Which comes first, supply or demand?
That question quickly becomes chicken-and-egg tough when it pertains to the Cook Inlet natural gas market, where constrained demand impedes development of high-cost supply.
It is, at best, an untenable situation.
Natural gas produced from the Cook Inlet basin, which includes shore side developments on the Kenai Peninsula and to the west of the Inlet, exclusively supplies the energy needs of nearly 60 percent of Alaskans from the outlying areas of the Matanuska-Susitna Borough south to Homer.
Electricity generated at natural gas-fired power plants in Southcentral supplied more than a third of Interior’s power in 2014, according to Golden Valley Electric Association; and about 1,000 Fairbanks residents and businesses have rid themselves of their backyard fuel oil tanks since Fairbanks Natural Gas began providing them Cook Inlet-sourced gas via truck in 1998.
With no nearby alternative supply, those numbers exemplify the importance maintaining Inlet gas production: it means keeping the lights on and buildings warm in the economic heart of the state.
While those population centers have grown over the past 10 years, the demand for gas has not.
Alaska’s appetite for Inlet gas was mostly stable at roughly 200 billion cubic feet, or bcf, per year for more than 20 years from the mid-1980s until 2007. The impact of increased residential and commercial demand from population growth was muted by larger industrial needs — namely that of the Agrium Inc. nitrogen fertilizer plant in Nikiski, which closed in 2007 for lack of gas supply — and ConocoPhillips’ LNG exports to Japan.
At about the same time a confluence of factors hit the market hard. In late 2006, the Regulatory Commission of Alaska rejected a gas supply contract between Enstar Natural Gas Co. and Marathon Oil that was linked to Lower 48 Henry Hub market pricing. That ultimately resulted in a separation of pricing for the isolated Inlet gas from the indexed trading market.
Since the de-linking, shale gas has depressed Henry Hub to the $2 per thousand cubic feet, or mcf range, while Inlet gas has generally fluctuated between $6 and $8 per mcf.
The primary gas fields in the basin were also starting to show their age. Some had been producing oil and gas since the mid-1960s. Waning oil reserves made reinvestment uneconomic for the large operating companies at the time and consequently impacted gas production as well.
With Agrium’s annual demand of about 55 bcf off the table and little exploration occurring, gas demand, and production, fell sharply for years until stabilizing somewhat in 2013 to roughly the current level of about 100 bcf per year.
When the Southcentral utilities saw the declining production curve they began contingency planning — “self-protection mode” as Matanuska Electric Association General Manager Tony Izzo described it — and began discussing LNG imports to meet consumer needs, despite having one of the most historically prolific gas basins in the country in their backyards.
The prospect of importing energy to one of the most hydrocarbon-rich regions of the world did not sit well with state lawmakers, who promptly drafted and passed the Cook Inlet Recovery Act in 2010, which incentivized development of the Cook Inlet Natural Gas Storage Alaska facility in Kenai and added to the oil and gas tax credits available to Inlet-operating companies.
Two years later came Hilcorp Energy. In nearly one fell swoop Hilcorp purchased the Inlet holdings of majors Chevron and Marathon and immediately became the basin’s dominant producer.
With Hilcorp came the 2012 consent decree between the state and the company — the agreement that has largely regulated Inlet gas pricing since then and will through its expiration in early 2018.
Stable but not optimal
The Cook Inlet gas situation began to stabilize with the consent decree, according to leaders of several Southcentral utilities.
It capped base load natural gas prices at $6.60 per mcf in 2013, with annual 4 percent increases to a cap of $7.72 per mcf in 2017.
The consent decree “added a degree of functionality to a previously dysfunctional market” and ended spot price bidding well in excess of $10 per mcf, Enstar Vice President and General Counsel Moira Smith said.
Izzo said his only significant issue with the agreement, as a gas buyer, is the 4 percent price escalator.
The most recent gas supply contracts between the utilities and Hilcorp and new gas producer Furie Operating Alaska LLC start when the consent decree expires and extend out to 2023. The initial prices in those contracts are up to 20 percent lower than the end of the decree pricing scale.
While securing fuel supply is typically a utility’s top priority, Smith said in an interview that Hilcorp was willing to extend terms beyond 2023. Rather, it was Enstar that wanted to keep its long-term options open for potential new producers.
Since Hilcorp took the lion’s share of the gas market, the lone new Inlet entrant with significant production at this point is Furie.
Last September the state Division of Oil and Gas estimated there is about 1.2 trillion cubic feet of proven plus probable, or 2P, recoverable natural gas reserves in the Cook Inlet basin.
With current local demand at about 85 bcf per year and ConocoPhillips annual LNG exports in the 15 bcf range the past two years — conducted in summer to balance seasonal utility demand swings — the division’s 2P reserve projection would provide a little more than a decade of supply.
The U.S. Geological Survey has published total Inlet gas reserve estimates as high as 17 trillion cubic feet for conventional and unconventional plays — economics not considered.
Furie Senior Vice President Bruce Webb said in an interview that he believes the current reserves could supply the status quo market for longer based on what Furie thinks it has, but the situation is still far from ideal.
Regardless of the exact extractable reserves, Izzo said MEA’s contract with Hilcorp inked in April to supply all of its natural gas through March of 2023 provides the electric utility with only “temporary relief.”
“As a buyer (of gas) and a provider of an essential service, the level of concern has not diminished for me at all,” he said. “For me, in three-to-five years I’m going to have to be looking at importing LNG again if I don’t see things turn around.”
A “turnaround” would mean new players bringing new investment to new fields resulting in new gas production, according to Izzo.
There has been a turnaround on the oil front since Hilcorp came to the scene. Cook Inlet oil production bottomed out at about 7,500 barrels per day in 2009. Almost always the more sought-after commodity, oil production has more than doubled to nearly 16,000 barrels per day from the Inlet in May, according to Alaska Oil and Gas Conservation Commission data.
“In many ways, one could say that gas production hasn’t seen the same degree of turnaround because it’s a restricted domestic market where you’re limited to the demand that’s available,” Janak Mayer told the House Resources Committee during a Feb. 26 hearing on oil and gas tax credit legislation.
Mayer is chairman of the Legislature’s oil and gas consulting firm Enalytica.
ConocoPhillips’ LNG exports, in addition to being subject to the forces of a depressed world market, are also limited by the company’s export license, which was renewed in February by the Department of Energy. It now runs into February 2018.
The license allows ConocoPhillips to export up to 40 bcf of natural gas in liquid form over the next two years. However, those exports can only be made if local utility demand is met first. Thus, ConocoPhillips exports have come during the off-peak summer season since the plant reopened in 2014.
Part of the market challenge stems from utilities, and residents, doing what we’ve been told to do for decades — saving energy.
Enstar is not expecting demand growth from its natural gas customers through 2023 in filings with the RCA related to its latest gas supply contract with Hilcorp.
Smith said incentive programs to purchase energy efficient appliances and state rebates for home weatherization projects, along with individual consumer efforts to use less natural gas, have offset the annual small growth in the utility’s customer base.
“The conservation effect will result in flat annual demand from now into the foreseeable future,” Smith said.
Izzo noted that the suite of new natural gas-fired generation plants in the region that have come online in recent years or are about to are all 25 percent to 30 percent more fuel efficient than the plants they are replacing, thus eliminating any significant demand growth from the electric utilities.
Finally, Municipal Light and Power and Chugach Electric Association basically took up to 80 bcf of demand off the market over the next 15 years to 18 years when they partnered to purchase ConocoPhillips’ share of the Beluga River Unit in February.
The utilities expect the field to produce between 70 bcf and 80 bcf in total before being depleted.
Hilcorp owns the remaining third of the Beluga field and will operate the unit for the utilities, but it is a portion of valuable gas demand that will not be available to bid on for years to come.
“We all think there’s gas out there but you have to think you can sell it before you can go out and invest,” Izzo commented.
“If you went out and drilled a gas well now you wouldn’t be able to sell it until about 2021 or 2023,” Webb added.
For better or worse, Cook Inlet natural gas is about to return to a truly free, but still constrained, market.
House Bill 247 signed by Gov. Bill Walker would eliminate state support for work in the basin starting in January 2018. That is just before the blanket price control of the consent decree will officially end on April 1, 2018.
While much of the extra-extended legislative session this year focused on tax credits for the oil and gas industry, bill versions from House and Senate committees varied greatly on North Slope issue, but fairly quickly settled on eliminating credits from the Inlet within a few years.
HB 247 cuts the current 25 percent Net Operating Loss, 20 percent Qualified Capital Expenditure and 40 percent Well Lease Expenditure reimbursable credits in half on Jan. 1, 2017. The halved credits are then fully killed off a year later.
Webb testified in legislative hearings on HB 247 that Furie took advantage of all of the available Cook Inlet tax credits in developing the $700 million offshore Kitchen Lights gas discovery, which included installation of the first production platform in the Inlet in roughly 30 years. Furie began producing gas in time to fill its first utility contract with Homer Electric Association this spring.
However, he noted the company recognizes the position falling oil prices quickly put the state in — that of annual budget deficits approaching $4 billion.
“The state didn’t see this oil crisis — budget crisis — coming so we can appreciate the state’s position that they just can’t afford to pay everything anymore,” Webb said.
He added that the final version of HB 247 that passed the Legislature gives companies needed time to adjust, while the administration’s proposal would have cut some of the Inlet credits nearly immediately this July 1.
The tax credits helped Furie mitigate its biggest risk and the biggest risk any company takes —the risk of exploration — in a basin that is “easily 300 percent more expensive than the Lower 48” in terms of gas development, Webb said.
Izzo said he is worried the state acted just a little too soon in wholly eliminating the credit program before additional gas reserves could be developed.
BlueCrest Energy of Fort Worth, Texas, began producing small amounts of oil from the Cosmopolitan Unit just offshore of Anchor Point via a single onshore well in late April.
The company committed upwards of $525 million to the project and hopes to produce up to 5,000 barrels per day this year. CEO Benjamin Johnson credited tax credits with helping the company develop the well-defined but green field reserve.
BlueCrest investigated options to make gas production from Cosmo worthwhile — the gas reservoir sits directly above the oil — but the uncertainty about the credit program starting after Gov. Walker’s well-publicized line-item veto of $200 million of fiscal year 2016’s $700 million budget appropriation to pay for credits earned caused the company to delay tapping the Cosmo gas reserve, Johnson said in testimony to legislators this year.
Another challenge for selling gas from Cosmo is that Hilcorp and Furie have eaten up much of the utility market for years to come. This year each secured contracts with Enstar through at least 2021. Hilcorp also recently inked a deal to supply all of Matanuska Electric’s demand from the end of the consent decree into 2023; and the two have other contracts in place as well.
Now, BlueCrest is preparing to frack wells drilled from onshore to increase oil production.
Legislative consultant Mayer said that infill drilling of developed fields should be profitable given Inlet gas prices and drilling costs; the situation Hilcorp is mostly in and Furie is working to get to with its first few gas wells in place.
The economics of early development drilling, however, can be much different, he said.
In a written response to questions from the Journal, Hilcorp stated: “House Bill 247 that recently passed the Legislature impacts our industry negatively. We, like all other oil and gas companies, have to consider these impacts when making our investment decisions.
“In deciding where to spend our capital, a number of factors come into play and the stability of Alaska’s fiscal regime is an important one. Continued turmoil and instability within the Alaska oil and gas tax structure will also place Alaska at a disadvantage in attracting new players. We hope the result of any new legislation being considered will create a predictable and stable tax structure that encourages more oil and gas activity in Alaska.”
A proposal by the administration to potentially offset the loss of the credits died in the Legislature and is not on the governor’s July 11 special session agenda; however oil and gas tax credits are an item once again.
House Bill 246 would have established an oil and gas project development loan fund within the state-owned Alaska Industrial Development and Export Authority to provide low-interest loans for low-risk development projects.
The fund would not have been immediately capitalized because the budget had already been passed, but HB 246 passed the House by a wide margin in the final days of the special session. The Senate had little time to address the legislation and adjourned without taking it up.
Furie’s Webb said it obviously would not replace the tax credit system, which could offset more than half of the development costs of some projects, but has the promise to be useful, if it is not too restrictive.
“If you go to Wall Street (for funding), the interest is really high because you’re trying to finance a project that may or may not prove out and you may or may not have a market for the product,” Webb said. “If the state has a good low-cost financing tool, that would definitely help out further development.”
The Alaska Oil and Gas Association initially testified against the loan fund proposal, but later warmed slightly to the idea while emphasizing it would not be an adequate replacement for the credit program.
Mayer testified to House Resources that spending more than $300 million per year on tax credits in Cook Inlet — as the state has done the past three years — is simply not feasible, particularly given the state receives minimal the production taxes the credits are tied to.
“I think it’s hard to look at those (credit expense) numbers and see that as a sustainable system,” Mayer said.
However, in the same hearing he added, “The basic impact of the credits is to make what is a very marginal investment maybe just possible,” exemplifying the challenge of the situation.
Demand on the horizon
The nearest demand growth appears to be at least four or five years away.
That is, unless Agrium suddenly decides to restart its Nikiski facility, which seems unlikely given a statement by Richard Downey, a company vice president, who said nitrogen prices do not make that feasible at this point.
“We continue to keep the plant warm, so to speak, in terms of upkeep, in hopes that someday we can return it to production. I would say market conditions are not conducive to that at the moment,” Downey told the Journal.
He added that lower energy prices worldwide make restarting the Nikiski plant that relies on the Cook Inlet gas market a challenge.
Webb also said he doesn’t think the Alaska LNG Project, or any other large North Slope export project, would impact the Southcentral gas market much, unless the Inlet gas supply fades and prices rise because the cost to move the gas down the 800-mile pipe would not match the local cost advantage.
AIDEA officials leading the Interior Energy Project initiative to get natural gas to the Fairbanks area hope to start trucking more LNG north in 2018, but the 3 bcf per year starting point would be a minimal change in the overall market.
The mega-mine Donlin Gold project is looking at a 315-mile natural gas pipeline from the west side of Cook Inlet to the mine site in the Kuskokwim River valley. As currently planned Donlin would need about 12 bcf per year to fuel the mine’s power plant and it would add the potential of getting natural gas to some of the nearby villages in the region.
It would be a long-term customer, but would it provide enough to spur significant new exploration. The mine is also still in the environmental impact statement process, awaiting a federal decision sometime next year with operation still years away, along with being economically challenged by low gold prices.
A mid-sized LNG export plant proposed at Port MacKenzie by Resources Energy Inc., a joint venture of Alaska and Japan interests, could crack the market egg.
The plant’s 1 million tons per year of LNG processing capacity could add nearly 50 bcf of gas demand over 20-plus years and be the elusive “anchor tenant” to replace the void left by Agrium.
With startup planned for 2021, the lead-time would allow for field development if need be.
REI is looking for utilities interested in investing in gas reserves, which Japan has plenty of, General Manager Mary Ann Pease said, noting gas supply is not a worry.
“We definitely think the gas supply is there,” she said.
The challenge will be achieving the project’s $4 per mcf price target for wholesale gas, but that could be helped some through buying directly into a field.
“The cost of gas is the single biggest thing that drives our project,” Pease said.
Elwood Brehmer can be reached at [email protected]