Order Code RL34671
The Alaska Natural Gas Pipeline:
Status and Current Policy Issues
September 12, 2008
William F. Hederman
Specialist in Energy Policy
Resources, Science, and Industry Division
The Alaska Natural Gas Pipeline:
Status and Current Policy Issues
On August 27, 2008, the governor of Alaska signed legislation awarding a
license to TransCanada Alaska (TransCanada) to permit, develop, and build a natural
gas pipeline from Prudhoe Bay, Alaska, to the gas market hub in Alberta, Canada,
with $500 million of state support. Since the discovery of significant oil and gas
reserves in Prudhoe Bay in 1968, Alaska state and federal policymakers have sought
to accelerate bringing these important energy resources to market, especially to
market in the lower-48 states. The Trans Alaska Pipeline System (TAPS) began
shipping crude oil from Prudhoe Bay in 1978. Efforts to build a gas pipeline still
have achieved little progress 30 years later.
This report provides a brief review of efforts to develop and construct a natural
gas pipeline from Prudhoe Bay, a status report on recent efforts to proceed, and an
analysis of major relevant policy issues.
In 1976, Congress passed the Alaska Natural Gas Transportation Act (ANGTA)
as one element of a multi-pronged effort to respond to the natural gas supply
problems caused by earlier wellhead price controls. Engineering work was underway
on the pipeline when, in the early 1980s, the natural gas market in North America
entered a prolonged period of relatively low prices for natural gas because domestic
producers had responded vigorously to high prices during the phased decontrol of
wellhead prices through the Natural Gas Policy Act of 1978 (NGPA). Interest in
developing the pipeline waned because of the poor market prospects.
In 1997, the United States became a net importer of liquefied natural gas (LNG)
for the first time. In retrospect, this was a leading indicator of a tightening natural
gas supply for the North American market. Congress again promoted development
of the pipeline in the Alaska Natural Gas Pipeline Act (ANGPA) in 2004 and with
related amendments in the Energy Policy Act of 2005 (EPAct 2005).
The State of Alaska has pursued the natural gas pipeline development with a
sense of urgency for several years. In 2001, Alaska established an interagency task
force to move forward with a pipeline. The administration immediately preceding
the current governor reached a controversial agreement with the Prudhoe Bay
producers (ExxonMobil, BP, ConocoPhillips). The current governor proceeded with
a new initiative, the Alaska Gasline Inducement Act (AGIA) that has led to the
August 27 signing mentioned earlier.
Two producers, ConocoPhillips and BP, have formed Denali Pipeline to develop
a Prudhoe Bay-to-market pipeline without AGIA support. The third, and largest,
producer, ExxonMobil, has not supported any currently active pipeline development
Many challenges remain at this time. The key parties, however, appear
constructively engaged in the effort to make available this significant energy supply
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Historical Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Recent Developments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Alaska’s Selection Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Recent Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Current Status of AGIA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Policy Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Energy Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Open Access to the Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Project Risk Management and Sharing . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Diligent Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
International Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Alaska Economic Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Environmental Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
List of Figures
Figure 1. Alaska Oil and Gas Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
List of Tables
Table 1. Selected Dates from Alaska Natural Gas Development . . . . . . . . . . . . . 3
The Alaska Natural Gas Pipeline:
Status and Current Policy Issues
Forty years ago, major oil and natural gas resources were discovered at Prudhoe
Bay, Alaska. Since 1976, Congress has acted to promote the successful development
of a natural gas pipeline from the Alaska North Slope (ANS) to the lower-48 states.1
In the Alaska Natural Gas Pipeline Act of 2004 Congress established a statutory
finding of public need for this project, stating in Section 103(b)(2) that:
(A) a public need exists to construct and operate the proposed Alaska
natural gas transportation project; and
(B) sufficient downstream capacity will exist to transport the Alaska
natural gas moving through the project to markets in the contiguous United
On August 27, 2008, Alaska’s governor signed legislation into law that
officially awarded to TransCanada Corporation (TransCanada) a license to permit,
develop, and build an Alaska natural gas pipeline from Prudhoe Bay, Alaska, to the
lower-48 states with $500 million from the state. At full initial capacity of 4.5 billion
cubic feet per day, this pipeline could initially supply an amount equal to about 7%
of U.S. natural gas consumption in 2007.2
This report provides a brief review of the history of efforts to develop this
project, a report on recent developments and project status, and a summary of
remaining policy issues and the project outlook at this time.3
Since the discovery of the major natural gas and oil reserves on the Alaska
North Slope in 1968, Congress has passed several measures to encourage the
development of the natural gas resources there. Table 1 presents several highlights
of this process.
Alaska Natural Gas Transportation Act of 1976 (15 U.S.C. Sec. 719 et seq.).
U.S. Energy Information Administration, Natural Gas Monthly, April 2008, Table 2.
CRS reports on this subject include CRS Report, Major Alaska Gas Pipeline Issues — A
Perspective, by Alvin Kaufman, Gary Pagliano, Joseph Riva, and Susan Bodilly, October
17, 1979 and CRS Report RL33716, Alaska Natural Gas Pipelines: Interaction of the
Natural Gas and Steel Markets, by Stephen Cooney and Robert Pirog, updated March 28,
In 1976, Congress passed the Alaska Natural Gas Transportation Act (ANGTA).
The purpose of that legislation was to provide for sound decision-making on the
natural gas transportation system that provided for Congressional and presidential
participation in the process and to expedite construction and the start of operations.
Briefly, the policy steps of the process moved expeditiously, all completed in 1977.
In step one, the Federal Power Commission transmitted a recommendation of one of
three transportation system options (May 1977), the land-based pipeline route along
the Alaska Highway.4 Two alternatives were land-based pipeline systems and one
was a combination pipeline across Alaska and an LNG export terminal in Valdez.
In step two, the president recommended the same Alaska Highway alternative
(September 1977). In step three, Congress approved the president’s decision through
a joint resolution. That may have been the last time this project proceeded according
to the original plan.
In the winter of 1977-1978, the nation experienced serious problems with
natural gas deliveries through the interstate market because of the distortions of
wellhead natural gas price controls. These price controls had been driven by a
Supreme Court decision in 1954 (Phillips Petroleum Co. v. Wisconsin, 347 U.S.
672). In response to these delivery problems, Congress passed the Natural Gas
Policy Act of 1978 (NGPA) and the Powerplant and Industrial Fuel Use Act of 1978
As natural gas supply and demand began to respond favorably to the energy
policy legislation of 1978, the desirability of the Alaska natural gas transportation
system declined.5 Moreover, in an often repeated pattern for major U.S. energy
supply projects, cost estimates for this transport system increased. Natural gas prices
softened significantly as a natural gas supply “bubble” developed, and persisted for
years, in response to wellhead price decontrol.6 Commercial attention to the Alaska
gas pipe initiative essentially disappeared during the 1980s.
Although the full pipeline project made no progress, as Canadian natural gas
supplies from the Western Canadian sedimentary basin increased in the late 1970s
and early 1980s, producers from the province of Alberta, Canadian authorities, and
U.S. and Canadian pipeline companies worked to pre-build the downstream legs of
the Alaska Natural Gas Transportation System (ANGTS) from Alberta to California
and to the Midwest. The concept was that Canadian producers would loan the gas to
the U.S. consumers and be repaid in kind when the Alaska North Slope supplies
arrived. This concept led to tight provincial regulatory scrutiny of reserves-toproduction ratios as Canadian producers sought export approvals from Alberta
The Federal Power Commission (FPC) was the predecessor of the Federal Energy
Regulatory Commission (FERC).
See discussion in D. Fried and W. Hederman, “The Benefits of an Alaska Natural Gas
Pipeline,” The Energy Journal, Vol. 2, No. 1, January 1981, p.22.
A natural gas supply “bubble” is a temporary oversupply of capacity to produce natural
The Western leg of ANGTS was Pacific Gas Transmission, and it went into
service from Alberta to California in 1981. The eastern leg of ANGTS (Northern
Border Pipeline) went into service in 1982.
Table 1. Selected Dates from Alaska Natural Gas Development
Prudhoe Bay oil and gas discovered
United States begins export of LNG to Japan from south central Alaska
Alaska Natural Gas Transportation Act (ANGTA) passed, P.L. 94-586
Presidential Decision and FPC Report to Congress on ANGTS
FERC (successor to FPC) issues conditional certificate for pipeline
TAPS oil pipeline into service (ANS natural gas re-injected)
Office of Federal Inspector (OFI) established
“Western leg” of Alaska gas pipeline (Pacific Gas Transmission) prebuild into service
“Eastern leg” (Northern Border Pipeline) pre-build into service
Maritime Administration study of alternatives to pipeline released
United States becomes net importer of LNG for the first time
Alaska Natural Gas Interagency Task Force established (State Dept.,
Dept. of Interior (including MMS and BLM), Dept. of Transportation,
Dept. of Energy (including FERC))
Alaska Natural Gas Pipeline Act passed, Division C, P.L. 108-324
New governor announces Alaska Gasline Inducement Act (AGIA)
Five proposals submitted for AGIA consideration
Governor determines one AGIA proposal meets AGIA criteria
Conoco Phillips and BP announce the Denali Project as an alternative to
an AGIA project
Alaska legislature approves governor’s AGIA recommendation and it
In response to the lack of progress on the land-based pipeline system, the U.S.
Maritime Administration authorized a study of marine system options in the 1980s
to determine whether there might be commercial opportunities for the U.S.
shipbuilding industry. The results indicated roughly comparable economics for the
pipeline and LNG options to the U.S. west coast. LNG sales to the Pacific Rim
generally had greater economic potential, but were not politically viable in terms of
the large energy exports that such options could entail.7
In 1992, approximately 13 years after the Office of the Federal Inspector had
been established to expedite the Alaska natural gas pipeline project, it shut down.
In 1997, U.S. imports of LNG began using the lower-48 receiving and
regasification facilities built during the 1970s. The United States imported enough
LNG that, for the first time, imports exceeded the approximately 60 billion cubic feet
per year exported from the Cook Inlet/Kenai Peninsula of South Central Alaska. This
milestone proved to be an early indicator of a tightening supply situation in the
Serious reconsideration of the construction of a natural gas pipeline from the
Alaska North Slope began around 2000. One important sign of the renewed interest
was the inclusion in the 2001 National Energy Plan of the recommendation to
expedite construction of a natural gas pipeline from the Alaska North Slope to make
deliveries to the lower-48. Also in 2001, the Alaska natural gas interagency task
force formed. This task force included the State Department, the Department of the
Interior (including Bureau of Land Management and the Minerals Management
Service), the Department of Transportation, and the Department of Energy (including
the Federal Energy Regulatory Commission).
In 2004, Congress passed the Alaska Natural Gas Pipeline Act. Among its
clarified that the Federal Energy Regulatory Commission could
consider any application under the Natural Gas Act or the Alaska
Natural Gas Transportation Act;
created an Office of the Federal Coordinator (OFC);
provided for a loan guarantee of as much as $18 billion;
provided for accelerated tax depreciation (7 years versus 15 years);
provided for an enhanced oil recovery tax credit for the cost of a gas
treatment plant on the Alaska North Slope; and
established guidance to ensure the Federal Energy Regulatory
Commission would regulate the open season capacity bidding
procedures so that access to pipeline capacity would become
available to parties beyond the three major Alaska North Slope
producers to promote competition in Alaska North Slope
development of natural gas.8
The Federal Energy Regulatory Commission issued a final rule on the open
season matter on February 9, 2005 (FERC Order No. 2005).
W. F. Hederman, “A Review of Marine Systems Use in Developing Alaska Natural Gas,”
SPE 11294, SPE Hydrocarbon Economics and Evaluation Symposium, March 2, 1983,
Division C, Public Law 108-324.
The Energy Policy Act of 2005 (EPAct 2005), also addressed the Alaska natural
gas pipeline. In Section 1810, Congress required that the FERC submit to Congress,
on a semi-annual basis, reports describing the progress made regarding licensing and
building the pipeline.9
There are four projects that are being actively promoted at this time. Two are
mutually exclusive to transport Alaska North Slope natural gas to the lower-48 states,
the TransCanada project and the Denali project. Two smaller projects focus on intraAlaska issues: the “bullet line” to South Central Alaska and an LNG project with a
pipeline to Valdez that could proceed with varying levels of supply.
In January TransCanada submitted the only proposal to the Alaska Gasline
Inducement Act (AGIA) process that the governor judged complete. This proposal
resembles the original Alaska Natural Gas Transportation System (ANGTS).
TransCanada has stated that it will not be responsible for natural gas treatment into
the pipeline and will only accept pipeline quality gas into the pipe. It also stated a
willingness to develop the gas treatment facilities if necessary.
The pipeline would follow the Trans-Alaska Pipeline system (TAPS) past
Fairbanks to Delta Junction then follow the Alaska Highway to Alberta, Canada. The
natural gas would move through Alberta via TransCanada’s existing pipeline
network. The natural gas would continue to the lower-48 states via the ANGTS prebuild lines and other existing pipeline capacity. Through AGIA, TransCanada would
receive $500 million from the state of Alaska to support its expenses to prepare cost
estimates, environmental work, etc., for an open season for potential shippers and for
applying to the FERC for a certificate and tariff.10 The original capacity of this
pipeline would be between 4.5 to 5 billion cubic feet per day (Bcf/d). According to
FERC staff, it would be expandable to 5.9 Bcf/d with compression only,11 which
means expansion to this level would be relatively low cost.
Conoco Philips and BP, two of the three major Prudhoe Bay natural gas
producers, have made a proposal outside of the AGIA process to build a pipeline.
This BP Conoco Philips Denali Project (BPCPDP) would follow a similar right of
way (ROW) to the TransCanada project. BPCPDP would include a gas treatment
facility and would consider the option of new pipelines through Alberta and to the
lower-48 states if deemed necessary.
P.L. 109-58, 119 Stat. 594(2005), 42 U.S.C. Section 15801 et seq.
In an “open season” process, all parties wishing to become shippers can compete for
available capacity on a pipeline. There are no special rights for existing shippers or other
FERC, Sixth Report to Congress on Progress Made in Licensing and Constructing the
Alaska Gas Pipeline, August 29, 2008, p. 8.
Figure 1. Alaska Oil and Gas Pipelines
Source: Adapted from CRS Report RL31278, Arctic National Wildlife Refuge, Figure 6, based on
Energy Department maps.
The other two proposals are of more local interest than national interest. An
in-state plan for a new pipeline linking Anchorage and other parts of south central
Alaska, as proposed by Enstar, Inc. and the Alaska Natural Gas Development
Authority (ANGDA), recently gained approval from the governor of Alaska. This
pipeline would initially run about 450 miles from Cook Inlet to Fairbanks (in central
Alaska). If necessary (for instance, if a large pipeline is not operational when needed
for in-state Alaska demand) then a small diameter “bullet line” may extend to the
Brooks Range (north Alaska) to bring natural gas south to Fairbanks, Anchorage, and
other Alaska markets. This pipeline would have an in-service target date of 2013 and
deliver 460 million cubic feet per day for a cost of approximately $3 billion.
Finally, a project option that began with all-Alaska project proposals would
involve an extension to Valdez on the southern coast of Alaska of the main line
natural gas pipeline to the lower-48. This line would deliver an unspecified volume
of natural gas to be liquefied for export as LNG either to North American or other
markets. The intent would be for Alaska to participate in some value-addition
economic activity. With the announcement of state support of the other projects, the
prospects for the LNG option appear less likely.
Alaska’s Selection Process
When Alaska’s new governor took office in December 2006, she reiterated her
commitment to make progress on an Alaska gas pipeline a priority for the state. In
2007, Alaska passed the Alaska Gasline Inducement Act (AGIA), proceeded with a
Request for applications (RFA), and determined that one application was complete.
In a related development, the state of Alaska announced it was taking back the
oil and gas leases of the Point Thompson unit on the ANS because the unit operator,
ExxonMobil, had failed to meet development obligations. This matter is now in the
Alaska received five applications through the AGIA process:
1. TransCanada Pipelines Ltd. and Foothills Pipe Lines, Ltd. (TransCanada)
proposed a pipeline that would follow a route similar to the ANGTS route for the
originally approved project. TransCanada would not be responsible for the gas
treatment plant on the ANS and the pipeline would stop at Alberta and connect with
the existing TransCanada Alberta network (Alberta hub).
2. Alaska Gasline Port Authority, a municipal entity (City of Valdez, Fairbanks
North Star Borough, and North Slope Borough), proposed a natural gas pipeline from
the ANS to Valdez, where the gas would be liquefied and exported, providing added
value within Alaska.
3. Alaska Natural Gasline Development Authority (ANGDA) proposed a
smaller capacity lateral line to link from whatever major line was selected to move
gas to South Central Alaska (Anchorage and other locations) to make up for
declining production there.
4. Little Susitna Construction Company and a subsidiary of China Petroleum
and Chemical Corporation (Sinopec) proposed a pipeline from the ANS to Valdez
in the south where the gas would be liquefied and exported to the Pacific Rim.
5. AEnergia LLC, a startup formed by persons with large engineering project
experience, proposed an ANS to Alberta pipeline that would be jointly owned by the
producers (74%), the State of Alaska (25%), and AEnergia (1%).
The state determined that one application, TransCanada’s, was complete. That
is the only project that advanced to the evaluation step. Alaska awarded
TransCanada the AGIA license on August 27, 2008.
During the state AGIA process, Conoco Phillips sought out-of-time
consideration for a project that did not meet the AGIA requirements. This proposal
was quickly rejected. In April, Conoco Phillips and BP announced a joint proposal,
the Denali Project. ExxonMobil, a major player in any successful development, has
expressed both objections and support (for no project in particular) for developments
Bradner, Tim, “Exxon continues work at Point Thompson site,” Alaska Journal of
Commerce, September 7, 2008; story available at [http://www.alaskajournal.com/stories/
The governor dismissed the BP Conoco Phillips Denali Project proposal. Other
state and federal energy policy makers have welcomed the Denali proposal.
The results of recent reports prepared for the state of Alaska were presented at
recent legislative hearings in the AGIA process.13 A project cost/schedule and tariffs
analysis appears to provide input for the overall net present value (NPV) analysis.
This cost/schedule analysis presents a range of cost estimates.14 The range, however,
appears rather narrow in light of the recent general cost escalation on energy products
and services and the specific costs escalation announced for another North American
Arctic gas development project, the Mackenzie Valley project (now above $16
billion (Canadian)) for this 760 mile pipeline.15
The net present value analysis prepared for the State calls the TransCanada
project economics “robust” and finds benefits for all stakeholders across a “wide
range of project cost outcomes,”16 but there is not adequate information in the
presentation posted on the AGIA website to assess these results independently.17
Current Status of AGIA
The Alaska Legislature held special sessions called by the governor to consider
the AGIA proposal. Legislative meetings occurred in multiple locations around
Alaska. The recent approval means that TransCanada will get $500 million from the
state to support TransCanada’s next steps in the project approval process. In
particular, TransCanada must proceed to an open season and to apply for a certificate
from the FERC. The state funds will help pay for these steps.
Policy issues related to the construction and operation of an Alaska natural gas
national energy supply,
open access to the pipeline,
project risk management and sharing,
diligent development of the resources,
The AGIA website is located at [http://gov.state.ak.us/agia/].
AGIA Analysis Technical Team, B. Sparger and E. Briel, “Analysis of Project
Costs/Schedules & Tariffs,” Alaska Gasline Inducement Act Legislative License Hearings,
Juneau, ALASKA, June 6-10, 2008.
“Net Present Value (NPV) analysis,” State of Alaska - Anchorage Special Session, June
AGIA website: [http://gov.state.ak.us/agia/].
Alaska economic development, and
Prudhoe Bay on the north slope of Alaska is the largest oil accumulation in
North America. The production of the associated and dissolved natural gas has
implications for oil production. Early in the efforts to proceed with the natural gas
pipeline, some expressed concern that continued reinjection of the co-produced
natural gas could damage the structure of the reservoirs and harm oil production.
Reservoir simulation modeling and actual results ultimately proved this concern to
Advanced enhanced oil recovery techniques now use the natural gas and
condensates to maintain oil production at levels above those that would result from
natural decline rates. The Alaska Oil and Gas Conservation Commission must
approve natural gas production rates after reviewing potential effects on oil
production. The potential natural gas reserves on the ANS exceed 100 trillion cubic
In 1995, the U.S. Geological Survey (USGS) estimated that the ANS may
contain as much as 590 trillion cubic feet of in-place gas in the form of hydrates.19
This immense resource base remains unavailable at this time because there are no
commercially viable technologies to produce methane from hydrates.
In 2008, the USGS completed an assessment of undiscovered conventional oil
and gas resources in all areas north of the Arctic Circle that applied a geology-based
probabilistic technique. The results indicate that more than 1,600 trillion cubic feet
of natural gas, 44 billion barrels of natural gas liquids, and 90 billion barrels of oil
remain to be found in the Arctic. The extent to which these resources are under
United States territory or other Arctic nations has not yet been determined.20
The vast resources proven and expected from Arctic Alaska have provided
strong reasons to get a natural gas pipeline in operation.
The ANGPA found that an Alaska natural gas transportation project would
provide specific significant economic benefits to the United Sates and Canada.
Recent independent gas producer assertions, however, suggest that technology
advances for gas shales in the last two to three years may assure strong lower-48
USGS Open File Report 2004-1440, Conventional Natural Gas Resource Potential,
Alaska North Slope, by David W. Houseknecht, December 13, 2004.
USGS Open File Report 2004-1452, Alaska North Slope Gas Hydrate Energy Resources,
by Timothy S. Collett, no date.
Available at [http://geology.com/usgs/arctic-oil-and-gas-report.shtml].
domestic natural gas supplies for the foreseeable future.21 Whether these new
assertions affect pipeline project financing for the Alaska project remains to be
Open Access to the Pipeline
An important policy concern regarding development of this pipeline is that it
provide a means for all potential natural gas producers on the ANS to transport gas
to market through it. If the three Prudhoe Bay producers were to build a private
pipeline with no capacity for others, it would not provide an incentive for additional
exploration and production from others on the ANS. The FERC has required open
access on this pipeline.22
Project Risk Management and Sharing
This pipeline project would be the largest civilian construction project in the
history of North America. Current cost estimates range from $26 billion to $40
billion. It would likely take at least ten years from approval to completion/operation.
Its developers and their financial backers would face immense execution, financial,
market, and political risk. Congress has acknowledged the magnitude of these risks
and authorized up to $18 billion of loan guarantees to help address the risk challenge
(ANGPA 2004, P.L. 108-324). The congressionally approved $18 billion loan
guarantee relates to the risks associated with a potential drop in delivered natural gas
values compared to current forecasts. Although current prices and forecast prices are
high, natural gas prices and the outlook for future prices can change.
Currently, it appears that an Alaska natural gas pipeline would operate under
tariffs approved by the Federal Energy Regulatory Commission (FERC) for the
United States and by the National Energy Board (NEB) for Canada. The pipeline
operators would have contractual commitments from shippers for transporting gas
through the pipeline.
Producers and the state of Alaska might face financial risk on the price of the
natural gas produced. The value of the natural gas on the Alaska North Slope would
be the market value where the pipeline delivered the gas minus the tariff payment to
deliver the natural gas to market. As currently envisioned, the Alaska North Slope
producers would be the shippers. Local gas distribution companies (LDCs) or other
natural gas consumers or marketers could also commit to transport contracts with the
pipeline. In the case of LDCs, it appears that most state regulators would not approve
the necessary long-term contracts at this time.
See, for example, Navigant Consulting, Inc., North American Natural Gas Supply
Assessment, July 4, 2008.
Regulations Governing the Conduct of Open Seasons for Alaska Natural Gas
Transportation Projects, FERC Stats. & Regs., Regs. Preambles ¶ 31,174 (February 9,
2005); 70 Fed. Reg. 8,269 (February 18, 2005) (Order No. 2005) and Regulations Governing
the Conduct of Open Seasons for Alaska Natural Gas Transportation Projects, FERC Stats.
& Regs., Regs. Preambles ¶ 31,187 (June 1, 2005); 70 Fed. Reg. 35,011 (June 16, 2005)
(Order No. 2005-A).
Federal policymakers may want to make sure that all participants in this project
accept a fair share of the risks so that they will take responsibility and be accountable
for successful implementation. For example,
Supply risk appears minor but the Point Thompson natural gas may
be necessary to realize the economies of scale on the pipeline. The
state of Alaska and ExxonMobil continue to dispute the pace of
development there. This dispute could endanger the timely
availability of these natural gas volumes and harm project
Construction risk appears serious with regard to cost overruns.
Given the recent cost escalation experienced in energy projects
generally, the potential for this project to cost more than the $26
billion (U.S. dollars)23 initial estimate appears likely and to exceed
the highest estimates heard to date, $40 billion, remains possible.
Engineering completion risk appears small. All the potential project
developers (BP, Conoco Philips, ExxonMobil, and TransCanada)
have relevant and appropriate scale pipeline system engineering
Market risk appears moderate in terms of the potential market value
at time of delivery. The Canadian Energy Research Institute (CERI)
has reportedly estimated that market value for the natural gas would
need to exceed $10 (Canadian) per million Btu for the project to be
viable.24 Because it appears producers must deliver the natural gas
to Alberta or the lower-48 states, the market risks fall on them. This
explains the importance to them of control over project costs, which
affect the netback value at Prudhoe Bay. Alternatively, gas
distribution companies or other natural gas purchasers could also
purchase pipeline capacity and assume some market risk. Current
state regulatory practice does not appear to encourage such long term
commitments. This is a policy area that would benefit from
additional analysis but is a state-level issue.
The three Prudhoe Bay producers have sought guarantees on Alaska
tax and royalty policy that the state has viewed as unreasonable. On
long-term, multi-decade agreements, flexibility from all parties is
often a key to successful agreements. Rather than locking all factors
down permanently up front, agreeing to the timing of renegotiation
and the range of acceptable variations might provide a faster path to
Unless specifically mentioned otherwise, all dollars are in current U.S. dollars.
P. Howard, D. McColl, D. Mutysheva, and P. Kralovic, Ensuring Market Access: The
Capacity of Western Canada’s Natural Gas Pipeline System, Canadian Energy Research
Institute, Study No. 113, 2008.
TransCanada, in its AGIA application, also proposed another
measure to mitigate financial risks. This proposal, known as the
Bridge Shipper proposal, would have the United States federal
government take the risk for unused capacity were the pipeline
finished and there were not adequate natural gas flowing to use the
capacity. TransCanada points out that it is prepared to proceed with
the pipeline without such Bridge Shipper support and provided it as
an “outside the box” idea invited by Alaska in the AGIA invitation.
If the pipeline were built with 4.5 billion cubic feet per day (Bcf/d)
capacity and no natural gas producers or customers signed on for
capacity, the levelized annual bridge shipper contingent liability for
all capacity could be as high as approximately $3 billion (nominal)
per year for 25 years.25 The primary purposes of this proposal
appear to be (1) to buttress the attractiveness for those who might
finance the project and (2) to allow the project to proceed without
Prudhoe Bay producer commitments so that it will be easier to make
the case later on that these producers are not working diligently to
develop the resource.
The magnitude and complexity of the risks for this project have always
presented challenges for success — and for project start-up. There is little reason to
expect these challenges to diminish significantly.
The slow pace of development on the Alaska natural gas pipeline has led some
pipeline proponents to conclude that the Prudhoe Bay producers would prefer not to
develop these resources at this time. This controversy has expanded on the ANS
when, in April 2008, the Alaska State Department of Natural Resources terminated
ExxonMobil’s lease in the Point Thompson unit east of Prudhoe Bay. ExxonMobil
disputes the termination and this matter will likely end up in the court system for
many years if there is no settlement.
Recent announcements by ExxonMobil indicate they intend to proceed with
Point Thompson development activity. They have also indicated a willingness to
move forward on a Prudhoe Bay to lower-48 pipeline.26 Progress on the pipeline may
require progress on Point Thompson, as well.
Any onshore pipeline from Alaska to the lower-48 states must go through
Canada. Canada has cooperated with the United States for decades on a variety of
matters related to this pipeline (e.g., the pre-build segments in the early 1980s).
$1.96/MMBtu x 1.067 MMBtu/1 mcf x 4.5 million mcf/day x 365 day/year = $3.4
See, for example, Dow Jones news service, “Exxon: Set to work with TransCanada,
Conoco, BP on Alaska Pipeline,” August 7, 2008, 2:40 PM EST.
Canadian matters that could affect an Alaska natural gas pipeline include the
Mackenzie Valley pipeline; TransCanada’s certification; the Alberta pipeline
network status; oil sands development (which could consume significant quantities
of natural gas as fuel); and Alberta natural gas production.
The Mackenzie Valley in the Canadian Arctic contains an estimated 6 trillion
cubic feet of natural gas. It was discovered at approximately the same time as the
Alaska North Slope gas at Prudhoe Bay. At one time, development of Mackenzie
Valley gas appeared likely to be through a spur line connecting to the pipeline from
Alaska. That configuration appears less likely today and Canadian interests hope to
proceed with a Mackenzie Valley pipeline before the Alaska pipeline project
Mackenzie Valley gas, if developed, may go to the oil sands of northern Alberta
to provide fuel for the steam generation required to produce crude oil there. The
demand for steel and pipe for a Mackenzie Valley project are significant, and it is not
clear that there is adequate, large diameter pipe reduction capacity in the entire world
to serve both Alaska and Mackenzie Valley projects at the same time. Supporters of
the Mackenzie Valley pipeline intend to precede the Alaska project. Mackenzie
Valley pipeline supporters fear that if the Alaska line is completed first, then the
economics for their pipeline may not remain viable.
TransCanada’s ownership of Foothills Pipe Lines, Ltd., which was certificated
for the section of the Alaska pipeline through Canada in Canada’s Northern Pipeline
Act (NPA, section 21), with the right-of-way approved (pursuant to section 37 of the
NPA), has been an important consideration throughout Alaska pipeline discussions.
At this time, there appears to be the expectation that in ten years, when Alaska
natural gas could start to flow through Alberta, there will be spare capacity in the
Alberta pipeline grid. The treaty provisions included in the NPA appear to commit
to providing sufficient capacity without specifying a capacity figure, and there is no
sunset date in the legislation.
Oil sands development has accelerated in northern Alberta and costs have
increased as pressure mounts for the available labor and other input requirements.
Much of the Mackenzie natural gas is expected to serve the growing oil sands load.
Alberta gas production has been declining. There is the potential that
unconventional gas production could reverse this trend but there is no concrete
evidence of a turn-around at this time.
Another potentially important policy matter relates to the quantities of natural
gas reaching the lower-48. The proposal to end an Alaska natural gas pipeline at the
Alberta border and use the Alberta pipeline grid, the Alaska natural gas transportation
system pre-build lines to California and the Midwest, as well as other pipelines
downstream of Alberta into the lower-48 is possible because Alberta natural gas
Mackenzie Natural Gas Pipeline
production is declining. This decline has left spare capacity that could be used by the
Alaska natural gas traversing Canada. Given that the rationale for federal support of
the Alaska natural gas pipeline is to increase lower-48 natural gas supplies, there is
the potential for misunderstanding if Canadian exports to the United States decrease
as Alaska natural gas arrives. This matter may require some attention before the
Finally, on the international dimension, other nations have expressed interest in
a role in ANS natural gas pipeline development. China’s Sinopec participated in the
AGIA process as a partner with Little Susitna Corporation in an application judged
incomplete. More recently, the chairman of GazProm has expressed an interest in
participating in the BP and Conoco Philips Denali Project.28
Alaska Economic Development
The Alaska natural gas pipeline project has important implications for the state’s
economic health through construction job creation and revenue generation from
production royalties. In addition, the presence of a major interstate pipeline from the
ANS to the lower-48 would change the economics for many local energy markets
within Alaska. For example, both TransCanada and Denali have agreed to provide
up to five delivery points within Alaska. This can allow local communities without
natural gas service to gain service if they are near the pipe right-of-way.
Presumably one of the delivery points would link with the Anchorage-Fairbanks
gas bullet line. This would allow ANS natural gas to flow south to Anchorage and
other South Central Alaska markets when Cook Inlet production declines. There
might also be a development opportunity for a relatively small pipeline to South
Alaska for LNG exportation. This would be another local value-add and job
generator. TransCanada has also assured the State that if shippers preferred to go to
South Alaska for an LNG system, they would accommodate that.
The addition of the significant natural gas supplies from Alaska’s north slope
to the lower 48 fuel supplies is generally considered a positive development in terms
of the environment. The immensity of the roughly 1,750-mile construction project
has caused some concern about potential environmental effects to the land and
wildlife near the construction area.
Congress has addressed this issue by delegating the Federal Energy Regulatory
Commission as the lead federal agency to assure all environmental regulations of the
national environmental policy act (and EPA) are met and that relevant agencies
worked to meet environmental impacts statement deadlines established by the
commission. In recognition of the complexity of this particular project, Congress
created an Office of the Federal Coordinator (OFC) to enhance coordination and
progress. Canadian regulators also coordinate with the OFC.
Charles Ganske, “Gazprom may bid on Alaska Pipeline,” WorldPoliticsReview blog, June
A concerted effort by the State of Alaska and other interested parties has
resulted in new momentum to proceed with an Alaska natural gas pipeline from
Prudhoe Bay to the lower-48 states. Many challenges remain at this time. The key
parties, however, appear constructively engaged in the effort to make available this
significant energy supply option.