Cook Inlet natural resource producers will need to double or perhaps triple production of natural gas in order to avoid projected shortfalls to residential and commercial consumers that could come as soon as 2015 otherwise, a new study concludes.
Petrotechnical Resources of Alaska recently published a Cook Inlet gas study compiled for ENSTAR, Chugach Electric Association, Municipal Light and Power, Homer Electric Association and others. The study, which is an update of one published by the same group in 2010, concludes producers have not drilled enough wells and produced enough gas estimated necessary by the previous report to avoid looming shortages.
In 2010, PRA wrote that Cook Inlet producers needed to drill 13.6 wells each year meet forecasted demand. However, only five gas wells were added in 2010, seven in 2011 and four through June 2012.
The group also wrote producers needed an annual increased production rate of 42.2 million cubic feet per day to meet demand. In 2010, total increased production increased reached 18.5 million cubic feet per day, 12.3 million cubic feet per day in 2011 and 21.5 million cubic feet per day in 2012 — all of which are significantly lagging from the group’s suggested annual increase.
PRA’s Peter Stokes, who penned the report, estimated 157 new gas completions are needed to meet demand through 2020. That means 31 million cubic feet per day of gas needs to be added each year from new completions from 2013 to 2019 to withhold shortfalls, Stokes wrote.
“It is a lot,” he said.
The report bases gas needs on projections from regional utilities and the Donlin Creek Mine, which is projected to start consumption in 2020. It also takes into account the needs of the Tesoro refinery, ConocoPhillips’ Kenai LNG facility and field fuel gas.
Cook Inlet gas provides all of ENSTAR’s supply and accounts for 90 percent and 88 percent of generation for Chugach Electric and ML&P, respectively.
Additionally, HEA officials say the utility will need 4.4 billion cubic feet of gas per year starting in 2014 — when its contract with Chugach expires — for its Independent Light project, including the Nikiski combined cycle project and the Soldotna combustion turbine project. In 2014, 90 percent of HEA’s generation will be fueled by gas with the remaining coming from the utility’s share of power from the state-owned Bradley Lake hydroelectric facility.
The current situation that predicts a shortfall — where demands exceeds supply — is a blend of declining reserves and production from existing wells and the time it takes for new exploration to result in gas heading to market, Stokes said.
“There is a lot of activity going on, a lot of exploration going on, but unfortunately exploration, if it is going to be a meaningful discovery, is not likely able to be brought on quick enough to avoid this near term shortfall issue,” he said.
The time from new discovery to market is anywhere from three to five years depending on location and permitting, Stokes said.
“(Location) not only impacts the permitting, but it also impacts the construction to get facilities and pipelines in place,” he said. “Obviously, if you are out in the middle of Cook Inlet it is a little different than being in the city of Kenai like Buccaneer is with their Kenai Loop — that’s the best of all worlds to have a discovery there, but how many of those are you going to have?”
In his report, Stokes identified importing liquefied natural gas or compressed natural gas as the most logical solution to bridge the gap if production doesn’t ramp up.
“(Utilities) feel like this is real and they feel like bringing imported gas whether it is compressed or liquefied is the only thing that they have within their control because they are obviously not going out and drilling wells,” Stokes said.
The downside of importing LNG or CNG would be the cost, he said. But supply could increase and push prices down as more and more LNG facilities come online around the world in the coming years, Stokes contends.
“If you take the spot price today it is quite a bit higher than what Cook Inlet producers are receiving for the gas through their contracts,” he said.
Stokes also wrote the most likely sources of new production in Cook Inlet would be from existing fields such as the Beluga River unit, the Trading Bay unit or development of recent discoveries like Buccaneer’s Kenai Loop, Nordaq’s Shadura or Tiger Eye prospects, Cook Inlet Energy’s Otter well near the Beluga River unit or Apache’s onshore well near Tyonek that should be drilled within the year.
The report also looked at offshore exploration from Furie’s Spartan 151 drilling rig operating in the Kitchen Lights unit and Buccaneer’s Endeavour-Spirit of Independence rig, which is expected to drill the Cosmopolitan unit. But, those developments are three to five years from market, Stokes wrote.
In addition to those developments, Cook Inlet demand has changed slightly since PRA’s 2010 study, Stokes wrote. There has been a 9.4 percent reduction in demand because of more efficient electric generation and a .4 percent reduction due to wind power.
“What we are seeing is that there is probably not enough activity that will avoid a shortfall probably in the 2015 timeframe,” he said. “A shortfall in 2014 is if we shut down all activity right now, which we know is not going on.”
Stokes said the newly-commissioned Cook Inlet Natural Gas Storage Alaska facility will help producers fully utilize gas wells by allowing a year-round place for the gas to go. And, he said, if there is not enough production, the facility could be used to store imported LNG necessary to bridge the gap if a shortfall occurs.
“It is not creating new gas,” he said of CINGSA. “It obviously helps with peaking in the winter time, but if there is not enough gas to fill it up in the summer time, then you don’t have enough gas to handle the annual demand.”
Brian Smith can be reached at firstname.lastname@example.org.