Alaska's Legacy Thaws Out

The era of the independents is taking hold in the so-called forgotten frontier of Alaskan oil and gas.

In a state where a “small” field holds 50- to 150 million barrels of oil, Alaska still has secrets up its sleeve. And smaller and midsize companies are quickly catching on, buying up legacy fields from major operators and making discoveries that, by non-Alaskan standards, are substantial. The pace of exploration promises more development in 2013. In some areas, production is just starting up for the new arrivals, which are adapting to a forbidding environment where equipment is often hauled on roads built of ice.

Challenges and opportunities remain, of course. The state’s tax structure could hurt the oil and gas industry, officials say. And the North Slope’s potential for shale production is still on the horizon.

In Juneau, Cook Inlet is foremost on officials’ minds. Concerns about the inlet’s natural gas supplies, and even brownouts by 2014 to 2015, have led to alternative plans, including trucking in natural gas.

Nevertheless, the region is being transformed, as Chevron and Marathon Oil Corp. sell out to smaller companies specializing in reworking wells and resurrecting mature oil and gas fields.

The star of 2012 was Hilcorp Alaska LLC, Anchorage, which won control of most of Cook Inlet’s production in a deal that was to be finalized in January of this year. The company’s net leasehold is 165,926 acres.

Hilcorp Alaska and Apache Corp. are wagering on Cook Inlet potential.

In a $375-million deal, Hilcorp took over Houston-based Marathon Oil’s Alaskan assets, solidifying Hilcorp’s position with control of most gas storage and pipeline infrastructure in south-central Alaska. The company plans to spend at least $200 million over the next two years in development in the region, in addition to the $200 million it spent in 2012.

“Overall, the Marathon assets in Cook Inlet fit our business model well,” says Lori Nelson, Hilcorp’s manager for external affairs in Alaska. “Hilcorp has had great success with acquiring and developing challenging, mature legacy oil and gas fields.”

Nelson said that in the short term, Hilcorp will focus on managing its Cook Inlet assets and building an inventory of additional development and exploration opportunities. After an assessment, it will target areas that best meet its objectives.

“Ultimately, we plan to develop our assets in Cook Inlet to their full potential, providing a reliable energy source for south-central Alaska while creating value for our company, our employees and our community,” Nelson says.

Joe Balash, deputy commissioner, Alaska Department of Natural Resources, says Hilcorp has seen threefold returns on reserves purchased in other parts of North America. He notes that in a little more than a year, Hilcorp has increased production across the board, even if only modestly, on the Chevron Alaskan assets it acquired prior to the Marathon acquisition.

“We are quite optimistic that this will ultimately be a very good thing in the inlet,” Balash says.

Apache Corp. is also wagering on Cook Inlet, investing in 3-D seismic in hopes it can prove up sizeable quantities of oil. The company has been tight-lipped about its geologic theories but has launched a basinwide survey onshore and off. The U.S. Geological Survey (USGS) said in 2011 technically recoverable oil resources in the basin are 600 million barrels, although Apache believes far more are within reach.

“Apache has a pretty good record in terms of sniffing things out, and taking advantage of first-mover opportunities,” Balash says.

The E&P sector is also making strides in the state’s main oil-producing region, the North Slope. Due to the seasonal window afforded to companies relying on ice roads to move equipment beyond existing infrastructure, competition is high for a small number of rigs.

New entrants include large integrateds such as Spain’s Repsol E&P USA, which is running a three-rig program west of Kuparuk Field. Smaller operators, such as Great Bear Petroleum LLC, Anchorage, are testing unconventional resources in the Shublik, Kingak and highly radioactive zones of source rock similar to the Bakken or Eagle Ford shales.

And, after a drawn-out struggle, the state has resolved a suit with ExxonMobil to allow work to begin at Point Thomson, a massive field holding more than a fifth of the North Slope’s known natural gas—an estimated 8 trillion cubic feet (Tcf) of natural gas and hundreds of millions of barrels of oil and condensate.

Despite declines in oil production to 600,000 barrels per day in 2011 from 2.2 million barrels per day in 1988, the North Slope still entices. And technology is adding to the state’s allure.

Armstrong Oil & Gas Inc., Denver, has invested more than $20 million in lease sales covering lands on the North Slope.

Bill Armstrong, president, has led several companies into Alaska, including the first large independent, Pioneer Natural Resources Co. He is working with Repsol to explore zones that were previously too difficult to develop.

“The biggest problem with Alaska, unlike the Eagle Ford or Permian, is there are not a whole lot of players trying to crack the code,” Arm-strong says. “Once one guy cracks it, everybody just piles in.”

E&P in Alaska has been limited to a few companies, as geologists’ lack of familiarity with the North Slope’s stratigraphy and oil plays has contributed to a perception of its resource plays as “a forgotten frontier,” says Mohamed Abdel-Rahman, Royale Energy Inc.’s vice president of E&P. The San Diego-based company in September 2012 announced plans to develop its acreage in Alaska, which is near Great Bear’s holdings.

Hilcorp’s Inlet

Roughly 60 years ago, gas was discovered at Deep Creek and Kenai in Cook Inlet. So much gas, in fact, that the U.S. authorized its only liquefied natural gas (LNG) exporting site, converting billions of cubic feet for shipment to Japan. Over the years, the basin produced 7.8 Tcf.

The gas seemed limitless. But a report by Petrotechnical Resources Alaska reviewed by Alaskan lawmakers on January 21 found the Inlet’s gas supply would be unable to keep up with anticipated demand by 2014-2015.

Hilcorp was ready to step in. The Houston company secured regulatory approval of its mammoth deal with Marathon in January and now takes command of nearly 70% of the natural gas produced in Cook Inlet, according to the Alaska Attorney General’s office.

Nelson says Hilcorp is committed to a longterm capital investment plan that “aims at slowing decline and increasing production from existing, aging fields.”

Still, the company’s market share is so large that the Federal Trade Commission held an inquiry and appeared to be leaning toward disapproval, Balash says.

State authorities worked with Hilcorp to set caps on prices for local utilities and industry. The company agreed to a base cap of $6.60 per million Btu—prices Lower 48 producers would salivate over—rising to $7.72 in 2017, according to a January 17 consent decree. The company will not export gas.

Marathon gave up 10 productive fields that had made it one of the largest natural gas producers in the basin. Hilcorp, one of the largest privately held independents in the U.S., also took over net proved reserves of 17 million barrels of oil equivalent in Cook Inlet and acquired storage and interests in natural gas pipeline transmission systems.

The deal follows Hilcorp’s December 2011 acquisition of Chevron’s holdings in southern Alaska. In that deal, Hilcorp purchased onshore gas fields, 10 offshore platforms, two gas-storage facilities and two pipeline companies.

With Marathon’s infrastructure, Hilcorp con- trols all proprietary gas-storage capacity in south-central Alaska and the majority of pipeline infrastructure necessary to deliver gas to customers.

Energy security and local energy supply shortages are at the heart of the state’s recent actions.

Operators are looking at application of shale technology on the North Slope.

“Hilcorp has a proven track record of reinvigorating old fields by consolidating ownership and aggressive reinvestment,” Nelson says. “The consolidation of interests in those fields is a natural progression in the life cycle of any mature oil and gas province. It simply facilitates and accelerates our ability to chart a new path forward and increases our ability to efficiently and effectively support Alaska’s energy needs.”

Balash says it was disappointing to see Marathon leave the state, but the company had curtailed its investment in Cook Inlet for the past couple of years, “doing what was necessary to meet their contractual obligations but little else.”

“Hilcorp brings a balance sheet, a willingness to invest and produce,” he says.

The company believes it can streamline discovery, development and production while providing geographic alignment for its onshore fields on the east side of Cook Inlet. In 2011, the USGS estimated the region still holds an estimated 19 Tcf of natural gas that could be produced using current technology, though the amount that could be profitably produced may be as little as 10%.

In 2011, Marathon’s net production averaged about 93 million cubic feet of natural gas per day from Alaska. Marathon had roughly 12.5 billion cubic feet of natural gas in storage at the end of 2011.

Hilcorp plans to increase production in 2013 while pursuing new opportunities.

“Folks can expect more of the same in 2013,” Nelson says, “lots of activity in the field and continued investment. We plan to spend in excess of $200 million in Alaska again this year. We hope the increased activity will help to rebuild the local service industry.”

Projects include identifying a mobile rig solution for offshore.

Hilcorp will also revisit the area where the first discoveries were made; it recently launched a seismic survey of the Deep Creek unit.

“We are hopeful the data will lead us to further gas development in that area,” Nelson says.

Armstrong Oil & Gas also has taken note of supply issues in Cook Inlet. Beginning four years ago, the company expanded the natural gas infrastructure more than 20 miles to develop North Fork Unit, a field discovered decades earlier but never developed. Armstrong and its partners are now producing more than 13 million cubic feet per day, with additional developmental drilling planned.

Inside the Inlet

The heyday of Cook Inlet was brief: In the 1950s and 1960s about 1.4 billion barrels of oil were discovered. But after the Prudhoe Bay discovery on the North Slope, explorers largely turned their backs on the inlet.

Prior to Hilcorp’s deal, there were signs that the region’s hydrocarbon potential was far from depleted. In 2011 and 2012, the inlet saw some of the highest lease sale activity in decades, with nearly $18 million in bids. Companies have invested hundreds of millions of dollars in the area. And rigs have increased, tallying 17 in November 2012 from nine in 2006.

In early 2012, Cook Inlet Energy LLC received an exploration license for 25,764 acres.

Apache took the next big step, embarking on a 3-D seismic survey. It has access to 1 million net acres in the inlet. It spudded its first well there in fourth-quarter 2012.

John Bedingfield, Apache’s vice president of worldwide exploration and new ventures, told investors in 2012 the inlet is a forgotten, but proven basin.

“When you go up there, it’s kind of like going back in time,” Bedingfield said. “Things have just been frozen for 40-plus years.”

Bedingfield said only a handful of fields have been discovered in Cook Inlet, and that field size distribution suggests at least 1.3- to 1.4 billion barrels of oil remain to be discovered, considerably more than the USGS assessment in 2011.

Trap analysis has also detected hydrocarbons, which Bedingfield said “doesn’t mean that they’re commercial. But every trap has hydrocarbons.”

The key to unlocking the play will be 3-D seismic, he said. An initial survey of 20 square miles resulted in identification of eight leads. A rough extrapolation of that density suggests as many as 650 potential leads in the inlet, Bedingfield said.

Apache’s 3-D acquisition program employs the industry’s first true cable-free wireless seismic technology in order to limit disturbance of communities, wildlife and the environment.

The company has also been making exploration plans; Apache and Cook Inlet Region Inc. have announced they will explore for oil and natural gas in the basin.

“The implication is that activity is going to be much higher than we originally anticipated,” Bedingfield said.

He noted that the inlet’s fields are extremely complex. “We have fields in Cook Inlet with a surface area of only 800 acres that hold 100 million barrels of oil,” he said. “We feel like we’re in a very good position to capitalize on the opportunity.”

Climbing the slope

Underground, all is good on the North Slope. The basin has “a ridiculous amount of opportunity” from a geological standpoint, Armstrong says.

The problems are aboveground.

“It’s wicked cold, it’s a remote place and so costs are higher because of that. It’s dark in winter time, below zero a significant amount of time,” he says. “The infrastructure is dominated by the majors.”

Yet activity on the North Slope, which holds more than 35 Tcf of discovered natural gas, hasn’t stopped. In November, companies bought lease rights to 165,000 acres for $11.5 million.

Notably, an old spat between Alaska and ExxonMobil has ended, with the company’s launch of construction at Point Thomson. And ExxonMobil, ConocoPhillips and BP have aligned with the Alaska Pipeline Project (APP) to build a gas line with TransCanada to bring North Slope gas to a tidewater location in south-central Alaska. The project could cost $45- to $65 billion and require 1.7 million tons of steel.

Despite their hold on Alaskan production, the majors are starting to see independents encroach.

The USGS pegs the likely field size for undiscovered resources at between 50- and 150 million barrels, Balash says.

“Those field sizes are not attracting (or) have not attracted the attention of the supermajors operating our legacy assets, so these new entrants are providing a shot in the arm to oilfield service contractors,” Balash says.

Brooks Range Petroleum, for instance, is positioned near the giant Point Thomson development and believes it will provide opportunities for several 50- to 100-millionbarrel discoveries. In 2013, Brooks plans to drill exploration wells in several areas; under consideration are the Putu, Kachemak, Tofkat and Beechey Point units.

Pioneer is moving forward with its drilling program, including a winter exploration program that added 50 million barrels of oil to its onshore Torok well, the company says.

In third-quarter 2012, Pioneer produced a net 4,500 barrels of oil per day. A one-rig development effort is continuing from the Oooguruk island drillsite, targeting Nuiqsut and Torok intervals.

In first-quarter 2012, the company completed its first successful mechanically diverted fracture stimulation of a Nuiqsut interval well. Based on its success, it’s drilling four more wells that will be stimulated early in 2013. A second onshore Torok appraisal well is to be drilled this quarter.

Armstrong says the joint venture between Repsol and his company involves more than 500,000 acres. “What we’re chasing would be referred to as low-hanging fruit in the Lower 48, ridiculously low-hanging fruit,” he says.

But Repsol and Armstrong will be using different drilling and completion techniques than those deployed in the past on the North Slope. Rather, they will use state-of-the-art drilling and completion techniques developed in the Lower 48 shale plays.

Shale shock

Alaska is at a turning point, some producers and state officials say.

In June 2012, Alaska’s contribution to U.S. total oil production was 7.9%, a far cry from a quarter century ago, when the state contributed 25%. Less than 25% of the Trans-Alaska pipeline’s maximum daily capacity of 2.1 million barrels is being used.

From 2007 to 2011, annual oil production dropped 22%, a precipitous decline to 223 million barrels from 285 million in 2007. Most production is from the North Slope, which yielded 219 million barrels in 2011. And shale development in the Lower 48 has so dominated the oil and gas industry that North Dakota’s oil production recently surpassed Alaska’s for the first time.

On January 15, Gov. Sean Parnell proposed tax reforms to help Alaska compete as oil production from legacy fields declines.

Alaska is not running out of oil, but “we are running behind the competition,” Parnell says.

Alaska’s North Slope has billions of proven barrels of oil, but Parnell argues that the state’s progressive taxes take far more profit from investors than in North Dakota, Alberta or Texas, for example.

“Investors take their money where they get a greater return, and they are investing new capital elsewhere,” he says.

Parnell wants to end monthly progressive taxes and maintain a 25% base tax rate with a 20% gross revenue exclusion for new oil.

Armstrong calls the current tax regime confiscatory. While he believes that the tax law has “crushed development of new fields on the North Slope,” he thinks Governor Parnell’s tax bill, if passed, will provide the vision and leadership needed to put the North Slope back on top as one of the preeminent petroleum basins in the world.

Balash says Alaska has struggled at times with the oil tax regime.

“I think that’s a big part of what will be focused on here,” he says. “In our view, Alaska is sort of poised to have really great things happen or will miss out on the boom going on around the world. This is a prolific resource that, if shown to be economic, could be a real game-changer on the Slope.”

Unfortunately, the costs may be too high for development to be economic. But companies such as Great Bear have the support of private-equity funder Riverstone Holdings, and Halliburton. And Royale Energy is pursuing acreage that is mainly focused on shale plays.

“They should know a lot more about how the rocks will perform in flow tests later this year,” Balash says.

In a November North Slope lease sale, Great Bear spent $749,000 for 24,480 acres.

Repsol bought 24 tracts comprising 39,040 acres.

Armstrong notes that operators have only recently begun to use long horizontals with multistage fracs on the North Slope.

Pioneer has produced more than 500,000 barrels of oil in just six months, he says.

“The North Slope of Alaska has three extremely rich mature source rocks,” he says. “It’s a little bit like the Bakken or the Eagle Ford times three. Nobody ever tried to make an unconventional play up there.”

Until now.