There is a lot of natural gas on the North Slope, but bringing it to Southcentral Alaska in a bullet line won’t be cheap.
“I can tell you this much: Anyone that wants to just believe that you can get gas from Prudhoe Bay (to Southcentral) without huge anchor tenants for the same price as we can get gas from 20 miles away just isn’t living in reality.”
That comment, by Dan Fauske, CEO and executive director of the Alaska Housing Finance Corp. — and president of its newly formed subsidiary, the Alaska Gasline Development Corp., pretty much summed up the progress report on the Alaska Stand Alone Gas Pipeline presented to AGDC July 1.
That meeting saw work completed by the Alaska Stand Alone Gas Pipeline team headed by Bob Swenson, the in-state gas coordinator, turned over to the Joint In-State Gasline Development Team established by the Legislature in House Bill 369.
Major AGDC players include Fauske, long-time head of AHFC, who was on former Gov. Sarah Palin’s Alaska Gasline Development Act team; Bryan Butcher, the newly named vice president of AGDC, who is AHFC’s director of governmental relations and public affairs; and Dave Haugen, AGDC project manager.
Members of the development team established by HB 369 include Fauske; the in-state gasline coordinator, previously Swenson but unnamed on the AGDC website; Harold Heinze, CEO of the Alaska Natural Gas Development Authority; Commissioner Leo Von Schelben of the Alaska Department of Transportation and Public Facilities; and John Binkley, chairman of the board of the directors of the Alaska Railroad Corp.
Volume the issueThe problem with cost is volume. A pipeline tariff — which reflects the cost to process the gas for transportation and then to move it to market — is spread over the volume of gas moved. The smaller the volume, the higher the cost per unit, and Southcentral Alaska lacks large industrial users of natural gas, so the cost to residential users would be high.
How high became clear as Swenson and members of that team presented costs of the pipeline and facilities required for a bullet line project, and translated those costs into cost of service to consumers.
The bullet line, Swenson noted, was evaluated by Enstar and others in 2008. The team headed first by Harry Noah and then by Swenson, working out of the governor’s office, built on that work.
HB 369 passed the torch to a new team. Swenson said the transition began he June when he started working with Haugen and his team to transfer the work done to AGDC.
The work done in the last six months is on the standalone pipeline down the Parks Highway, he said.
The work being delivered to AGDC “really gives the critical baseline data to move forward” and the tools necessary “to be able to analyze all the different configurations and look at what’s going to optimize the pipeline,” Swenson said.
The work product delivered “is a project specification necessary to evaluate and optimize project development,” which will be the job of Fauske and the AGDC team, he said.
The cost of service estimates provided bracket the economic scenarios, allowing “reasonable and well-informed decisions.”
The goal of the engineering effort was development of a fast-track pipeline for 2016, Swenson said, and the “credible cost estimates and set of decision support tools” will allow the AGDC to evaluate and develop the plan the Legislature set out in HB 369.
The cost estimatesKeith Meyer of Michael Baker Jr., the project engineering manager, said parallel groups worked on estimates for the pipeline and for the facilities. The cost estimate presented last year, he said, was for the pipeline only.
Another pipeline estimate was done at the end of last year, Meyer said, because the route had changed a little bit and they wanted to verify all the specifications before they were turned over to the cost estimator.
On the facilities side there were a number of scenarios so analysis was done by cost blocks, Meyer said, “so I could take out a cost block and put it in where it was needed in an area” as different scenarios were evaluated.
The pipeline cost at $3.8 billion is about the number presented last summer, Meyer said, but is now broken down into construction, materials, engineering and permitting.
At high flows of gas 11 compressor stations would be needed on the line; at low flows, zero compressor stations.
The cost breakdown for the pipeline includes: $1.8 billion for construction of the 24-inch mainline; $40 million for construction of a 12-inch lateral to Fairbanks; $900 million for materials; $300 million for engineering and permitting; $200 million for communications; $200 million for construction and right-of-way support; and $400 million for owner’s management costs.
Facilities more complicatedFacilities were broken down by scenarios, Meyer said, and grew out of work with the commercial group which included the North Slope producers and the major utilities.
Four cases were developed, all using Prudhoe Bay gas because the composition of the gas is known and it’s a known reserve, and also, he said, because “it has a realistic difficulty and that is that it needs conditioning,” removal of impurities such as carbon dioxide. Cook Inlet gas, and Gubik gas — discussed in the past for a bullet line — require no conditioning.
Meyer said the base case has Prudhoe Bay residue gas (what’s left for re-injection after you take out liquids for transport on the trans-Alaska oil pipeline and for use in miscible injection) being conditioned on the North Slope at a gas treatment plant; natural gas liquids would be extracted in Fairbanks and Cook Inlet.
“The TransCanada-Exxon project and the Denali project use this scenario, except the NGLs are extracted in Alberta in Canada,” said Bill Sparger, president of Energy Project Consultants.
The second scenario, Meyer said, uses the same Prudhoe Bay residue gas, but conditioning will be done in Cook Inlet, so the gas treatment plant will be built in Cook Inlet, “The idea being that we’d get rid of some of perhaps the remote costs that are associated with the labor on the North Slope.”
The third scenario takes out the NGLs on the North Slope, and transmits only utility-grade gas down the line.
And the fourth scenario is “spiked” — “we’re going to put extra NGLs into this line; we’re going to enhance the energy density of this gas.”
They also looked at four different volumes: 250 million cubic feet a day, addressed to current demand; plus 500 million, 750 million and 1 billion cubic feet per day.
The volume issueThe problem, Meyer said, is that Cook Inlet is the target and the Cook Inlet gas price is the target, but there is an expensive gas treatment plant and hundreds of miles of pipeline.
One way to address this, he said, is to move more energy down the line.
That can be done by pushing up the volume or by changing the energy density of the gas.
With economics likely to be challenged at lower volumes, Meyer said the team looked at what would happen with higher volumes and also at what would happen if the energy density was increased.
Putting conditioning facilities in Cook Inlet did result in savings, Meyer said, while spiking with NGLs produced the most expensive project because it involved “a lot more processing and fractionation to get those NGLs going.”
Facilities costs ranged from $1.9 billion for 250 million cubic feet a day with Cook Inlet conditioning, to $8 billion for 1 billion cubic feet a day spiked with NGL.
Overall costs, adding in the pipeline, ranged from $5.7 billion for the 250 million cubic foot case with Cook Inlet conditioning to $11.8 billion for 1 bcf a day spiked with NGL.
Feeding the economic modelSparger, with Energy Project Consultants, took the information developed by Michael Baker Jr. and used it to develop input for the economic model which produced the cost of service.
“The cost of service, as we defined it, is the cost to the consumer — whether that consumer is residential or industrial,” he said, and was developed using an industry-standard commercial model which had been enhanced by Black & Veatch for the state’s Alaska Gasline Inducement Act process.
The transmission component is what Michael Baker Jr. developed costs for, including the pipeline, the gas treatment plant, the NGL facility, Sparger said, and along with the distribution component which is what the local utility charges to get the gas to the consumer it’s all included in the cost of service.
The commodity cost — what it costs to buy the gas from the seller — is an unknown and appears in Black & Veatch figures as a range of possible prices superimposed on the transmission and local distribution costs.
On the commercial side what impacts the cost of service includes things such as the debt-equity ratio, cost of debt, expected return on equity and length of contract term.
Talking about the different scenarios, Sparger said that the second scenario, with CO2 extracted in Cook Inlet, impacts the amount of natural gas that is moved on the line, since CO2 takes up about 12 percent of the volume. A reduction in natural gas also occurs with scenario four, which is spiked with NGL, because “these NGLs are taking up space in the pipeline that could be used for natural gas.”
In addition to the scenarios described, the state also asked for an analysis of cases in which the market for North Slope natural gas grew and volumes were ramped up from 250 million to 500 million cubic feet a day two years after service in the line began, to 750 million three years after that and to 1 bcf a day three years after that. Another case addressed very rapid market growth, going from 250 million to 1 bcf in three years.
Cost of service modelingMike Elenbaas of Black & Veatch, who led the cost of service study, said the question addressed was projected tariff calculations and sensitivities for the scenarios analyzed.
Assumptions included a 70-30 debt-equity split and 2017 as the first year that the pipeline would be full, he said.
For the base case (conditioning on the North Slope; NGLs removed in Fairbanks and Cook Inlet) at 250 million cubic feet per day the tariff was estimated to be $15.81 for one dekatherm or approximately 1,000 cubic feet to the customer, including the local distribution charge. Adding in the cost of the gas — shown as a range of possibilities on Black & Veatch’s graphs — could raise the total cost of service to between $20 and $25 compared to the current Enstar rate of $8.10 (the cost of gas plus Enstar’s local distribution charge).
Elenbaas said they used a range for the gas commodity cost, and didn’t try to forecast what commodity costs would be in the future.
While the cost of gas to Enstar customers in the future is an unknown, Black & Veatch’s graph of base cases (250 million cubic feet per day) showed the overall cost of North Slope gas on a bullet line could be double what is paid now even with increases in the cost of gas to Enstar customers from sources other than a North Slope bullet line.
The tariff range for 250 million cubic feet a day doesn’t vary much with gas conditioning in Cook Inlet and shipment of utility grade gas, but drops to around $13 with the NGL-spike scenario, although Elenbaas noted the spiked case is a substantial increase of NGLs to the market, and would require an increase in the liquids market.
Elenbaas said they modeled the impact of an increased market for gas, looking at cases of 500 million, 750 million and 1 bcf per day (noting on the resulting graph that the AGIA limit for another state-supported gas pipeline is 500 million cubic feet per day).
At 500 million cubic feet per day the tariff (pipeline transmission and local distribution combined) drops to about $12, Elenbaas said, with further drops as the volume of natural gas increases.
These amounts are exclusive of the cost of gas, and assume market expansion.
Charts referenced in this story are available online at www.ahfc.state.ak.us/agdc/links.cfm.