n January 2018, the Anchorage Economic Development Corporation (AEDC) projected that after an enduring economic recession, things were beginning to look up for the oil and gas sector. One year later, it appears AEDC’s forecasts were correct. Bolstered by new legislation, new discoveries, and increased levels of production, 2018 was a fairly fruitful year for the oil and gas industry.

Optimism regarding Alaska’s slow crawl out of recession began at the end of 2017 with the federal government’s decision to open the 1002 Area of the Arctic National Wildlife Refuge (ANWR) to oil and gas leasing. The decision—included as a provision in the passage of the federal tax overhaul bill—was a major milestone in Alaska’s long history of oil exploration.

“This is a watershed moment for Alaska and all of America,” US Senator Lisa Murkowski remarked in a December 2017 press release. “We have fought to open the 1002 Area for a very long time, and now our day has finally arrived.” Her sentiment was echoed by US Representative Don Young, who noted that he has advocated opening ANWR for the last thirty-seven years.

Although the 1002 Area is just one ten-thousandth of all of ANWR’s total acreage, it has the potential to bring an estimated 10.4 billion barrels of oil to market. According to Alaska Oil and Gas Association (AOGA) President and CEO Kara Moriarty, production is about ten to fifteen years away. However, in April 2018, the Bureau of Land Management said that it was beginning to prepare an environmental impact statement (EIS) for a leasing program in the 1002 Area.

Choosing the ideal site for the Alaska LNG terminal proved controversial in 2018. Federal law requires that an EIS consider not only the applicant’s preferred construction plans but also any economical or environmentally-friendly alternatives. Determining the best terminal location is key for Alaska LNG to move forward. With so much at stake, it is of little surprise that discussions between the Federal Energy Regulatory Commission (FERC), the Alaska Gasline Development Corporation (AGDC), the Matanuska-Susitna Borough, and the Kenai Peninsula Borough went back and forth all year.

In 2017, FERC ordered AGDC to evaluate Port MacKenzie in the Mat-Su Borough as an alternative location for the terminal of the Alaska LNG pipeline. AGDC complied, but in January 2018 the borough filed a complaint with FERC noting that AGDC had misidentified Port MacKenzie and subsequently evaluated the wrong location. AGDC turned its efforts toward the evaluation of the correction location of Port MacKenzie, and after several months of additional analysis, AGDC deemed the correct location inadequate, asserting again that Nikiski was best suited for the terminal. Not surprisingly, the Mat-Su Borough disagreed with AGDC’s assessment.

The Mat-Su Borough argued that AGDC presented “numerous factual errors and willfully misleading statements” to federal regulators and failed to perform “a good faith and unbiased analysis” of borough land at Port MacKenzie. AGDC responded by calling the Mat-Su Borough’s claim “baseless.”

On November 20, AGDC reaffirmed its initial filing, citing several geographic impairments of Port MacKenzie. First, Port MacKenzie’s existing deep-water dock would need to be removed to make room for significant expansion of the barge dock. Second, the port’s haul road would need to be widened from 45 feet to 150 feet to accommodate large-scale construction components. Third, the road would also need to be reduced to a maximum of a 3 percent grade. As the bluff at Port MacKenzie is higher than the proposed Nikiski site, the expansion would require a significant increase to the cut and fill required to build the road.

For now, AGDC continues to work toward making its pitch to potential investors in early 2019. If all goes according to plan, AGDC hopes to begin construction in 2020 in Nikiski with liquefied natural gas (LNG) production estimated to begin in 2024.

For much of the first half of 2018, the uncertainty of Alaska’s fiscal policy was an area of contention for those in the oil and gas industry. On June 7, Hilcorp, ExxonMobil, and SAExploration filed a lawsuit against the state Department of Revenue over what they asserted was a change in tax policy that could cost companies tens of millions of dollars. The dispute centered on a Senate Bill 21 provision that has been referred to as a “sliding scale” tax credit.

The provision enabled companies to apply the tax credit to each barrel of oil production with the value increasing as oil prices sink. When Senate Bill 21 was signed into law, it dictated that the sliding scale could not be used to reduce a company’s taxes below a set minimum. During the first few years of the law, some companies were able to pay less than the minimum required through a loophole in the law’s language. In 2017, the loophole was closed via an advisory bulletin and it caused a ruckus within the industry.

SAExploration—a non-producing oil exploration company—had planned to sell its tax credits to another company that would then use SAExploration’s credits to reduce its tax bill. But the state’s tax bulletin now bars that practice, which has “drastically reduced” the value of SAExploration’s credits, the complaint states.

As of the writing of this article, a decision had not been reached by the state’s Superior Court.

After years of paying only partial tax credits to developers, the state owed various companies about $900 million in tax credits. Talks of future investment were contingent on a solution being found to address the debt while financing the state government’s operating budget. The solution seemed to be House Bill 331, which would allow the state to sell bonds to pay off the tax credits in a lump sum.

The bill passed the Alaska House in early May and the Senate at the end of an extended legislative session in June. However, the sales were halted soon after the legislation passed due to a lawsuit filed that argues against the bill’s constitutionality.

A ruling on the case was anticipated to be made in November but as of mid-December, the state’s motion to dismiss the suit has not been addressed by the state’s Superior Court.

More proof of increasing exploration and development interest in Alaska was evidenced by a record-shattering annual North Slope oil and gas lease sale in November. The state received a total of $28.1 million from 159 bids for areas in the North Slope, Beaufort Sea, and North Slope Foothills. The previous year’s sale was the third largest ranked by bonus bid amount and bid per acre since 1998, when areawide oil and gas leasing began. 2018’s sale exceeded both marks, with total bid amounts increasing from $27.3 million in 2017 to $28.1 million in 2018, while the bid per acre amount leaped from $110 per acre to $121 per acre.

In a September letter to state officials, Alyeska Pipeline Service Company President Tom Barrett announced that the company would be “realigning into three divisions: operations and maintenance; engineering and risk; and chief financial officer.” As a result, many jobs would be directly or indirectly impacted, including a reduction of the Trans Alaska Pipeline System (TAPS) workforce by 10 percent.

The move, according to Barrett, is an effort to simplify operations. After launching an initiative in 2017 to understand the necessary actions needed to keep TAPS technically and economically viable, Alyeska presented a strategy that was endorsed by TAPS owners.

“As we move implementation forward, we will apply sound personnel processes designed to provide fairness, respect, and support for affected employees,” Barrett assured officials.

The US Department of the Interior’s Bureau of Ocean Energy Management issued conditional approval to Hilcorp Alaska for its Liberty Project oil and gas development and production plan in 2018. The project (co-funded by Hilcorp, BP, and ASRC Exploration) has the potential to be the first oil and gas production facility in federal waters off Alaska.

The largest undeveloped, light-oil reservoir on the North Slope, the Liberty Project predicts to unearth an estimated 80 million to 150 million barrels of recoverable oil. Peak production of between 60,000 and 70,000 barrels per day is projected within two years of initial production, and the field has a life expectancy of fifteen to twenty years. The proposed nine-acre artificial gravel island would be housed in the shallow waters of the Beaufort Sea, about 20 miles east of Prudhoe Bay. A buried subsea pipeline would carry sales-grade crude oil to shore, to connect with the existing Badami pipeline.

According to Liberty Project Manager Mike Dunn, construction of the artificial island is set to take place in 2020 and 2021. Construction of the subsea pipeline is projected to begin in the winter of 2021, and Hilcorp plans to move the various modules to the island during the following summer, with the drilling rig being moved within that same summer timeframe. Startup of the facilities is planned for May 2023.

In May 2018, AGDC entered into a Cooperation Agreement with BP to collaborate in the development of the financial and tolling structure to advance the Alaska LNG project. BP will contribute staff, resources, and selection of third-party contractors to assist in developing a commercial structure for the project to enable project financing. The agreement was punctuated in September with a “historic milestone,” a sales agreement between BP and AGDC in which an estimated 30 trillion cubic feet of gas from Prudhoe Bay would travel through an 800-mile pipeline to Nikiski, where it would be turned into LNG at a plant before being shipped overseas. However, many are quick to caution against unwarranted optimism as it will take several additional gas sales agreements to realize the LNG project. According to AOGA President and CEO Kara Moriarty, this initial agreement is only one piece of a much larger puzzle.

While BP remains the sole operator in the Prudhoe Bay oilfield, in July the company agreed to sell its 39.2 percent stake in the Kuparuk River Unit to ConocoPhillips in exchange for an increased share in the Clair field, which is part of BP’s North Sea operations in Scottish territorial waters.

The transaction was one of several that established ConocoPhillips as the single working interest owner in the Kuparuk River Unit, and in addition, ConocoPhillips purchased Anadarko Petroleum Corporation’s assets in the Colville River and Greater Mooses Tooth (GMT) units for $400 million earlier in the year.

The Kuparuk transactions were just a portion of an aggressive exploration pursuit made by ConocoPhillips in 2018.

In April, the company announced it had achieved a North American drilling record and two State of Alaska drilling records at drill site CD5 in the Colville River Unit on Alaska’s North Slope. With the help of the Doyon 19 drilling rig, ConocoPhillips drilled the longest horizontal lateral at 21,748 feet to claim the North American drilling record. Their two Alaska records were set with a total combined lateral length of 34,211 feet and total combined footage for a well at 42,993 feet. At the time of the records, CD5 was exceeding its original production target of 16,000 barrels per day.

Oil Search, based out of Papua, New Guinea, purchased $400 million of Alaska assets from Armstrong. Included in those assets were a 25.5 percent interest in the Pikka Unit and adjacent exploration acreage as well as a 37.5 percent interest in the Horseshoe Block. The sites contain the Nanushuk field, thought to be one of the largest onshore conventional oil discoveries made in the United States in the last three decades.

Oil Search’s analysis suggests that the Nanushuk field and satellite fields contain approximately 500 million barrels of recoverable oil. Repsol, their joint venture partner, estimates that there are more than 1 billion barrels. For 2019, Oil Search plans to conduct further appraisal drilling to confirm the size of the resource.