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Is there a Cook Inlet natural gas shortage? Utilities, state officials have different answers

Alan Bailey

Amid concerns over the continuity of natural gas supplies for Southcentral gas and power utilities, apparent disconnects between statements by the Alaska Department of Natural Resources, or DNR, and the utilities about the abundance or otherwise of remaining gas in the Cook Inlet basin have created a sense of confusion for those who worry about the specter of an Alaska winter with inadequate energy supplies.

Residents of Southcentral Alaska depend on gas from aging gas fields in the basin for heating homes and other buildings, while about 90 percent of the region's electricity comes from gas-fueled power plants. Utilities say that, with production from those gas fields declining at around 16 percent per year, supplies are likely to run short around 2014-15, necessitating actions such as running some power generation on expensive diesel fuel or importing some natural gas from outside the region.

The core issues at stake seem to be the certainty that utilities need for gas supplies for their customers and the time required to bring new gas on line.

The Alaska Legislature has held a series of committee meetings around the theme of "who's keeping the lights and heat on," hearing presentations from DNR and the utilities, to gain a clearer understanding of the gas supply situation. During one of these meetings, a House Energy Committee meeting on Jan. 23, Rep. Charisse Millett, R-District 24, expressed the frustration that some lawmakers and others feel.

"It's very concerning that we have two groups of people that one says we're awash with gas in the Cook Inlet and then another group saying that we have gas and that we're just not producing enough of it," Millett said. "So it's disturbing for those of us who live in the Cook Inlet (region) because this has been the ongoing debate between the (state) administration and what the utilities have been saying."

During presentations to the Senate Resources Committee on Jan. 21 and to the Regulatory Commission of Alaska on Jan. 23, DNR Commissioner Dan Sullivan said that DNR shares the utilities' concerns about potential shortfalls in the delivery of gas to Southcentral consumers and power plants. But, while there are legitimate concerns about the amount of gas that the utilities have available under secure contracts with Cook Inlet gas producers, DNR, as manager of the state's gas resources, takes a much broader view of the situation, Sullivan said.

"We also think there are still large volumes of oil and gas in the inlet, not maybe in huge fields, but in intermediate fields, and we think that's important," he said. "We've been focusing on that view."

Sullivan said that DNR has seen success in encouraging companies such as Hilcorp Energy and Apache Corp. to come to Alaska to seek and develop some of the substantial oil and gas resources that the state believes remain in the basin. The Cook Inlet basin is currently seeing something of a renaissance in oil and gas exploration and development.

So, what is the situation on the future prospects for continuing Cook Inlet gas supplies?

The state has conducted studies into how much gas might be available for production from the basin. And independently from the state, the utilities commissioned consultancy firm Petrotechnical Resources of Alaska, or PRA, to assess the situation. As a starting point, both DNR and PRA used a technique called decline curve analysis, projecting the rate of decline of gas production from currently operational gas wells and gas fields to predict the future decline in gas production from the basin as a whole. Both DNR and PRA came to almost identical conclusions: In the absence of new gas wells, gas production will drop below gas demand around 2013 to 2014.

But, on the assumption that gas producers will continue to drill more wells, DNR and PRA have taken different approaches to evaluating how much gas might in reality be produced from the Cook Inlet basin in the coming years. DNR has assessed how much gas could be available for development, regardless of how long that development might take or how much it might cost, while PRA has evaluated the extent to which feasible rates of new gas well drilling might impact the gas production decline.

DNR used two techniques to assess how much gas people might reasonably expect to see come from the basin as gas field development continues, Paul Decker, a petroleum geologist with Alaska's Division of Oil and Gas, explained to the RCA commissioners on Jan. 23.

The first of these techniques, called "material balance," uses changes in gas field reservoir pressures over time, as gas is produced, to estimate how much gas remains in pressure contact with producing gas wells. The use of this technique expands by about 32 percent the gas volume estimated from decline curve analysis, Decker said.

The second technique involves a geologic analysis, mapping known reservoir horizons to estimate volumes of gas that are likely to lie trapped underground.

Decker also explained the importance of assessing uncertainties when using these techniques. Undeveloped gas can broadly be categorized as reserves, gas proved to exist from drilling and economic to produce, and resources, gas not proved from drilling or not shown to be economically viable, he said. And within those categories there are statistical ranges of uncertainty in gas volume estimates.

Decker said that for the most part DNR does not have access to companies' reserves estimates, the volumes that the companies use when making decisions over gas sale contracts with utilities. But DNR views the volume estimates obtained from decline curve analysis as high probability reserves and the estimates from material balance as medium probability reserves. The volume estimates obtained from geologic analysis include some reserves, as well as less certain gas resources including some gas that would be discovered from exploration.

Overall, DNR has estimated that there remain about 1.1 trillion cubic feet of producible gas reserves in the 28 existing fields in the Cook Inlet basin, Decker said. The geologic analysis indicates another 355 billion cubic feet of natural gas in undeveloped areas of existing fields, mainly in three large fields: the Beluga River field, the Trading Bay unit Grayling Gas Sands and the North Cook Inlet field, he said. Further gas estimated from the geology would be found as a result of future exploration.

And, while DNR does not disagree with PRA's view that there is a shortage of gas under utility contract, the gas resources in the basin are not depleted, Decker said. A plot of all of DNR's reserves and resource estimates relative to anticipated Cook Inlet gas demand indicates that there may be enough gas in basin to meet gas demand through to the late 2020s, if enough drilling is done.

"What it reflects is that not enough wells are being drilled fast enough to keep pace with demand," Decker said. "We believe that there's significant gas left in the basin."

On Jan. 21 Deputy Commissioner of Natural Resources Joe Balash told the Senate Resources Committee that the drilling required to sustain Cook Inlet gas supplies requires adequate commercial incentives. Balash recounted events in 2005 when the Regulatory Commission of Alaska rejected a proposed gas supply contract between Marathon Oil Co. and Enstar, following concerns about proposed price rises in the contract, with opposition to the contract from a number of entities including the state Attorney General's Regulatory Affairs and Public Advocacy Section.

The rejection of that contract sent a chill through the Cook Inlet industry, was followed by a dramatic drop in drilling activity and may have triggered Marathon's eventual departure from Alaska, Balash said. But that contract, which had prices indexed to the Lower 48 Henry Hub market, would have met all of Enstar's gas needs through 2016, including seasonal swings in gas demand. Ironically, given a subsequent fall in Henry Hub prices that no one predicted in 2005, gas prices in the Marathon contract would have dropped rather than risen.

But Marathon's willingness to commit to that contract demonstrates that the company had sufficient gas to meet Enstar's needs for the duration of the contract, Balash said.

"We're not out of gas," Balash said. "Marathon would not have put its corporate reputation and balance sheet on the line if they didn't think there were sufficient reserves to meet all of the requirements."

PRA, in its forecasts, has not made any attempt to estimate as-yet undeveloped gas volumes in the basin. Instead, on the assumption that there is more gas to develop, either in existing fields or from gas exploration, the PRA analysis has evaluated the rate of gas-well drilling required to overcome the gas supply decline. And, by considering the numbers of wells that have been drilled each year in the past and then evaluating how much drilling might realistically take place in coming years, the PRA study sought to forecast future gas production using likely future drilling rates.

PRA sees the possibility of at least three new gas well completions each year, with the realistic possibility of as many as eight wells per year and a likely drilling rate somewhere in the middle of that three to eight range, PRA consultant Bill Van Dyke told the House Energy Committee on Jan. 23. Based on typical gas production rates from new Cook Inlet wells, the anticipated drilling rate suggests an addition of 10 million to 20 million cubic feet of gas production each year, but with the new wells themselves going into decline after startup. Adding up the numbers and projecting the production rates forward leads to that prediction of a supply shortfall around 2014-15.

And to enter into gas supply contracts with utilities, gas producers need proven reserves, not uncertain resource estimates.

"Would you bet the energy security of your community on the speculative prospects of major gas finds in the Cook Inlet and major gas development at this time?" Rep. Mike Hawker, R-District 27, asked Van Dyke.

"No, I would not," Van Dyke replied. "Utilities need a guaranteed gas supply. A probabilistic study of how much gas is in Cook Inlet is not a guaranteed gas supply."

Van Dyke also commented on the timing issues associated with bringing a new gas field on line. In a simplest case, say on the Kenai Peninsula, it might take two to three years to complete all of the planning, permitting, contract negotiations and development involved in bringing a new field into production, he said. That would bring new gas from the new field into the gas infrastructure after the date of the projected gas supply shortfall.

And if gas producers accelerate the rate of drilling in the existing fields, the effect would be to accelerate the production decline rates in the fields, thus further reducing production rates a few years down the road. Essentially, people are trying to deal with a set of gas fields, all undergoing a natural production decline, Van Dyke said.

"We're showing a 16 or 17 percent annual decline and that's a pretty steep decline rate to chase," Van Dyke said. "You're going to have to find a lot of new gas just if you want to keep production flat, let alone increase it, because you have this base that's always in natural decline."

Moira Smith, vice president and general counsel of Enstar Natural Gas Co., told the Energy Committee that Enstar has been supplying Southcentral residents with gas since 1961, using only Cook Inlet supplies.

"It is Enstar's primary goal to continue to do that, and to do that at a price that's reasonable for Southcentral customers," Smith said.

But, with a gas supply shortfall on the horizon, the utilities are taking steps to bolster Southcentral energy supplies from other sources, she said.

"We've reached the bottom line, which is that we need to supplement Cook Inlet gas production," Smith said.

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