Sullivan attributes this low level of exploration to cost competitiveness compared with other regions, the state's remoteness and Arctic conditions which some companies and potential investors may find intimidating.
But Alaska hopes to encourage additional exploration and development through reforms of its tax and permitting systems.
"The state recognizes the need to make Alaska a more cost competitive place," Sullivan told Rigzone.
To achieve this goal, the state is reforming its oil and gas tax regime. Introduced last month, Senate Bill (SB) 21, which was introduced to the Alaska State Legislature last month and is under consideration by both Alaska's House and Senate, would reform Alaska's Clear and Equitable Share (ACES) program. The bill implementing the ACES program was passed by the Alaskan legislation in November 2007 in a move to make Alaska more responsive to the high cost environment that existed in the state. In 2008, a move was made to amend the bill to increase the progressivity function and adjust the way the system workers.
The state's current production tax program, ACES, means that new development and existing production rank among the least competitive of global fiscal regimes at $80 per barrel of oil, and even at $100 per barrel and $120 per barrel, Sullivan said citing recent data from a Jan. 31 presentation by PFC Energys. Costs are significantly higher in Alaska versus the continental United States, or U.S. Lower 48, even compared to unconventionals. Meanwhile, the Alaskan government's take has grown significantly in recent years, meaning new project economics can be very challenging.
Between 2003 and 2012, North Slope oil production lagged behind production in other parts of the United States as well as other member countries of the Organisation for Economic Cooperation and Development, according to a recent analysis by Econ One Research. The state lags behind these other two groups in terms of exploration and development capital spending.
Under the current system, a 25 percent base rate tax is implemented on the production tax value, or the net value of the taxable oil after allowable operating, capital and transportation costs are deduced from the market value of oil, with the tax rate increasing with higher oil prices and/or profits.
The maximum tax under ACES is 75 percent of the production tax value for all fields, and a minimum tax of 4 percent of gross value at point of production when oil prices are above $25 per barrel, which is reduced to 0 percent at $15 per barrel. Under the ACES system, the effective tax rate after credits at $80 per barrel would be 21.5 percent, 32.0 percent at $100 per barrel, and 41.3 percent at $120 per barrel, according to Econ One Research.
SB 21 would establish a 25 percent flat net tax rate with no progression of taxes, eliminate the capital credit and state purchase of losses and establish a 20 percent gross revenue exclusion to incentivize oil production from new units or new participating areas in existing units. In considering the net value of new oil or gas produced, the cost of transferring oil to market is subtracted from the market price, then 20 percent of the gross value of production at the wellhead is subtracted. Then, the 25 percent tax rate is applied.
Because Alaska's tax is applied on a corporate and not field by field basis, the 20 percent gross revenue exclusion has the effect of lowering the tax rate on new oil being produced. Reducing costs is critical not only because of the heavy oil resources not yet produced in Alaska are more expensive to develop, but the smaller fields of around 50 million barrels which, because of logistics and costs, are more expensive to develop, Mike Pawlowski, advisor for petroleum fiscal systems for the State of Alaska's Department of Revenue, told Rigzone.
Under SB 21, losses could be carried forward and applied against a tax obligation when production occurs. Additionally, the new entrant credits would be extended through 2022 from 2016. No change would be made for the qualified capital expenditure credit and carry-forward annual loss credit for areas outside the North Slope.
The state needs billions of dollars in new investment to meet Alaska Gov. Sean Parnell's goal announced in 2011 to increase oil flow through the Trans-Alaska Pipeline System (TAPS) to one million barrels a day in a decade.
To reverse the decline in Alaska's oil production – the royalties from which help fund Alaska's roads, schools, libraries and public safety officers – Parnell has called for tax changes to attract the private capital needed to develop North Slope fields. Oil production flowing through the TAPS has been experiencing a 6 to 8 percent decline, and current production now averages approximately 600,000 barrels per day.
Alaska is also seeking to reform its oil and gas permitting process, which has posed an issue for some companies operating in Alaska, to make the system more timely and efficient. The state is almost in its third year of permitting reform, Sullivan noted. Strong bipartisan support exists for this reform which, although not at silver bullet, will make the system more timely and efficient.
Oil exploration and development is a significant driver in Alaska's private sector economy. One-third of Alaska's jobs can be tied to oil development and production, including not only oil industry jobs but related jobs in the state and local governments and the trade, construction and self-employment sectors, according to a 2011 Commonwealth North study.
Unlike the Lower 48, where the surge in shale gas supply has depressed natural gas prices, Alaskans pay significantly higher prices for gas-fired electric power. The state's citizens also pay higher prices at the gas pump. Encouraging exploration and production of Alaska's broad portfolio of resources will provide needed gas supply for Alaska and Hawaii, Sullivan commented.
The state already has a diverse array of oil and gas companies operating in Alaska, including Royal Dutch Shell plc, BP plc, ConocoPhillips, ExxonMobil, ENI S.p.A., Anadarko Petroleum Corp., Great Bear Petroleum and Linc Energy Ltd. Private equity groups such as Houston-based Riverstone are investing in Alaska.
"We like the diversity of companies," Sullivan said, noting that opportunities exist in Alaska for companies to develop conventional and unconventional resources in the same area. "But given the size of the basin and what we're trying to do, we want to encourage more companies to come here," Sullivan commented.
Oil and gas activity is on the upswing in Alaska, with the Point Thomson development moving forward after nearly seven years of litigation, Sullivan noted. Shale oil exploration is already ramping up and new operators are expanding production outside of existing units, such as at Oooguruk and Nikaitchuq, which are offshore oil fields in the Beaufort Sea.
Companies such as Apache Corporation, Hilcorp Energy Company, Buccaneer Energy Ltd. and ConocoPhillips also have invested hundreds of millions of dollars in Cook Inlet, where major 3D seismic programs are being conducted over large areas of the basin and exploratory drilling activity has grown from nine rigs in November 2006 to 17 rigs in November 2012. Cook Inlet activity has been boosted by tax incentives.
The state has also seen strong interest in oil and gas leasing in recent years. Alaska sold 108 tracts with total high bonus bids of $10.9 million in the June 2011 Cook Inlet lease sale, the highest number of lease sale bids in 28 years. In the May 2012 Cook Inlet lease sale, 44 tracts were sold that totaled over $6.8 million.
Alaska's Division of Oil and Gas in December 2011 received more than 300 bids from over 15 bidders for acreage on the North Slope, North Slope Foothills and the Beaufort Sea, totaling $21 million and marking one of the most successful sales in recent Alaska history. Two hundred and thirty nine tracts were sold, with total high bonus bids of $18.7 million. In the November 2012 lease sale, bids for all areas totaled over $14 million with 122 tracts sold. Tracts were sold in the Foothills area for the first time since 2009.
The benefits of developing Alaska's Outer Continental Shelf (OCS) oil and gas resources are significant for Alaska. Commercialization of oil and gas resources in the Beaufort OCS and Chukchi OCS could generate $97 billion and $96 billion in 2010 dollars respectively in revenues to federal, state and local governments over a 50-year period, according to a February 2011 study prepared for Shell Exploration and Production by Anchorage-based consulting firm Northern Economics.
Additionally, economic activity resulting from OCS development in the Beaufort and Chukchi seas could generate an annual average of 54,700 jobs across the United States, with an estimated cumulative payroll amounting to $145 billion in 2010 dollars over the next 50 years, including 30,100 jobs resulting from Beaufort OCS development and 24,600 jobs from Chukchi OCS development.
The decision of ExxonMobil, ConocoPhillips, BP and TransCanada Corporation to cooperate with each other to move development of the Point Thomson project marks a major benchmark in commercializing North Slope gas, Sullivan said.
Construction has begun on the multi-billion dollar project, which is expected to begin production within the next three years. Point Thomson holds approximately 8 Tcf of known gas reserves, plus hundreds of millions of barrels of liquid condensates and oil.
In March 2012, the four companies formally aligned to commercialize North Slope gas with a specific focus on a large scale liquefied natural gas (LNG) plant in south-central Alaska as an alternative to gas exports through Alberta. The alignment was announced shortly after the state of Alaska settled with ExxonMobil and other Point Thomson field leaseholders a court case that had lasted nearly seven years.
ExxonMobil will serve as operator for the Point Thomson project, located in northeast Alaska east of the Arctic National Wildlife Refuge, marking the first time ExxonMobil has been an operator on Alaska's North Slope. As part of the Point Thomson development, ExxonMobil also will build a 70,000 barrel per day capacity pipeline that will link into TAPS.
This pipeline will open new gas exploration opportunities for smaller companies, who will be allowed to link production to TAPS via the pipeline ExxonMobil is building. In addition to new gas production, the partners in the Point Thomson project have confirmed to DNR that the project is expected to sustain 600 to 700 jobs and provide peak employment of 2,400 jobs. Outside the AGIA framework, BP and ExxonMobil had been working on a competing Alberta/Lower 48 gasline project in Denali. The Denali project folded in 2011 due to declining Lower 48 gas prices and no customer commitments, and the ExxonMobil/TransCanada project continued until it switched focus to an LNG export project last year.
On Feb. 15, executives from BP, ConocoPhillips, ExxonMobil and TransCanada informed Alaska's governor that the concept selection phase for an Alaska LNG project has been completed. The project, which will cost between $45 billion and $65 billion, will be among the largest LNG projects in the world.
In a letter to Gov. Parnell, the companies outlined the project details. The project will include approximately 800 miles of 42-inch diameter pipeline, primarily underground, designed to transport between three and 3.5 billion cubic feet and up to eight compressor stations. A gas treatment plant with a footprint of between 150 and 250 acres will be located on the North Slope near Prudhoe Bay.
The LNG liquefaction plant will have three trains and capacity for between 15 and 18 million tons per annum. Two LNG storage tanks with 160,000 cubic meter capacity per tank and the terminal will have one loading jetty with two berths.
Five offtake points that can supply between 250 and 500 million standard cubic feet per day to local Alaskan consumers will be locate along the pipeline route.
Gov. Parnell said the concept selection represents historic progress.
"Never before has a gasline project been so specifically aligned and described in detail by the companies that have the capacity to build, fill, and operate it," Parnell commented. "A critical part of the concept selection is to ensure that Alaska's gas goes to Alaskans first, which will dramatically improve the quality of life and cost of living for many Alaskans."
Alaska is also working with the U.S. Department of Energy and the Japanese government to test methane gas hydrate potential on Alaska's North Slope and the Beaufort Sea. The Japanese government has an interest in the project, as a multi-year research program in deepwater gas hydrate exploration and production currently is underway in Japan, according to the USGS.
The United States and Japan are also collaborating on studying Japanese gas hydrate samples, which were taken from layers beneath the deep seafloor in the Nankai Trough offshore Japan. Japanese researchers are also conducting the first offshore production test to track how much methane can be released from deepwater gas hydrate deposits. Focus will be on the Nankai Trough, which is where the cores being studied now were recovered.
Gas hydrates are an ice-like substance formed when methane – and sometimes other gases – combine with water at specific pressure and temperature conditions. The USGS is studying gas hydrates worldwide, not only in Alaska but in India, Korea and the northern Gulf of Mexico.
Sullivan said the state has not yet successfully resolved issues associated with the Department of the Interior's management plan for the National Petroleum Reserve in Alaska (NPR-A), the B-2 Preferred Alternative proposed last August. The state withdrew from the planning process as a cooperating agency under the National Environmental Policy Act of 1969 because of repeated refusals by the Bureau of Land Management to consider the state's issues and concerns.
Alaskan officials have questioned whether the plan – which effectively prohibits oil and gas exploration and development on 11 million acres of the NPR-A by setting it aside as if it were a conservation system unit – which was set aside specifically for oil and gas exploration and production – was legal, Sullivan said.
In a letter written last month by Gov. Parnell to Interior Secretary Ken Salazar, Parnell told Salazar that the B-2 Preferred Alternative continues to selectively disregard Congressional direction provided by the Naval Petroleum Reserves Production Act of 1976. The congressional intent for the Production Act was for the Interior Secretary to minimize adverse impacts on the environment, not to prohibit oil and gas activities.
The B-2 alternative is based on the USGS's 2010 assessment of oil and gas resources, which significantly reduced previous estimates but did not include important geologic and geophysical data sets, Parnell commented. The assessment also did not benefit from complete review and input from local experts. Numerous aspects of the plan will also, if left unchanged, hamper construction of needed pipelines to transport offshore oil and gas to TAPS, and preclude oil and gas exploration and development in the NPR-A.
The Arctic Slope Regional Corporation and the North Slope Borough also expressed frustration with Interior's lack of meaningful consultation with tribal and other Native groups during the NPR-A Integrated Activity Plan/Environmental impact Statement for the B-2 alternative, saying that the Bureau of Land Management was siding with environmental groups outside the region rather than taking into account the viewpoint of those most directly impacted by the decision.
The two groups noted that BLM contradicted its previous statements that any changes made to the NPR-A IAP/EIA would be based on sound science, saying they could not find any ecological or biological significance assigned to four townships added to the unavailable for leasing category.
NPR-A was created in 1923 by President Warren G. Harding as a naval petroleum reserve; at that time, the United States was converting its Navy to run on oil instead of coal. The area was renamed the National Petroleum Reserve in 1976 and designated by Congress as a strategic oil and gas stockpile to meet the nation's energy needs.
Click here to visit DownstreamToday to read about Alaska's LNG export potential
Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.
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