Alaska Journal of Commerce
Despite new natural gas discoveries in Alaska’s Cook Inlet utilities in the region will still experience shortages of gas supply by 2014 due to declining production in maturing fields, according to a new study of Cook Inlet gas reserves and regional demand released Monday.
The only practical alternative to deal with the shortfall is the import of liquefied natural gas, said Pete Stokes, commercial manager with Petrotechnical Resources of Alaska, an Anchorage-based consulting firm.
PRA’s analysis was done for three Southcentral Alaska utilities, Enstar Natural Gas Co., Chugach Electric Association and Anchorage’s city-owned Municipal Light & Power.
“The PRA report just emphasizes what we’re been concerned with for some time, that there is a lot of talk about new gas resources out there but no one is bringing it to market. We need to see results,” said John Sims, spokesman for Enstar Natural Gas Co., the Southcentral regional gas utility.
Sims said the three utilities are working on plans to import LNG, but negotiations with potential suppliers are confidential.
ConocoPhillips owns and operates a liquefied natural gas plant at Kenai that the company had planned to mothball. However, the plant is now being kept open on a year-by-year basis with incremental shipments being made to customers in Asia.
There are reported new discoveries of gas both offshore and onshore in Cook Inlet including from a well drilled last summer by Escopeta Oil Co. from a jack-up rig, but the discoveries have yet to be tested, Stokes said.
Even if they can be produced commercially it will take five to six years, or more, to secure permits and build a platform and pipelines and other production facilities. The new gas would not come in time to meet the impending shortfall facing the utilities, he said. The expected supply shortfall that year is 7 billion cubic feet short of the utilities’ projected requirement of 80 billion cubic feet, Stokes said.
“Only a significant onshore discovery that is near existing pipelines will be sufficient to offset the shortfall in 2014. Offshore discoveries cannot be developed in time,” he said.
There are two new onshore Kenai Peninsula gas discoveries, one by Australia-based independent Buccaneer Energy in a prospect near the City of Kenai and a second in the Kenai National Wildlife Refuge by Alaskan independent NordAq, but both of these require further testing.
PRA’s analysis tracks studies done in recent years by the state Department of Natural Resources, which show potential reserve additions in the Cook Inlet Basin sufficient to meet local utility needs to 2020.
The difference, Stokes said, is that the state’s study assumes industry will make additional investments by producers in development drilling to prove up needed new reserves. PRA’s study, which is an update of work done in 2009, for the utilities, shows that the investments are not being made, at least at the rate needed.
In 2009, PRA estimated that if producers drilled no new development wells utilities would face a shortfall in 2013. The updated analysis just finished shows that some drilling and compression has been added, but that the supply shortfall is pushed out only one year, to 2014.
In 2009, PRA estimated that, assuming no discoveries of new fields, 185 new wells need to be drilled in the producing fields by 2020, or 14 to 18 new wells per year, to develop enough new gas to meet local utility demand. That level of drilling would require an investment of $1.9 billion to $2.8 billion, PRA said in its 2009 report.
The actual drilling by producers has been far below those levels, Stokes said. In 2010 producers drilled five new production wells. In 2011 six new production wells were drilled.
However, the 2011 drilling resulted in far less new production than wells in 2010, an indication of the declining productivity of the large Cook Inlet gas fields.
Wells drilled by producers in 2010 averages 18.5 million cubic feet of gas per day additions to production, while the wells drilled in 2011 averaged about 9.9 million cubic feet of gas per day, Stokes said.
PRA’s recent analysis indicates that even if producers ramp up drilling by three or four more wells per year the projected shortfall in the utilities’ need still appears in 2014 but drops from 7 billion cubic feet to 1 billion cubic feet that year, Stokes said.
Even if drilling is doubled, to six to eight wells per year over the 2010 and 2011 rates, the shortfall is pushed back only one more year, until 2015, he said.
The state of Alaska is meanwhile backing a plan to build a 24-inch pipeline to bring gas from the North Slope to Southcentral Alaska, or alternatively a 24-inch “spur line” if a large-diameter pipeline is built to Canada, but gas from the Slope cannot realistically be shipped until 2020 at the earliest, state officials have said.
Southcentral Alaska utilities have been grappling for years with the long-term decline of producing fields the region. For many years gas was in surplus to local needs and prices were low, at $1.50 per mcf or lower for many years. There was virtually no exploration given the prices.
In recent years prices have increased and are now in the range of $8 per mcf under new gas contracts signed by the utilities, and there has been new exploration in the last two years. Also, the state of Alaska has stepped in with generous incentives for exploration, paying as much as 60 percent to 70 percent of the cost of new wells.