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Solving Cook Inlet’s gas conundrum Region needs gas for foreseeable future; gas exploration, gas storage, North Slope gas, LNG all factor into energy supply options Alan Bailey Petroleum News
The days of an overabundance of cheap natural gas from Cook Inlet basin may be over, but Southcentral Alaska needs reliable gas supplies for years to come was a recurring theme during the first day of the Law Seminars International Energy in Alaska conference in Anchorage on Nov. 12.
Gas reserves from existing Cook Inlet gas fields are gradually dwindling. But, although there are definite opportunities to develop alternative energy supplies such as wind, hydro and geothermal power, the impracticality of a total switchover to alternative fuels will drive a need for natural gas for a long time.
“All of our assumptions are that you and I will continue to heat with gas at whatever it costs because the options are just so horrifically expensive to convert … from gas that it’s something we can’t visualize,” Harold Heinze, chief executive officer of the Alaska Natural Gas Development Authority, said in a discussion of the energy supply issues.
Heinze also said that a mix of different energy sources, including gas and alternative energies, would be desirable, because that diversity would increase the overall reliability of energy supplies.
“We believe that the energy in this area is going to be a mixture of things — there’s no one magic solution,” Heinze said.
So where will future Southcentral gas supplies come from?
ANGDA has been working on plans to build a spur gas line that would divert some North Slope gas into Southcentral Alaska from a future North Slope gas export line. But, although a spur line could likely meet Southcentral Alaska’s gas needs, gas line construction would be several years in the future and there is no certainty that the line will be built.
So, local gas supplies from the Cook Inlet basin remain critically important.
Guarded optimism Scott Jepsen, Cook Inlet manager for ConocoPhillips, and Mitch Little, production manager, Alaska, for Marathon, both sounded guardedly optimistic about the future of gas production from that basin. ConocoPhillips and Marathon are major gas producers in the Cook Inlet region.
That optimism comes despite the “gas cliff,” a familiar graph showing a precipitous decline in future Cook Inlet gas production in coming years. That graph only uses the forecast production from current estimated reserves and depicts a conservative picture of the gas situation, Jepsen said.
“It represents no further investment in existing fields and no exploration,” he said.
Whenever the plot is updated the cliff moves further ahead in time, Jepsen said.
In fact the Cook Inlet basin has been underexplored for natural gas and likely still contains substantial undiscovered gas resources.
“There have been a number of studies that have been done. … All of them have found significant amounts resource potential,” Jepsen said.
In addition there is considerable resource potential from the continued development of existing fields, he said.
J Lower 48 comparison epsen likened the situation in the Cook Inlet basin to the “perceived natural gas crisis” in the Lower 48 in the mid 1970s. When the reserves to production ratio, a measure of how many years of gas supply remain, had dropped from around 20 to about 10 people thought that gas supplies were about to run out, he said.
“We thought the gas bubble was about to burst. … We had utilities curtailing their expansions because they didn’t think they were going to have enough gas for existing consumers,” Jepsen said.
But then gas prices rose and, with new investments in gas development, the reserves to production ratio stabilized at around 10 over the years to come.
In Cook Inlet the reserves to production ratio dropped to about that magic 10 level at around 2000, Jepsen said. Then as gas prices rose the number of wells drilled in the Cook Inlet basin also increased. Between 2001 and 2005 five times more wells were drilled than during the previous 15 years, Jepsen said.
Little also compared the situation in Alaska with that in the Lower 48.
He showed a graph depicting a strong correlation between natural gas prices and the number of Lower 48 wells drilled as evidence of the connection between prices and gas development. The graph also showed growth in gas reserves in line with increased drilling activity.
Low Cook Inlet prices But gas prices in the Cook Inlet have remained consistently lower than those in the Lower 48, Little said.
“The average price for Southcentral Alaska’s producers is approximately $3 an mcf lower than what you see for competing opportunities in the Lower 48,” Little said. “… If a producer or an investor had equal opportunities … in those environments, they’re going to choose the market that gives them the most incentive for doing that. … Clearly Alaska’s gas opportunities are not today competitive on average with those opportunities in the Lower 48.”
Local market factors also come into play in Alaska because of the extreme seasonal swings in utility gas demand between summer and winter. The average daily supply volume is 75 million cubic feet, while the peak is 185 million to 200 million cubic feet, Little said. But the traditional utility gas supply contracts for the Cook Inlet basin are “full service” contracts that include both base load and peak winter demand.
“To date the producers bear the sole burden of providing that peak availability,” Little said. “… It’s a real cost of doing business.”
And there’s a double whammy in that it is becoming increasingly difficult to stop and start wells to adjust production to match the swings in demand. Whereas years ago it was possible to shut in a Cook Inlet gas well and then simply restart it, the mature nature of the gas fields nowadays means that well production recovery after a shut in may take anything from several days to several months, and may never fully return to pre-shut-in levels, Little explained.
Storage facilities So, with average production coming into balance with average demand, Cook Inlet producers have been establishing gas storage facilities. These facilities can store excess gas during the summer when demand is low, and then release gas during higher winter demand. To date, Chevron has developed storage facilities in the Swanson River and Pretty Creek fields, while Marathon has established a facility in the Kenai field.
Little sees a need for a portfolio of different types of gas storage arrangements to support demand fluctuations. Subsurface storage of the type that has currently been implemented should support major overall swings in demand between summer and winter, he said. And were a spur line to bring North Slope gas into Southcentral, gas storage in depleted gas reservoirs could help smooth out gas line throughput to maximize pipeline usage efficiency.
But other approaches, such as small-scale liquefied natural gas storage facilities, are needed to support short-term peaks in demand.
“On-the-surface LNG peak shaving is another common practice used by utilities and/or third party providers,” Little said. “… It can provide instantaneous needle peak supplies.”
Peak shaving facilities of this type are also commonly placed close to where the gas is used, as insurance against interruptions in gas production or transmission line operation, he said.
Gas storage could also provide a convenient buffer against fluctuations in supply rates from future alternative energy sources such as wind power, Heinze said.
Cook Inlet gas market But, with gas storage costing money, the issue of how to pay for the storage comes back to the operation of the Cook Inlet gas market — a market that is still adjusting to the changing gas supply situation in the region.
Kurt Gibson, acting deputy director of Alaska’s Division of Oil and Gas, characterized the Cook Inlet gas market as an “emerging market that requires some guidance on the part of regulatory agencies.”
“There is no market for natural gas in Cook Inlet. A functional market does not exist,” Gibson said. “It exists as periodic episodes of negotiation followed by silence.”
Although market forces should bring supply and demand into balance, it becomes problematic if, when prices go up, there is no outlet for additional supplies — the market needs to react on a more regular basis, Gibson said.
Full requirements and long-term contracts keep the parties apart and don’t result in smoothly transitioning commercial agreements, Gibson said. In the Lower 48 continuous negotiations and portfolios of commercial transactions form an overall supply portfolio for a utility. Regulatory agencies review agreements in retrospect, to determine whether the transactions are in the best interests of the ratepayers.
A similar approach in Alaska might cut out the long lead times and high costs associated with the regulatory approval of supply contracts, Gibson said.
And, as in the Lower 48, the regulators may need to create a situation where the supply transactions are “unbundled.” Companies could then shop around for different service components, and service providers could be compensated appropriately for different types of service.
That type of arrangement would enable peak shaving services pricing, for example, to reflect the cost and complexity of that specific service.
But that also raises questions about who should operate the gas storage.
In the Lower 48 gas utilities or midstream businesses, rather than the gas producers, often take care of peak demand, said natural gas consultant Tony Izzo.
“Typically, what you find is that the utility is responsible,” Izzo said. “Either they buy the service from someone at the midstream level or they own the peaking assets.”
Kenai LNG facility However, with deliverability of utility gas during the extreme peak demand of cold winter days in Southcentral Alaska being so important, several speakers at the conference spoke about the peak shaving role of the LNG export facility on the Kenai Peninsula. In recent winters the plant has cut production to boost the short-term availability of gas for utility use during peak demand.
But the plant’s export license expires in 2009 and the U.S. Department of Energy is currently reviewing an application by Marathon and ConocoPhillips, the plant owners, for a two-year license extension.
The prevailing view of the conference speakers was that closing the plant would be a mistake. At present, the plant provides the only means of quickly adjusting utility gas deliverability during peak winter demand, Heinze said, for example.
Not only that. Without the LNG plant, there would be insufficient base gas load in the region to support the regional gas market. And, if wells are shut-in as a result of closing the plant, it is unlikely to be possible to restart the wells.
“You’ll lose wells if you can’t produce them,” Heinze said.
Heinze also thinks that it is important to be able to convert the LNG plant to import LNG, in the event of gas supplies running short during the interim period before a pipeline infrastructure connects the North Slope gas supplies to Southcentral Alaska.
“If there isn’t some significant discovery made that makes you comfortable about our supply, it seems to us that you’ve got to look at modifying that plant,” Heinze said.
Energy conservation can also play a significant role in addressing future gas supply issues. Anchorage Mayor Mark Begich described to the conference several Municipality of Anchorage initiatives to reduce energy consumption by, for example, retrofitting lights with modern technology and putting computers into sleep mode when not in use.
And gas utility rate structures need to be redesigned to encourage gas conservation, Izzo said.
But, even with conservation, investment will be needed to address issues such as the need for gas storage and a dependable gas transmission infrastructure, Izzo said. And, since that ultimately comes back to cost to the customer, there will also need to be “regulatory response” to assure that appropriate cost increases will be approved, he said.
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