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Vol. 17, No. 53 Week of December 30, 2012
Providing coverage of Alaska and northern Canada's oil and gas industry

ASAP to carry lean gas

In-state gas line plan simplified — no NGLs, lower pressure, no straddle plant

Kristen Nelson

Petroleum News

Plans for ASAP, the Alaska Stand Alone Pipeline, have been simplified, with the proposal to ship natural gas liquids removed from the plan, allowing for lower pipeline pressure and easier offtake along the line.

The optimized plan also has a larger, 36-inch diameter pipe, allowing the project to use industry-standard pipe, fittings and valves, Frank Richards told the Alaska Legislature’s Joint In-State Gas Caucus Dec. 20.

Richards, manager of pipeline engineering for the Alaska Gasline Development Corp., established by the Legislature in 2010 to develop a natural gas pipeline project, said the new design premise contrasts with the proposal presented to the Legislature in 2011, which called for a 737-mile, 24-inch, high-pressure line. The proposed pressure, 2,500 pounds per square inch, was required because of the enriched gas composition, he said.

But the 2,500 psi pressure meant that a straddle plant was required to deliver natural gas to Fairbanks, “a plant that would allow the natural gas liquids that were entrained in that gas stream to be pulled out, gas to be depressurized” for shipment to Fairbanks. The extracted NGLs would also have to be “reinjected back into the line and then brought down to Cook Inlet where there was going to be a natural gas liquid, or NGL, extraction facility,” Richards said.

The straddle plant made the tariff higher for Fairbanks than for Anchorage, a feature of the 2011 plan which drew considerable objection from Fairbanks legislators.

‘Awash’ in NGLs

The facilities needed for NGLs are expensive, Richards said, that plan was based on “a market where natural gas liquids were at a premium,” and that premium for NGLs was going to help reduce the cost of natural gas for citizens of the state.

“However, the world has changed in the last couple years,” he said. “Now we see that the world is awash with natural gas liquids,” because of Lower 48 shale gas production, and NGL prices “have softened considerably, down nearly 60 percent over the last couple of years.”

There is “an NGL glut in the Lower 48,” Daryl Kleppin, AGDC’s commercial manager, told the caucus.

Kleppin said companies have been losing money on the NGL portion of their business, although petrochemical companies are benefitting from the NGL glut because they can make product from very low-priced feedstock.

Alaska’s “problem is that we have to transport those components over 700 miles and pay the tariff on them and the tariff is, well in most cases would be higher than the end value of the product,” he said.

Kleppin said that in conversations AGDC has had with potential shippers, “no one really had an interest in those components.” And “it makes the project a lot simpler if you take those out.”

Components no longer needed once NGLs are taken out of the plan include straddle plants for offtake along the line, the NGL extraction plant, a fractionation facility and intermediate compressor stations.

Entraining NGLs in the gas stream required a higher pressure.

“The higher pressure of 2,500 psi meant that we were not at industry standard piping, fittings and valves,” Richards said. The “high-pressure pipe comes at an extreme premium” for the pipe, the fittings and the values, raising the cost of the project.

And the enriched gas stream, at higher pressure, meant fewer takeoff points because of the high cost of straddle plants, limiting “the amount of gas available to Alaskans along the route.”

Evolution of project

Richards said the project evolved.

As AGDC looked at the engineering and economic aspects of the project, modifications were made to meet the charge AGDC had been given or providing natural gas in “the quickest possible timeframe, (at the) lowest possible cost to Alaskans.”

With the elimination of NGLs, the pipeline size was increased to a 36-inch diameter and the pressure decreased to 1,480 psi, “industry standard for not only the pipe, but the valves.”

The bill would allow AGDC to issue revenue bonds, project financing based on the merits of the project, and allow for confidentiality so that AGDC can exchange data with commercial entities and other state agencies.

The elimination of compressor stations along the line reduces the operating costs and the environmental footprint, he said.

Tariff drivers

With the changes in the project, including how the tariff is calculated, the projected tariff is lower, Kleppin said.

One change is that the tariffs are now calculated over a longer period, 30 years vs. 20 years in the 2011 plan.

Capital cost estimates have been updated and contingencies for different components have been adjusted, Kleppin said.

The key components of change are the lower operating pressure and the 36-inch diameter vs. the original 24 inches.

There is still a lot of engineering work required before costs can be finalized — and the requirements of shippers are not yet known, he said.

With the changes, the tariff is still within the original range for Anchorage, but the Fairbanks tariff “is significantly lower” with the main driver there elimination of the straddle plant, the cost of which was borne only by Fairbanks.

Cost at $7.7 billion

The current cost, on a plus or minus 30 percent basis, is $7.7 billion, compared to the $7.5 billion estimate in 2011.

“Inflation over the last year has added almost $200 million to the cost of the original concept, so $7.7 (billion) is essentially the cost estimate for both project,” Richards said, with and without NGLs. Each year of project delay adds 2.5 percent to 3 percent inflation to the cost of the project.

The optimized plan has “less risk going forward” without the NGL component and the higher pressures in the line.

The cost to consumers at the burner tip for the optimized case is $9-$11.25 per million Btu in 2012 dollars in Anchorage and $8.25-$10 per million Btu in 2012 dollars in Fairbanks. That compares to the 2011 case of $9.63 per million Btu in Anchorage and $10.45 per million Btu in Fairbanks.

Contingent on funding

Richards said AGDC received $25 million in this year’s capital budget and has “been able to continue some of the pipeline engineering work” and is initiating some of the facilities engineering work.

But staying on schedule, with an open season in 2014, a go/no-go decision in late 2015 and first gas in late 2019, “really depends on what we receive in funding and how much work we’re able to do,” he said.

If AGDC is again partially funded work would be done on advancing the pipeline and facilities, with limited field investigations.

“If we’re fully funded then we will advance through what is known as the front-end loading 2 phase of our design for both pipelines and facility engineering to get us to that class 3 estimate for an open season,” Richards said, with heavy engagement with regulators, including the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, but also environmental regulators, followed by “a very extensive engineering field investigation program in 2013 to advance those projects.”

The state’s contribution, including some $73 million AGDC has already received, would total $400 million “to advance the project through to project sanction.”

“That’s getting through an open season, successfully acquiring shippers and purchasers of the gas, and then getting to a point of having to decide whether to go/no-go on the project to the next phase ... build out,” Richards said.

For consumers

The optimized cost and tariff means that consumers in “Anchorage will see rates ranging from $9 to $11.25 per million Btu in 2012 dollars. That’s comparable to what we’re likely going to be paying in 2013, with the cost increases that we’re hearing from our utilities,” Richards said.

That compares to the 2011 base case, with NGLs, of $9.63, he said.

In Fairbanks, “the optimized case provides gas at $8.25 to $10 per million Btu as opposed to the $10.75 we were projecting last year,” and compares to some $23 per million Btu Fairbanks is now paying, based on the cost of diesel for home heating.

“And then any community along the line that wants to tap in and have natural gas as an option for their home heating or power generation would see comparable rates available to them. And any resource developer that is looking to provide for jobs and resource extraction could gain access to reasonably priced gas,” Richards said.

Confidentiality issue

Richards said many of the features of House Bill 9, which passed the House but got no traction in the Senate in the 2012 legislative session, “are still needed to be able to move this project forward.”

We need sufficient funding, he said, and because AGDC lacks confidentiality abilities which were included in HB9, because “we are subject to the open records act, and then folks feel that they can’t really share anything with us without it being flat open to the world.”

Ownership of the line is also an issue that needs to be determined, he said.

AGDC is working to determine that the project would be economically viable, “but in the end there’s going to have to be a builder-owner-operator and we need that ability to make that decision.”

Regulatory Commission of Alaska statutes are also an issue, because they “currently don’t cover contract carriage.” The current law is common carriage, he said, which means anybody that wants to ship gas is granted access.

The challenge is illustrated by utilities, he said, who need to know that volumes they expect are available to meet their power load requirements. With common carriage, existing shippers would be forced to reduce their rates to accommodate the new shipper, and “the end user, the utility” would get less gas.

“Under contract carriage it is a contract between the shipper and the buyer of that gas” and the utility knows that they will receive that volume.

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