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State says line on schedule, on budget Alaska commissioners of Natural Resources, Revenue, report to legislators on the state-backed TransCanada gas pipeline project Kristen Nelson Petroleum News
The AGIA-licensed Alaska Pipeline Project is on schedule and on budget, Alaska’s commissioners of Revenue and Natural Resources said in a report to legislators released Oct. 31.
The report, the second biannual report on progress of the project licensed under the Alaska Gasline Inducement Act, is a supplement to reporting required under AGIA.
In May 2008 the Revenue and DNR commissioners recommended issuance of a license to TransCanada Alaska and Foothills Pipe Lines; after a review the Legislature approved the recommendation on Aug. 1, 2008; the license was issued and signed by the commissioners on Dec. 5, 2008.
TC Alaska announced commercial alignment with ExxonMobil in the project in June.
The AGIA license provides a dedicated AGIA coordinator with authority to expedite permitting; fixed tax and royalty terms for a specified period of time for gas committed during the project’s first open season; and up to $500 million reimbursement from the state for qualified expenditures.
In exchange, TC Alaska made certain schedule, tariff and expansion commitments to the state.
AGIA requires a status report to the Legislature on reimbursements within the first 10 days of each regular session.
The commissioners said that in addition to information required under AGIA, the report includes information related to the progress of the pipeline project and updates on natural gas markets and capital cost expectations.
Reimbursements The report said the Department of Revenue began developing an electronic information management system for monitoring and control of reimbursement requests from TransCanada in early 2009. The first phase focused on design of the reimbursement and workflow; the second phase focused on technical design and construction of the electronic system.
The first phase is largely complete, the report said, and recent work has focused on refining technical system requirements.
The report said Revenue has been working closely with TransCanada on “the detailed reporting standards required to meet both technical and regulatory requirements for reimbursement submissions.” The standards, which will allow submissions to be accepted electronically, have taken more front-end work than was anticipated, “but is critical in order for the state to efficiently review, verify and track expenditures submitted in the future.”
Reimbursement requests are filed once each quarter, but expenditure information is submitted monthly, allowing Revenue to review expenditures in a consistent and timely manner.
AGIA requires periodic audit of the licensee and Revenue said it has contracted with a consultant for the first annual audit. Initial meetings with the audit firm will take place in mid-November, followed by coordination with TransCanada.
The report said the audit will most likely begin in the first quarter of 2009.
TransCanada submitted its first request for reimbursement in late September for work conducted in December 2008 and in the first quarter of 2009, allowing the state to conduct its first technical review of the company’s reimbursement requests. The report said Revenue requested additional information and is working with TransCanada’s staff to complete the necessary content revisions. The department expects to process the reimbursement request in November.
First reimbursement of $1.3 million The amount of reimbursement requested for December 2008 and the first quarter of 2009 is expected to total slightly more than $1.3 million; for the second quarter of 2009 the state’s contribution is expected to be slightly less than $3.8 million.
Based on TransCanada’s third-quarter 2009 budget report update, total spending through the AGIA license will total $691.76 million. The report said numbers are expected to change in the upcoming quarter to reflect additional restructuring efforts associated with TransCanada’s alignment with ExxonMobil.
TransCanada’s original estimate of $83 million in spending prior to the open season has been increased by approximately $67 million and the total spend prior to the open season is now expected to be some $150 million, allowing the companies “to provide a more refined cost estimate and project schedule” for the open season.
ExxonMobil joints project The report said the commercial alignment TransCanada announced with ExxonMobil in June provides an ideal arrangement for the licensee, which said in the AGIA application that it would prefer not to own or develop the gas treatment plant and would approach third parties to assess interest in the GTP.
TransCanada will continue to have a lead role on pipeline and compression engineering, the report said, while ExxonMobil will take the lead “on general project management duties, and on technical work associated with the GTP.”
The overall project schedule remains the same, the report said, but some work was moved forward including a request for pre-filing with the Federal Energy Regulatory Commission; establishing and staffing a project office in Midtown Anchorage; and undertaking additional field programs.
In addition to the increase in the budget to $150 million for work underpinning the open season, project management has been augmented with some 100 full-time equivalent positions, about half TransCanada and about half ExxonMobil; and the scope of the URS contract for GTP engineering work was expanded “to improve the quality and credibility of the design and cost estimate,” the report said.
The TransCanada-ExxonMobil commercial alignment also enabled the project to use the 2002 Alaska Gas Producers Pipeline Team study and trans-Alaska oil pipeline owners’ information.
“Correspondence and subsequent meetings with the Point Thomson and Prudhoe Bay operators has provided the project with access to information related to the potential gas supply for the project, as well as the opportunity for site visits and for validating assumptions.”
Significant progress The report said “significant progress” has been made on the base design and cost estimate for the open season, with the project “on schedule and on budget for submitting a plan to FERC” for the 2010 open season.
Work on the GTP is on schedule and on budget for year-end deliverables, the report said, with evaluation of the expected input and output gas component and selection of the gas handling process completed to facilitate the estimate basis.
The physical layout and module basis for the GTP have been finalized; infrastructure and logistics plans for construction are being reviewed; and evaluation of GTP capacity is under way to ensure the open season offerings are clear.
Pipeline and facility planning is on schedule; execution planning and schedule analysis are under way; and development of the design basis and cost estimate for the Valdez liquefied natural gas option is on schedule.
Technical field programs in Alaska included: 111 borehole samples taken on the Alaska corridor; LiDAR, light detection and ranging data, acquired for the mainline and the LNG pipeline corridors; a ground-based geophysical program executed; and immersive video, a 360-degree view, acquired for the route in Alaska with the exception of 60 miles in the Atigun Pass area.
The report also said work moved ahead on logistics for moving pipe, materials, equipment and manpower. Infrastructure evaluation work is under way and meetings have been held with port facilities, the Alaska Railroad and the Alaska Department of Transportation and Public Facilities.
In preparation for the open season there are ongoing discussions with potential shippers in Alaska and Canada, for both the mainline into Alberta and the Valdez LNG options.
An in-state gas study is under way with completion expected late this year.
These activities lead to the filing of required documents for FERC review of the 2010 open season plan package at the end of January, with the 90-day open season scheduled to begin in May and conclude at the end of July.
“However, this process may be delayed for a short period if the FERC determines it needs more than 60 days to review the January 2010 filing,” the report said.
Project personnel are located in Anchorage, Calgary, Whitehorse, Houston and Denver; additional space was acquired in Midtown Anchorage and will be used by the project team. The Anchorage Key Bank location will serve as the commercial and public affairs location.
Meetings with pipe mills Monthly monitoring reports are attached to the main report.
The May report said TransCanada believes several Japanese steel mills and one from Europe can meet its requirements for 48-inch X80 pipe, although a number of other mills around the world, including in the United States, have the potential of being able to meet TransCanada’s requirements.
The May report said all the mills that have the potential of meeting the requirements will be invited individually to TransCanada’s Calgary offices to be “introduced to details behind the TransCanada requirements and discuss the capabilities of their particular mill.”
The mills will be asked to return once they have analyzed TransCanada’s requirements and “understand the costs, if any, to upgrade their mill to meet these requirements.”
The August report said the project team has met with four companies that are close to being able to provide the required pipe, and said that the team will meet with six to eight additional companies over the next few weeks.
The companies are being asked to provide information to assist the protect team in estimating the cost of needed pipe.
Capacity of GTP The May report said the design for both the pipeline and the gas treatment plant require they be capable of processing and transporting 4.5 billion cubic feet per day in the summer.
“A pipeline that is designed for this summer capacity can transport more gas in the winter because the colder ambient temperatures in the winter make the gas turbines at the compressor stations capable of producing more power.”
Winter ambient temperatures also reduce the temperature of the gas, reducing the requirement for gas compression.
The report said TransCanada is evaluating two alternatives.
One is to assume less flow in the summer and more flow in the winter — with an average of 4.5 bcf a day. The other is to transport 4.5 bcf a day in the summer and as much gas as the pipeline is capable of carrying in the winter.
The second option requires that the GTP be “larger to accommodate the larger winter volumes.”
The monthly reports did not include a resolution of this issue, but the July report said the expected inlet capacity of the GTP is some 5 bcf per day.
Seismic issues The May report said TransCanada is working on the potential impact of seismic activity, including “a review of the effects on the pipeline due to ground displacement at the seismic faults” but also including liquefaction and landslide issues.
The report said TransCanada completed a workshop with State of Alaska subject matter experts and plans a similar meeting with Canadian officials.
“There are many historic faults along the pipeline corridor but the project will determine which ones are active and intersect the pipeline route.”
“Consideration will be given to slightly changing the route to minimize the number of intersections with active faults.”
To deal with active seismic faults which could cause significant ground movement the line could be put above ground as the trans-Alaska oil pipeline has done or buried in a material, such as plastic balls or foam, with almost no shear strength.
The July report said active seismic faults along the pipeline route have been identified and are being used in the preliminary pipeline design. The design for crossing the faults is not complete, but the report said that for purposes of the cost estimate the project team “is assuming that the pipeline will be above ground while it crosses the seismic faults.”
Limited HDD The May report also said that TransCanada has been studying horizontal directional drilling for crossing watercourses and has determined that for stiff pipe such as the 1-inch-thick 48-inch-diameter pipe required for the project, the angle of the pilot hole — through which the main pipe would be pulled — “must be very shallow as the pipe can flex only a small amount.”
Once a pilot hole is drilled it is reamed out until it is significantly larger than the main pipe; in the case of this project the final hole would be about 5 feet in diameter.
The preliminary determination TransCanada has made is that for this project the shortest HDD would be about 2,100 feet long and because of limitations on the force used to pull the main pipe through, the maximum length possible would be about 5,900 feet.
There are other factors influencing use of HDD at a particular crossing, the report said, but because of the limitations TransCanada estimates “there will be a limited number of HDDs” on the pipeline project.
The June report noted that the original length of the pipeline as estimated in TransCanada’s AGIA application was approximately 750 miles in Alaska and approximately 965 miles in the Yukon and British Columbia, a total of 1715 miles.
TransCanada has refined the route and used more detailed route maps and estimated lengths are now 734 miles in Alaska and 966 in Canada, a total of 1,700 miles.
“This total length may experience additional changes as the project’s route is more accurately defined,” the report said.
Prudhoe Bay questions The May report said TransCanada had met with Prudhoe Bay unit owners, including ConocoPhillips, BP, Chevron and ExxonMobil. TransCanada had sent the owners a 10-page list of questions. “The purpose of the meeting was to establish contact, discuss confidentiality issues, to elaborate on the technical questions and to discuss the scope and timing of a requested site visit.”
The unit owners agreed to discuss TransCanada’s requests and provide a response on how best to move forward.
The June report said the unit owners responded to the request for a site visit and to TransCanada’s questions, and in June a number of TransCanada, ExxonMobil and TransCanada engineering consultant staff met with the Prudhoe Bay engineering group, which answered “many of the questions” raised by TransCanada.
The report said the Prudhoe Bay unit is establishing a common information site “that would provide specific answers to all potential pipeline project proponents,” and facilitated a site visit to the Prudhoe Bay facilities.
The September report said that current thinking is that construction of the Alaska portion of the pipeline will require two winter construction seasons and the summer in between; in Canada the expectation is the same “except it may be necessary to add an additional summer season before the first winter construction season.”
The report said this continues to be reviewed and is subject to change.
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