Alaska’s energy scene heated up in December when E&P Buccaneer Energy Ltd. signed a contract to supply natural gas from Cook Inlet to ConocoPhillips. The deal enables the latter to resume exports of liquefied natural gas from its long-shuttered LNG terminal on the Kenai Peninsula. The announcement capped a banner year for Cook Inlet, which has flourished and languished by turns for decades.

Prior to the Buccaneer-ConocoPhillips agreement, the most significant of numerous recent developments in the inlet had been Houston-based Hilcorp Energy Co.’s arrival via its acquisition of Chevron’s entire holding in southern Alaska, and Apache Corp.’s high bid in the Alaskan lease sale held in June 2011.

Hilcorp, the third-largest private E&P in the U.S., acquired onshore gas fields, 10 offshore platforms, two gas-storage facilities and two pipeline companies from Chevron. The deal was expected to close by the end of 2011. Current net production for Chevron in Cook Inlet is 3,900 barrels of oil and 85 million cubic feet of natural gas per day.

While the Hilcorp acquisition represents a major long-term development for oil and gas in Alaska, the Buccaneer-ConocoPhillips contract signals an immediate change of fortune for Cook Inlet. The contract commenced when Buccaneer’s Kenai Loop # 1 started production in December 2011, and it will run through April 2012, with the potential to end earlier if construction of the Cook Inlet Natural Gas Storage (CINGSA) facility is completed.

Once the latter is on line, Buccaneer has a gas-sales contract in place with Enstar—the largest gas utility in Alaska. Enstar will purchase the Kenai Loop gas and inject it into CINGSA for storage and use at a later date.

The Buccaneer deal allows ConocoPhillips to resume regular LNG exports, which the company plans by mid-2012. At that point, ConocoPhillips and partner Marathon Oil Corp. can begin to build out, seeking further LNG sales—and the local gas to supply them.

The landed price for LNG in Japan has been as high as $15 per million Btu. Despite that lucrative market, ConocoPhillips had announced plans to cease operations at the Cook Inlet facility, citing declining regional production. Buccaneer has the ability to sell up to 2.5 billion cubic feet to ConocoPhillips under the contract. The pricing in the gas-sales contract is consistent with recently executed gas contracts, according to the companies.

As well as being a partner in the export terminal, Marathon Oil is also a major producer from the inlet. In 2010 the company averaged 104 million cubic feet of gas per day, representing 34% of the inlet’s total. It holds about 140,000 gross acres, 110,000 net, in Alaska. The company says it has no current exploration plans, but in July it named Wade Hutchings to the post of Alaska asset-team manager.

Given the flurry of recent activity around the inlet, new gas supplies could put the LNG unit in a strong position, even as a grassroots export terminal is being planned for 2015 at Kitimat, British Columbia. Notably, Apache Corp., which has the largest acreage position in Cook Inlet, is a partner with EOG Resources in the Kitimat project.

There is no shortage of potential supply. In June 2011, the U.S. Geological Survey increased its estimate of Cook Inlet reserves by almost 10 times, based on new technical information and including unconventional resources for the first time. The federal agency said the region contains an estimated mean of 19 trillion cubic feet (Tcf) of natural gas, 599 million barrels of oil, and 46 million barrels of natural gas liquids (NGLs).

The USGS assessment of undiscovered gas resources ranges from 4.9 Tcf to 39.7 Tcf (95% and 5% probability, respectively).

Activity in Cook Inlet has been heating up in the past year.

Classic evolution

In a classic basin evolution, the majors have left the inlet for the next big-game hunt, in this case the North Slope of Alaska. More recently, independents of all sizes, some private, have bought up acreage, commissioned new seismic surveys, redeveloped old wells, and spudded new ones in the inlet.

Hilcorp’s succession from Chevron is a case in point. The assets Hilcorp is acquiring include contracts and interests in the Granite Point, Middle Ground Shoals, Trading Bay and MacArthur River fields, as well as the Cook Inlet Pipe Line and Kenai Kachemak Pipeline.

These came to Chevron in its $18-billion acquisition of Union Oil of California (Unocal) in 2005. The Cook Inlet assets are not associated with Chevron’s North Slope fields nor its 1.4% stake in the Trans-Alaska Pipeline, which the company is retaining. Hilcorp declined to comment on its plans for the Cook Inlet until after the transaction had closed.

Despite the big Hilcorp deal, Apache is the big kid on the block. In June 2011, the state held its most successful lease sale in Cook Inlet in years, with 110 bids received versus 37 the prior year. Apache submitted the most high bids, with 91. According to the State Department of Natural Resources, Division of Oil and Gas (DNR-DOG), some 515,000 acres cost Apache roughly $9 million, or about $17.50 an acre. This acquisition more than doubled the company’s position to over 800,000 net acres.

“The Cook Inlet is a very underexplored, underexploited area for both oil and gas,” says John Hendrix, who was appointed general manager of Apache’s Alaska operations late in October 2011. The Anchorage posting is a homecoming for the native of Homer, Alaska, located some 200 miles southwest on the Kenai Peninsula.

“Just in the past few months we have begun extensive seismic surveys,” he says, “mostly onshore, but some in the transition zone, and mostly on the west side of the inlet. We will get to the offshore areas in the spring, then the east side of the inlet later in the year. We hope to cover 1,200 square miles over the next three years.”

Apache has no current production in Alaska, but Hendrix says the company hopes to find drillable prospects in 2012. “We are primarily looking for oil, but plenty of gas will come as well, and the Anchorage bowl needs gas. Local and state officials have shown a great deal of interest in developing supplies for the regional demand.”

The Apache and Hilcorp moves “tell you all you need to know about Cook Inlet,” says Curtis Burton, managing director and chief executive officer of Buccaneer. The company has purchased a jackup rig from Transocean, and plans to have it in service in the inlet by April or May of 2012.

“What you see happening in Cook Inlet is what happens in many basins,” says Burton. “The majors come in, identify the big finds and develop them, then move on. They don’t necessarily do that based on good science; it is just how they run their shops. We picked up some of our acres from Marathon. They were in the inlet for a long time, but now they are off to greener pastures in the Eagle Ford and other shale plays.”

Burton offers insight into the economics behind the shift from majors to independents: “The way one of the big guys did its accounting, production from Cook Inlet had to cover $80 a barrel overhead. Actual lifting costs were only about $20 a barrel. The private companies and independents have much lower overhead.”

He also notes that it was only in recent years that the state began courting smaller players, after decades of dealing with the majors. “The state has seen volumes on the Trans-Alaska Pipeline go from 2 million barrels a day to 600,000,” he notes.

What’s more, gas demand from utilities and industries in and around Anchorage is on the rise. So, the state began several programs to foster gas development. Says Burton: “One (program) that we are using pays 65 cents per dollar spent, cash—not tax credit—to compensate for development costs.”

Curtis Burton, managing director and chief executive officer of Buccaneer Energy Ltd., notes that only in recent years has Alaska begun courting smaller players, after decades of dealing with the majors.

The results of these stimulus programs have been clear: in 2008 there were only eight wells drilled in Cook Inlet, according to DNR-DOG. That more than doubled to 18 wells in 2009; producers posted 16 in 2010.

This trend, as well as the enthusiastic response to the most recent lease offering, marks quite a turnaround from prior years such as 2009, when Alaska received only five bids for Cook Inlet tracts. No new oilfield discovery has been made in Cook Inlet since 1991, and no new gas discovery since 1979.

Since oil and gas production began in the 180-mile-long Cook Inlet in 1958, more than 1.3 billion barrels of oil and 7.8 Tcf of gas have been produced, yet the new USGS numbers show that significant potential remains. Its esti- mate includes conventional and unconventional, or continuous, accumulations, including coalbed-methane gas and tight gas.

The recipe now cooking in the inlet is the result of many parties trying to balance supply and demand. When the first large discoveries were made by the majors decades ago, local industry was cultivated to use the supply not consumed by residential and commercial power and heat demand.

Three industrial users were established along the Kenai Peninsula. Today they are Tesoro’s 72,000-barrel-a-day refinery, the only LNG export terminal in North America, and a fertilizer plant owned by Agrium but shuttered.

“Development in the inlet has been in fits and starts,” says William Barron, director of DNR-DOG. “We have seen ebbs and flows as prospects are acquired, drilled, proved, produced and then depleted. Historically gas has been the target and oil has languished. Clearly now, with Apache and Hilcorp, as well as the many others, Cook Inlet is still a premium resource basin that is underexploited.”

That said, he notes that cumulatively there has been a lot of work done in the inlet, and several new players are reentering and reworking old wells using modern techniques.

“We have essentially a closed region here. It was difficult to convince the boards of the majors to spend on development. But companies like Apache and Hilcorp have great reputations for changing the operating and cost structures of a play. We are also seeing some investment by local guys who worked for the majors, and now are buying into the facilities they used to work on. These are very exciting times.”

Pirates of the Pacific

A good portion of the new interest in Cook Inlet is arriving by way of Australia. The highest profile has been taken by Buccaneer, which is listed on the Australian Securities Exchange. It has operations in the Gulf of Mexico and onshore Texas and Louisiana, and is listing on the TSX Venture Exchange in Canada.

The first well expected to be drilled by its new rig, renamed Endeavour, after Captain Cook’s vessel, will be its wholly owned Southern Cross prospect, where Netherland, Sewell & Associates has estimated proved and probable reserves of 12.7 million barrels of oil equivalent and an additional P-50 resource of 14.7 million barrels equivalent.

The Southern Cross project, in approximately 50 feet of water, faces no unusual technical hurdles to drill and develop, according to the company. It is within five miles of four significant oil and gas fields with a combined cumulative historical production of 1.1 billion barrels of oil and more than 550 billion cubic feet of gas.

Buccaneer’s initial test will offset several wells on its leasehold that tested oil and gas but were never produced. Its first well is some 1,700 feet from the Pan Am 17595 # 3 (circa 1960s), which tested 230 feet of oil and 1,080 feet of mud-cut oil from Lower Tyonek and 165 feet of oil from the Hemlock formation.

The test will also be structurally high to the Pan Am 17595 # 2 (also circa 1960s), which tested Lower Hemlock and recovered gas to the surface, followed by fluid from which 990 feet of clean oil was recovered. Other wells on the lease tested gas from Upper Tyonek. Buccaneer’s well will be within the demonstrated hydrocarbon column for the area.

“This basin has been untouched by a drillbit since 1993,” Burton says. “How far has drilling and completion technology advanced since then?”

The company has just concluded a deal to sell gas at an average price of $6.24 per thousand cubic feet (Mcf), with a floor of $6 and a ceiling of $10. “Where is Henry Hub today? $3 or $4?” Burton asks.

Linc Energy, based in Brisbane, Australia, came to Cook Inlet originally in quest of coal for its proprietary in-situ gasification technology, but it also has built a position of 122,000 net acres of oil and gas leases. The core of that was acquired from GeoPetro 18 months ago, according to Don Schofield, president of U.S. operations and based in Denver.

“Our first well, Lea 1, was drilled in Point Mackenzie Field north of Anchorage,” says Schofield. “We found gas, but we could not produce it, so we will continue to investigate the area. We are acquiring and shooting 2-D and 3-D seismic, using our in-house equipment, and will interpret it ourselves. We hope to have the analysis completed by midsummer.”

The company is also drilling on the west side of the inlet near the Beluga River, coring for coal suitable for gasification. The process produces syngas, which most likely would be sold to the Beluga Power Station a few miles away.

Northern lights

Not all of the excitement in Cook Inlet comes from new players. Aurora Gas is a current producer still in action from the last flurry of interest in the inlet a decade ago. Based in Houston, the company sells an average of 7 million cubic feet of gas a day from the inlet.

“We drilled two development wells in the Nicolai Creek and Three-Mile Creek fields,” says Ed Jones, president. “We completed four different Tyonek intervals. Current production from one well is 4 million cubic feet a day from the second-best interval. All the zones tested at least one million a day.”

The company’s existing wells are all reworks, acquired from four different companies. “Stepping out is the key to this development,” says Jones. “We have a 3-D seismic plan for 2012, and may do some more drilling.”

“If ours and other discoveries come in, we may start to see excess supply in the summer. Perhaps that will bring more industry, or more LNG. The situation is very fluid right now.”

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