Alaska’s oil and gas producers achieved what many thought was unthinkable last year. In state fiscal year 2014, which ended last June 30, there was almost zero decline in production. Output from producing oil fields averaged about 531,000 barrels per day, virtually the same as the previous year.
The surprising increase in output last year is now credited to more intensive drilling and “workovers” of older wells in the large producing fields of the North Slope. No new fields or major oil products came online during the year, so the increase in routine drilling and well-stimulus activities in the field is the only explanation.
Industry officials said an improved economic climate due to changes in the state oil production tax in 2013 was a major factor in increased activity. The tax change was made by the Legislature but Alaska voters endorsed it in August 2014 when they turned down a ballot referendum that would have repealed the tax change.
There were also increases in Cook Inlet oil production although the numbers were small compared with the Slope.
Indications in late 2014 are that the increased well work is continuing, but 2015 and 2016 may see even more drilling, with new drilling rigs being brought to the slope, and the start of production from new, smaller oil projects.
These include CD-5, a “satellite” of the Alpine field, that is now in construction; Mustang, a small field being developed by Brooks Range Petroleum; and Nuna, a new production pad near the Oooguruk field being developed by Caelus Energy, which purchased the assets in 2014 from Pioneer Natural Resources.
— Tim Bradner
2. Interior Energy Project unfinished
A year that started with an abundance of promise for the Interior Energy Project ended with a similar amount of uncertainty.
Beginning the year Jan. 14, the Alaska Industrial Development and Export Authority chose to partner with Colorado-based MHW Global Inc., based on a financial outline for the project the engineering and consulting firm had.
The challenging AIDEA-led plan to truck North Slope liquefied natural gas to Fairbanks kept its momentum in April when the authority’s board approved $23.1 million in loans to local gas utilities for distribution infrastructure. AIDEA also spent $1.8 million in spring on a North Slope parcel for its LNG plant.
While Fairbanks Natural Gas spent the summer building out its pipe network, other aspects of the IEP lost steam.
Financial agreements, including a critical gas supply contract, were delayed. The final cost of the primarily privately financed LNG plant remained a mystery.
The IEP team decided it would use a gas contract with BP offered up by Golden Valley Electric Association by October. Confusion about whether AIDEA would try to get its own contract slowed negotiations with BP, according to MWH.
The feasibility of hitting the project’s assumed target “burner tip” price of $15 per thousand cubic feet, or mcf, of natural gas was called into question by Golden Valley CEO Cory Borgeson and Interior Gas Utility chair Bob Shefchik in the fall.
Both said they thought the final price — disputed by the IEP team at the time — would be in the $20 per mcf range. At that price it’s believed conversion from fuel oil to natural gas boiler systems would be slowed and a subsequent lack of demand for gas could financially doom the project.
By the end of the year, the “financial close” with all project parties sought at one time by early November was not complete. The AIDEA board was left to determine at its Dec. 16 meeting if it wanted to extend its relationship with MWH for another 90 days — a contractual agreement that expires Dec. 31. The board had not announced a decision as of Dec. 22.
— Elwood Brehmer
3. Flint Hills closes
When Flint Hills Resources closed up its North Pole oil refinery June 1, the aftershocks were felt well beyond the small Interior town.
Most immediate was the loss of 81 jobs. Out of 126 positions in the state before the shutdown, the company kept 35 positions in the Interior and 10 at its Anchorage fuel terminal, according to Flint Hills.
Gasoline production ended May 1 and the facility’s crude processing unit was turned off at the start of June.
The February news of the impending closure left Golden Valley Electric Association looking for a new fuel oil source into spring. Flint Hills supplied the electric utility with between 1,200 and 1,700 barrels per day of naphtha and fuel oil.
It also put a cost burden on the neighboring PetroStar Inc. refinery, which shared the cost of pipelines that connected the refineries to the trans-Alaska Pipeline System, with Flint Hills.
The Alaska Railroad also took a hit; as it hauled up to 2 million tons of Flint Hills jet fuel from Fairbanks to Anchorage each year.
Asphalt for Northern Region road and airport projects was also more expensive this year because it had to be hauled up from Tesoro’s Nikiski refinery, according to Fairbanks-area contractors.
The State of Alaska got involved when Gov. Sean Parnell signed House Bill 287 that provided up to $10 million per year in tax credits for each of PetroStar’s two small refineries in North Pole and Valdez.
In March, the state also sued Flint Hills to see who is liable for cleanup of a sulfolane spill at the refinery.
— Elwood Brehmer
4. Hilcorp gets busy
Hilcorp Energy, Cook Inlet’s major oil producer, expanded its activities in 2014 to the North Slope with the acquisition of small properties from BP, and also entered the liquefied natural gas, or LNG, supply business with the purchase of a small LNG plant in the Matanuska-Susitna Borough previously owned by Fairbanks Natural Gas.
Fairbanks Natural Gas, or FNG, has operated the plant for years to supply its small gas distribution system in Fairbanks. The company purchased gas from Cook Inlet producers or from Enstar Natural Gas Co., the Southcentral regional utility, and trucked LNG to Fairbanks.
Hilcorp will continue to supply FNG’s trucks, which it owns and operates, but is also looking for ways to expand the service including shipping more LNG to Fairbanks if a planned LNG trucking operation from the North Slope falters.
In Cook Inlet, Hilcorp continued its programs of redevelopment of older oil and gas producing properties acquired in 2012 and 2013 from Chevron Corp. and Marathon Oil and Gas when those companies left Alaska.
In November, Hilcorp closed on its purchase of four North Slope properties from BP including interest in three producing fields, Northstar, Enidott and Milne Point, and one undeveloped property, the Liberty offshore field. Hilcorp now owns 100 percent of Northstar and Endicott and 50 percent of Milne Point, and will be operator at all three fields.
The company is also a 50 percent owner at Liberty with BP and will be operator. Hilcorp is to submit a development plan for Liberty to the U.S. Bureau of Ocean Energy and Management on Dec. 30 or 31, BOEM officials said.
This is regulatory requirement and Hilcorp has set no timetable as to when the company would develop Liberty, Hilcorp has said.
— Tim Bradner
5. Shell hopes to drill, once again
Shell submitted new exploration plans for its Chukchi Sea federal offshore leases in 2014 and is waiting once again for federal permission to actually explore. The company paid more than $2 billion for its leases in a 2008 federal lease sale and had spent more than $5 billion so far on its Alaska Arctic offshore program including the partial-drilling of two wells in 2012, one in the Chukchi Sea and one in the Beaufort Sea where the company also holds leases.
The Chukchi Sea is Shell’s top priority because of the prospects for major oil and gas discoveries. The company also made a discovery in the Chukchi, its “Burger” prospect, when it drilled it the early 1990s, although it was not then considered economically viable.
Shell has since done further tests at Burger, mainly advanced seismic work, but needs to complete exploration wells to determine its full potential.
Meanwhile the exploration is bogged down in a series of lawsuits and regulatory delays. Environmental groups challenged certain assumptions in the 2008 environmental impact statement for the Chukchi Sea, and a supplemental EIS has now been prepared and is to be finalized by the U.S. Bureau of Ocean Energy and Management in February, with a Record of Decision planned in March.
Shell must decide in March to begin preparations for 2015 summer drilling, which will involve two drilling vessels and a small fleet of support vessels.
6. Buccaneer files bankruptcy, leaves Alaska
It was a tough year for Buccaneer Energy Ltd. in Alaska, that’s for sure.
The Australia-based independent filed for Chapter 11 bankruptcy May 31 in a Houston federal Bankruptcy Court after deals to finance exploration fell through and it became embroiled in a dispute with Cook Inlet Region Inc. over gas royalties related to Buccaneer’s only producing assets, the Kenai Loop wells in their namesake city.
When it filed for bankruptcy protection, court records showed Buccaneer had liabilities of between $50 million and $100 million. It owed about $33 million to its 30 largest unsecured creditors at the time. Overall, Buccaneer owed more than $2.1 million to the State of Alaska and other state businesses.
A settlement with CIRI, which owns a property adjacent to the Kenai Loop pad, and the Department of Natural Resources, which also represents the state Mental Health Trust Land Office in the dispute, was close several times during the year but was never reached. Buccaneer acknowledged in Alaska Oil and Gas Conservation Commission hearings that it produced gas from a reservoir that CIRI had at least partial right to without a unit agreement.
Prior to filing bankruptcy, Buccaneer suspended and ultimately fired its CEO Curtis Burton, who turned around and sued the company for breach of contract.
The company also sold its 50 percent share of Kenai Offshore Ventures in January for about $24 million. KOV was a joint effort with the Alaska Industrial Development and Export Authority to bring the Endeavour jack-up rig to Cook Inlet.
AIDEA subsequently sold its share of KOV and the rig for $25.6 million in November to Ezion Holdings Ltd., which had purchased Buccaneer’s share as well.
The Endeavour is on its way to South Africa, according to AIDEA.
— Elwood Brehmer
7. LNG exports resume
ConocoPhillips resumed periodic shipments of liquefied natural gas, or LNG, from its existing plant at Nikiski, near Kenai, earlier this year. The plant had ceased regular LNG shipments to long-term customers in Japan in 2012 but made periodic shipments in 2013 on a “spot cargo” basis.
That was to help Japanese utilities facing an urgent need to import more LNG following a shutdown of the nation’s nuclear generation plants following a major earthquake and tsunami.
Following those shipments, the plant was maintained in a suspended status until shipments were resumed in late spring 2014 with five cargoes shipped in 2014, the last in October.
The plant is now back in suspended status because ConocoPhillips is reserving its Cook Inlet gas production for its utility customers in the region. Expectations are that periodic LNG shipments will resume in late spring following the winter high-demand period for the utilities.
While there are no longer year-around exports from the Kenai LNG facility, the presence of the plant and its infrastructure is important. ConocoPhillips has agreed to make the facility available for processing natural gas from other parties as well as its own gas, and has performed this service in the last two years, although the company says details of these commercial transactions are confidential.
In this role the plant, with its ability to export LNG, serves as a potential customer for companies exploring for gas. Without it the only customer for explorers are the regional gas and electric utilities, and the needs of those entities are being met by Hilcorp Energy with contracts that extend into 2018.
— Tim Bradner
8. Point Thomson one year closer
Point Thomson is hooked up to TAPS and first production is in sight.
A 22-mile pipeline connecting the natural gas field on the eastern edge of the North Slope to the trans-Alaska Pipeline System was completed in March and tested in July.
The 12-inch pipeline will carry natural gas liquids, or condensates. It has the capacity to carry 70,000 barrels per day. According to ExxonMobil, the development operator, about 10,000 barrels of condensates per day will be produced beginning sometime in 2016.
By late 2014, about $2.5 billion had been spent on the overall $4 billion project, ExxonMobil representatives said at the Resource Development Council for Alaska conference in November.
Point Thomson will open access to roughly 8 trillion cubic feet of natural gas, about a quarter of the total North Slope gas reserves. That makes its progress key to the prospective Alaska LNG Project.
Unlike Prudhoe Bay gas, it is a high-pressure gas field, which makes it easier to extract the high-quality condensates that are easily turned into fuels, such as diesel, according to project leaders.
If the liquefied natural gas export project moves forward, ExxonMobil estimates another $6 billion to $8 billion could be spent at Point Thomson to fully develop the gas field. That would include a 30-inch gas line to a treatment plant at Prudhoe Bay.
— Elwood Brehmer