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On April 7, 2010 Denali—The Alaska Gas Pipeline, LLC (Denali) filed a request for the Federal Energy Regulatory Commission (Commission) to approve its detailed plan for conducting an open season for the purpose of obtaining binding commitments for the acquisition of initial capacity on Denali’s Alaska Project (Alaska Project).

The Alaska Project is an undertaking advanced on behalf of Denali, a limited liability corporation formed by BP and ConocoPhillips to bring natural gas resources from the Alaska North Slope to North American gas markets. The Alaska Project, to be constructed and operated by Denali, would interconnect at the Alaska – Canadian border with a pipeline (Canada Project) to be constructed and operated by an affiliate, Denali Canada – The Alaska Pipeline (West), Inc. (Denali Canada), transporting gas from the interconnect with the Alaska Project approximately 1,020 miles to its terminus at the Alberta, Canada hub.

Below is a summary of the June 7, 2010 Commissioners order (Order) approving the plan for conducting an open season with modifications for Denali. More information on the Alaska Project or other Denali filings can be found on the Commission’s e-library system at http://elibrary.FERC.gov in the Denali docket PF08-26.

In the Order, the Commission addressed the following concerns raised by various parties commenting on Denali’s plan for open season:

** The Commission disagreed with BP Exploration’s contention that Denali’s creditworthiness requirements are discriminatory. The Commission found that Denali requires all bidders who are subsidiaries of larger companies maintain a credit rating at least at a level of its ultimate parent company or provide a source of collateral to guarantee its obligations to Denali. Denali states this obligation applies to all similarly-situated shippers. Therefore, the requirements are not discriminatory.

** BP Exploration argued that a provision in Denali’s proposed precedent agreement discriminates against recourse rate shippers as well as negotiated rate shippers in terms of being able to challenge rates, tariff terms and conditions. The Commission accepted Denali’s clarification to its proposed precedent agreement. Therefore, finding no discrimination. Denali’s precedent agreement allows a shipper to submit multiple bids, some at recourse rates and others at negotiated rates, though for each bid the shipper must elect either negotiated rates or recourse rates. For those bids where negotiated rates are elected, the shipper must agree to not challenge before the Commission the commercial deal struck between it and Denali. Further, the same shipper, if acting as a recourse rate shipper, is not precluded from challenging the recourse rate-related provisions of Denali’s tariff. Denali claims it is not restricting a negotiated rate shipper’s right to challenge the general terms and conditions of Denali’s tariff to the extent those terms are not addressed in the shipper’s negotiated rate agreement.

** The Commission ordered Denali to more clearly delineate in its open season notice the procedures it will follow for notifying bidders of any reduction in their maximum daily quantity allotment and also to explicitly provide bidders the opportunity to decline any reduced award of capacity.

** ConocoPhillips asked the Commission for clarification on how Denali would notify shippers of any design reconfiguration, or whether shippers would have the right to withdraw their bids as a result of such reconfiguration or the revised rate estimates. The Commission ordered Denali to modify its open season procedures to include a process for notifying bidders of any design reconfiguration that results in a material change in transportation rates or capacity allotment as a result of the precedent agreement and to provide bidders an opportunity to modify or withdraw their bids if there are changes to their capacity allotment or if rates are revised due to a reconfiguration of the system.

** The Commission ordered Denali to revise its proposed precedent agreement to remove a provision that would require a bidder to commit in advance to resubmitting a bid in the event the Commission requires Denali to hold a revised open season. The Commissions states that such a provision could require a prospective shipper to bid on capacity at a rate or under terms it no longer considers sufficient to its interests or acceptable.

** ExxonMobil requested that Denali explain how its proposed non-conforming bid and over-subscribed capacity processes would operate and how the proposal would ensure against undue discrimination or preference. The Commission accepted Denali’s reply comments regarding allocation of capacity in the case of over-subscription. Denali states that in order to qualify as a conforming bid, a prospective shipper’s bid must include a signed precedent agreement containing the appropriate information and must be received by Denali by the close of the open season. Any bid not meeting these requirements or containing conditions that materially change the terms of the precedent agreement will be considered a non-conforming bid. Denali states that it will provide an explanation to any prospective shipper who submits a non-conforming bid that is rejected by Denali. In the case of an over-subscription Denali will allocate capacity first to conforming bids submitted before the end of the open season, then to non-conforming bids submitted before the close of the open season which it ultimately accepts on a non-discriminatory basis. Denali’s use of pro rata allocation insures that shippers within the same category are not discriminated against.

** The State of Alaska raised objections to Denali’s confidentiality requirements with respect to access to materials the reading rooms. The Commission agreed with Denali that under the open season regulations, the only entities entitled to access Denali’s shipper reading room are potential shippers. Based on the competitive nature of the two competing Alaska gasline projects and the State of Alaska’s relationship to The Alaska Pipeline Project (being advanced by TransCanada and ExxonMobil), the Commission found Denali’s concerns reasonable. The Commission agreed that the confidential, proprietary, and competitively sensitive reading room information not be shared with State of Alaska representatives involved in the management oversight of the state’s interests in a competing pipeline project or for purposes other than acquiring capacity in Denali’s open season.

** The Commission is mindful of the State of Alaska’s concern that Alaska’s Constitution prohibits its representatives from agreeing to provisions concerning indemnification and injunctive relief. In handling this concern, the Commission borrowed from previous Trans Alaska Pipeline System (TAPS) proceedings where representatives of Alaska were not required to sign a non-disclosure certificate. However, Alaska was required to provide a list of employees to be granted access to protected materials and those employees were required to treat protected information as confidential pursuant to Alaska’s Executive Branch Ethics Act. The Commission directs that this TAPS model be utilized for the Alaska Project.

** The Commission found that the implementation procedures for standards of conduct designed by Denali adequately protect against a discriminatory open season. The Commission requires Denali to fully comply with the applicable standards of conduct imposed under all FERC Orders that have been issued since Denali filed its plan for open season.

 Denali’s proposed Alaska Project will consist of:

 ** the Alaska Mainline (a 730 mile-long, 48-inch diameter, high pressure pipeline) which is designed to transport up to 4.5 Bcf/d of pipeline quality gas from the outlet of the gas treatment plant to six in-state delivery points and the Alaska–Canada border where the pipeline would connect with the Canada Mainline;

** two transmission lines: a 36-inch diameter pipeline approximately 62 miles in length and designed to deliver 1.1 billion cubic feet per day (Bcf/d) from the Point Thomson Unit to a proposed gas treatment plant; and a 60-inch diameter pipeline approximately 1.2 miles in length and designed to deliver 4.6 Bcf/d from the Prudhoe Bay Unit Central Gas Facility to the gas treatment plant; and

** the gas treatment plant capable of treating and conditioning approximately 5.8 Bcf/d of Alaska North Slope gas and delivering 4.5 Bcf/d of pipeline quality gas on an annual average basis to the Alaska Mainline.

Denali has designed its project to include six delivery points within the State of Alaska. The first delivery point will be at the outlet of the gas treatment plant prior to final compression to provide treated, low-carbon dioxide gas for Alaska North Slope users. The other five in-state delivery points were identified in the In-State Gas Demand Study. Denali states that during the open season process, shippers may express interest in other receipt or delivery points and Denali will consider including such requests in its plan.

Denali proposes a 14 percent return on equity for its recourse rates and a 12 percent return on equity for its negotiated rates. Denali estimates a weighted average cost of debt of 5.1 percent for both recourse rates and negotiated rates. Denali states that it will finance its construction activities with a target of 70 percent debt and 30 percent equity, while it estimates that long term financing for operations will equal 75 percent debt and 25 percent equity. Denali states that rates will be designed using a straight fixed-variable cost classification. Denali further states that negotiated rates will be recalculated annually in order to assure that its rates recover all costs of providing firm service.

Denali proposes to establish three reading room locations where interested entities can review information related to the proposed project. The reading rooms will be located in Houston, Texas; Anchorage, Alaska; and Calgary, Alberta, Canada.

A recent report from a natural gas pipeline industry trade group estimates that half of the oldest, dirtiest coal-fired power plants in the United States could be at risk of retirement in the near term, creating a potential demand for an additional 2 trillion cubic feet of natural gas a year (an average 5.5 billion cubic feet per day).

That would be a 9 percent boost in total U.S. demand from 2009 consumption.

But whether the owners of those coal-fired power plants retire their generating facilities depends, in great part, on pending federal laws restricting carbon emissions and imposing costs on those emissions. The higher the cost of compliance, the more likely older coal-fired plants will be retired, with the potential for an increased reliance on gas-fired power generation.

The Interstate Natural Gas Association of America (INGAA) contracted with consultant ICF International to provide an estimate of the nation’s coal-fired generating plants that either lack emission "scrubbers," are not scheduled to receive scrubbers, or are too old and inefficient to justify the high capital cost of further emission controls.

The May 11 INGAA summary — "Coal-Fired Electric Generation Unit Retirement Analysis" — estimates that 50 gigawatts of coal-fired power generating capacity across the United States is at risk of retirement in the near term, with two-thirds of that capacity in Wisconsin, Illinois, Michigan, Indiana, Ohio, Kentucky, Tennessee, Mississippi and Alabama.

"A portion of this demand could be met by increasing generation at existing natural gas-fueled electric generation plants," INGAA’s executive summary of the report stated. "While natural gas generally is more expensive than coal," the summary said, gas emits fewer pollutants and "does not face the same pressures from impending environmental regulations."

Burning gas instead of running the older coal plants to generate 50 gigawatts of power a year could reduce carbon dioxide emissions by 170 million tons a year nationwide, the summary said. That would equal about 3 percent of CO2 emissions in the United States in 2006.

"A number of impending environmental regulations have created uncertainties about the ability of certain coal-fired power plants … to remain profitable into the extended future," the summary said, citing pending greenhouse gas regulations as "one of the largest threats to coal-fired power plants’ economic viability."

Of the approximately 310 gigawatts of coal-fired generating capacity in the country, almost half are running with pollution scrubbers and an additional 50 gigawatts have scrubbers under construction or permitted. The INGAA-funded analysis estimates that half of the remaining plants may be too old and inefficient to justify the expense of new pollution controls — making them prime candidates for retirement.

The INGAA estimate for potential growth in gas demand is within the range of a recent Congressional Research Service report — "Displacing Coal with Generation from Existing Natural Gas-Fired Power Plants" — which pegged the hypothetical growth at 1.2 tcf to 4.8 tcf a year (based on 2007 data).

Those numbers represent the range between 25 percent displacement and maximum displacement of coal by increased capacity utilization at existing gas-fired power plants.

The January 2010 congressional report includes, however, a cautionary note: "Natural gas markets have historically been exceptionally difficult to forecast. According to an EIA (U.S. Energy Information Administration) self-assessment of its long-term projections, ‘the fuel with the largest difference between the projections and actual data has generally been natural gas.’"

While coal-fired power plants face the high cost of cleaning up their emissions, the natural gas industry has its own dollar-sign demon — price volatility of the fuel. Whereas coal prices are relatively stable, gas-fired power is at the mercy of a much more volatile fuel commodity price.

Certainty of long-term gas supplies, accompanied by more stability in contract pricing, could reduce the volatility risk for electric utilities and other large customers, driving up demand for gas.

Another issue confronting the nation that could help boost demand for gas would be a change in utility regulation, said a report, "The Role of Natural Gas in a Low-Carbon Energy Economy," issued last month by the Worldwatch Institute.

Instead of requiring electrical utilities to order up power based on the lowest cost of generation (usually a coal-fired plant), a shift in power dispatch requirements to consider lower emission levels (usually a gas-fired plant) would boost demand for gas while reducing CO2 emissions, the report said.

But even if utilities want to switch from coal to gas, they might have trouble moving the power. "If the existing transmission network does not have sufficient capacity in the right places, then it may not be practical to move gas-powered electricity to loads currently served by coal plants without investing in upgraded or new power lines," said the January Congressional Research Service report on displacing coal with gas-fired power plants.

"Transmission congestion can increase costs to consumers by forcing utilities to depend on nearby inefficient power plants to meet load instead of importing power from more distant but less costly units."

All three of the North Slope's major producers, plus the State of Alaska, have submitted comments to the Federal Energy Regulatory Commission on the request for an open season filed by Denali - The Alaska Gas Pipeline (a joint venture between ConocoPhillips and BP). None of the comments oppose the open season that would start July 6 for the North Slope natural gas pipeline, subject to FERC approval, though all ask questions and offer suggestions.

Those comments include:

The State of Alaska disagrees with Denali's proposed restrictions on access to open season documents in the reading rooms that will be maintained by Denali. The pipeline developer, in its open season plans submitted to FERC, included provisions to shield commercial and competitive information from State of Alaska offices and officials that have a statutory relationship with Denali's competitor, the Alaska Pipeline Project (a partnership joint effort of TransCanada Alaska and ExxonMobil).  The Alaska Pipeline Project is the pipeline developer selected under the Alaska Gasline Inducement Act for state financial and regulatory support.

The State of Alaska, in its April 30 motion with FERC, said Denali's proposed restrictions on access to documents is too broad and could hinder the legitimate interests of the state as a potential shipper on the gas line. The state asks FERC to lessen the restrictions and to accept the state's commitment that officials with access to Denali information will not share it with the Alaska Pipeline Project representatives.

ExxonMobil, in its April 30 motion with FERC, said it supports FERC approval of Denali's open season, with some clarifications. The federal commission has the authority to order changes in an applicant's open season proposal.

ExxonMobil is asking Denali to more clearly identify how it plans to segregate in-state and out-of-state pipeline costs in establishing its rates, specifically as it affects rates for in-state shipment of gas. The producer also wants Denali to further explain its proposal to allocate over-subscribed capacity to non-conforming bids outside the open season.  ExxonMobil claims Denali does not sufficiently explain how it would allocate such capacity to non-conforming bidders.

BP in its April 30 comments filed with FERC asks that Denali's open season bid sheet should more clearly define the services that are offered to ensure that all bidders are bidding on the same service arrangements, especially as they relate to seasonal variations in the maximum daily quantity. The producer also objects to Denali's precedent agreement provision requiring bidders to commit to resubmitting their bids in the event that FERC requires Denali to hold a revised open season.  BP is concerned that bidders should not be required to commit to resubmitting a bid under unknown terms if FERC orders a revised open season.

BP objects to several of Denali's requirements for a bidder to show upstream and downstream capacity, including contracts with third-party upstream and downstream service providers in advance of the in-service date for the gas line. The producer also objects to Denali's provision that would allow the pipeline developer to back out of the deal at any time, without making a termination payment to potential shippers, while a shipper has only until Feb. 1, 2011, to back out without owing a termination payment.

BP would like to see more information in the open season documents on how Denali proposes to calculate and implement negotiated rates for the pipeline, and how shippers can challenge recourse rates for the project.

BP, with the longest list of questions/objections of any of the producers or the state, supports implementation of a tracking system to account for the ownership of the natural gas liquids in the line, which Denali has said it is willing to accommodate. ConocoPhillips also raised the gas liquids tracking issue in its April 30 motion filed with FERC. In its open season proposal, Denali said it would permit the establishment of a gas component tracking system funded by the shippers but ConocoPhillips wants FERC to require agreement by all shippers on the line before Denali could establish the system.

ConocoPhillips also asks for more information on the cost-of-service components that would be included in a levelized pipeline tariff; more information on how Denali would handle any reductions in a shipper's maximum daily quantity in the line; and more information on how Denali would notify potential shippers of any design changes in the project and offer bidders the option of withdrawing their bids.

And ConocoPhillips objects to a provision that would limit a shipper's right to oppose certain filings by Denali before FERC, calling the provision "extremely broad".

Denali filed its Open Season Plan with the FERC on April 7, 2010.  Denali is a limited liability company that was formed by North Slope producers BP and Conoco Phillips in June 2008.  It will conduct its open season in an effort to secure binding commitments from prospective qualified Alaska natural gas shippers (Shippers) for firm transmission line, Gas Treatment Plant (GTP), and transportation services. 

The Denali Project is designed to deliver approximately 4.5 billion cubic feet per day of natural gas to North American markets. The GTP at Prudhoe Bay will remove CO2 and dehydrate, compress and chill the gas in preparation for transport down the mainline. When completed, the GTP will be the largest facility of its kind in the world.

Denali and its affiliate, Denali Canada - The Alaska Gas Pipeline (West), Inc. (Denali Canada), are offering to construct and operate an Alaska natural gas transportation project to bring natural gas resources from the Alaska North Slope (ANS) to North American gas markets (Project). Denali would construct the Alaska portion of the Project (Alaska Project) and Denali Canada would construct the Canada portion of the Project (Canada Project).

Denali's cost estimate for the GTP and mainline is $35 billion dollars (2009 U.S. dollars). Denali expects the Project to be in service in 2020.  Denali is not offering a Liquefied Natural Gas (LNG) option in the Open Season, but based on its filing, it has not closed out the possibility of an LNG option.

The Alaska Project will consist of the following FERC jurisdictional facilities:

• Transmission Lines. Denali is planning two Transmission Lines: one beginning in the Point Thomson area and one beginning at the Central Gas Facility in the Prudhoe Bay Unit. The Transmission Lines will transport gas to the GTP.
• GTP. The GTP will be located in the Prudhoe Bay Unit on the ANS and is designed to receive gas from the producing fields and to treat and condition the gas for delivery into the Alaska Mainline. The GTP's services (gas treating and compression/chilling) will be unbundled.
• Alaska Mainline. The 730-mile Alaska Mainline will be a large diameter, high-pressure natural gas pipeline and related facilities for the transportation of natural gas from the outlet of the GTP to Alaska in-state delivery points (five in-state delivery points downstream of the GTP and one at the GTP) and the international border between Alaska and Canada.

The Canada Project consists of the Canada Mainline, which includes a large diameter, high-pressure pipeline and related facilities for the transportation of natural gas from the Alaska- Canada border about 1,020 miles to Alberta, Canada. In Canada, Denali Canada will offer connections to multiple pipelines to provide Shippers options for transporting their gas to North American markets.

Among the features included in Denali's offer are the following:

• If Denali does not receive commitments for at least 85 percent of the design capacity at Open Season, a framework for Shippers and Denali to work together to consider a scaled down project, a different project such as a pipeline to an LNG facility, or to generate additional commitments to allow the original Project to proceed.
• Unbundled transmission (transportation service on the Transmission Lines), GTP, and transportation services that allow Shippers to select only those services that are necessary to treat and transport each Shipper's gas to market;
• Terms that recognize the Project's significant economic uncertainty and risks, including decision points at Project milestones for a Shipper to decide whether to continue its participation as new Project information is developed;
• A minimum credit rating requirement of BBB (Standard & Poor's) or Baa2 (Moody's Investors Service, Inc.) and no minimum volume commitment to encourage smaller leaseholders, explorers, and end users to participate in Denali's Open Season;
• A levelized rate over 20 years for negotiated rate Shippers and a three year levelization period at the start-up of operations for recourse rate Shippers;
• Distance-sensitive rates based on mileage;
• No requirement that existing Shippers subsidize expansion Shippers; and
• Credit of 100 percent of the net revenues from interruptible and authorized overrun service to firm Shippers on a pro-rata basis.

Denali intends to take advantage of the modern, streamlined regulatory processes available in the U.S. and in Canada to progress the Project. In the U.S., Denali will proceed under ANGPA and the FERC's regulations with federal coordination assistance provided by the Office of the Federal Coordinator. Denali will also adhere to the right-of-way and permitting requirements of the State.

Denali Canada will apply to the National Energy Board of Canada (NEB) for a CPCN. The NEB, like the FERC, is mandated to evaluate projects - including in relation to competing projects - on the basis of the public interest. Additionally, the Canada Project will be advanced through a single, coordinated, and modern assessment process under the auspices of the Major Projects Management Office (MPMO).

Denali's Open Season Timeline as proposed:

Contact William Doyle, Director of Permits, Scheduling & Compliance at wdoyle@arcticgas.gov

IHS' 29^th Executive Conference, CERA Week 2010, took place last week in Houston, Texas. The Conference is a forum that offers insight to the energy future.  This year U.S. Secretary of Energy Steven Chu and Lawrence Summers, Assistant to the President for Economic Policy and Director of the National Economic Council, were keynote speakers.  Reports coming out of the conference are encouraging for natural gas. 

Secretary Chu talked about the promise of natural gas, which can be used for power generation.  He discussed the role of natural gas because it burns cleaner than coal and can be used as a bridge fuel that can play a role in the transition to other fuels in the future. White House Economics Advisor Lawrence Summers also acknowledged the role natural gas should play in future energy policy commenting on the remarkable opportunities created by all the natural gas that was not available five years ago.

At the Conference IHS Cambridge Energy Research Associates presented a special report titled "Fueling North America's Energy Future."  Key Findings in the special report include:

• North American discovered natural gas resources have increased by more than 1,800 trillion cubic feet (Tcf) over the past three years, bringing the total natural gas resource base to more than 3,000 Tcf, a level that could supply current consumption for well over 100 years
• Development of this expanded resource may be able to meet significantly increased levels of demand without significant increases in prices.
• Domestic natural gas supplies reduce the need for LNG imports into North America-which become a matter of choice rather than necessity.
• Natural gas has a lower carbon footprint-about half that of coal-and results in negligible emissions of sulfur dioxide (SO2), nitrogen oxides (NOx), mercury, and particulates in contrast to other fossil fuels.
• The newfound expansion of unconventional gas, combined with the expansion of LNG import facilities in the United States and Canada and increased storage, has introduced new supply shock absorbers to respond to disruptions and market imbalances.
• The major source for rapid growth in natural gas demand is the electric power sector. Power demand growth is extremely likely as new uses for electricity (possibly including electric vehicles) overcome the effects of energy efficiency and conservation.
• Much of any electricity demand growth will be met by gas-fired generation. Natural gas demand from the US power sector could grow from roughly 19 Bcf per day today to as much as 35 Bcf per day by 2030.
• Natural gas-fired power plants have cost, timing, and emissions advantages compared to coal-fired plants. However, natural gas use for power generation over the long term depends on how strict GHG emissions targets will be and how other competing or complementary technologies (nuclear, CCS, and renewables) develop over time.
• LNG exports from either British Columbia or Alaska (already an LNG exporter) may be competitive into high priced oil-linked Asian markets, but significant exports from the US Lower 48 are problematic.
• The abundance of new natural gas will increase the share of natural gas-fired generation in the North American power sector.
• It will expand the role of natural gas-fired generation technologies to back up renewable power resources-a new role for natural gas.
• Natural gas-fired generation consumed 3 Bcf per day more natural gas in 2009 than in 2008 when adjusted for the impact of the Great Recession. Displacement of coal-fired generation contributed significantly to this number. But there is a limited pool of "spare" gas-fired capacity that prevents wholesale displacement of coal with natural gas.
• In addition to this fuel switching, the power sector can reduce near-term CO2 emissions by replacing existing coal-fired plants with new gas-fired plants and converting existing coal fired plants to burning gas. This would require substantial investment and would result in growth of natural gas use. But power companies would be concerned about longer-term requirements to further reduce CO2, which would also affect gas-fired facilities.
• The power industry has a multiple-decade planning horizon. If the goals include cutting carbon emissions substantially over the long term, such as the often-cited 80 percent reduction by midcentury, aggressive development and deployment of zero-carbon technologies, including nuclear and CCS, will need to take place today.

Alaska has 35 trillion cubic feet of identified gas reserves, with average estimates of another 227 tcf of technically recoverable undiscovered gas. Alaska's natural gas needs to be part of nation's energy policy for the future.

Sources:  IHSCERA.com and Houston Chronicle

I am the Senior Project Engineer for the OFC and presented at the largest geospatial technology event for federal agencies, the Federal ESRI conference on February 19th. The session was Geoenabling Web Applications to Support Open Government and my presentation can be found here (PDF). As government strives to deliver greater transparency to the public, its web applications continue to incorporate more spatial intelligence. I focused on how GIS and geographic services bring richer, dynamic, and more collaborative mapping to government websites.

For years, Alaskans have discussed the need for better mapping and many of our project agencies identified a need for a single reference system for information collection. There is not a consistent, standard set of maps detailing the pipeline route in Alaska. Each state and federal agency has data pertinent to their mission; however, sharing that data and incorporation it into one authoritative basemap is instrumental to expedite permitting. We selected a 20-mile stretch of the pipeline route at Atigun pass as our prototype. We then used LiDAR for our basemap and flew the 20-mile stretch in the fall of 2009. With LiDAR we can detect geohazards, wetlands, conduct stream mapping, and ensure the engineering design meets specifications for frost-heave and permafrost construction.

Our goal is to demonstrate that the prototype is an authoritative, consistent, and integrated source of information that can be used by all parties to permit, design, construct, operate, and maintain a gas pipeline. The prototype has two separate platforms. An ArcGIS platform that the agencies will have access to and can layer their information on, and a public web platform that will provide public transparency to the project enabling more informed public comments and a value added database that can incorporate historical data.

The public transparency piece of the prototype is key and provides valuable information and visualizing to the communities and native tribes. The agency web service application provides an authoritative basemap and allows stakeholders to insert their layers and manipulate the data. This project is different in regards to multiple agency collaboration and therefore efficiency to expedite the project. Our next step is to acquire additional agency inputs and develop a data integration plan.

The OFC also participated in the Alaska Forum on the Environment (AFE) in Anchorage the week of February 8. AFE hosted over 1,700 attendees from diverse backgrounds including environmental professionals from government agencies, non-profit and for-profit businesses, community leaders, Alaskan youth, conservationists, biologists and community elders. The OFC hosted a booth at the AFE where we had access through the web to our prototype GIS for AFE attendees to try out the system. I also presented it to the group on February 9 and my presentation can be found here (PDF).

I had the opportunity to attend the winter committee meetings of the National Association of Regulatory Utility Commissioners this week in Washington, D.C. There were three full days of committee meetings on natural gas. Sunday set the stage for the week as there was much interest on recent studies related the abundance of natural gas in the United States. Much of the focus over the past year has been on shale formations and the assessment released by the Potential Gas Committee (PGC) in 2009. The assessment found that the United States possesses a total natural gas resource base of 1,836 trillion cubic feet (Tcf) and a total available future supply of 2,074 Tcf-the highest resources evaluation in the PGC's 44-year history, equaling about 100 years of supply. Americans consume an average of 22 Tcf per year.

It did not take long for the question to arise that with all this new natural gas available is there a need for an Alaska natural gas pipeline? The answer during Sunday's Subcommittee on Gas discussion was an unequivocal yes! Natural gas is the cleanest source of all hydrocarbons. With many of the nation's coal facilities 25 years of age and older, natural gas is the preferred future energy source for electric power generation. Moreover, municipalities throughout the country are looking to power their automobile fleets with clean burning natural gas. The message is clear; we need all the natural gas we can domestically produce to ensure the energy security of the United States. Finally, no matter what committee was in session-all roads led to job creation and the natural gas industry is part of the solution not the problem.

On Tuesday, the Committee on International Relations and Committee on Gas joined together to discuss natural gas as it relates to the United States and Canada. The panel discussion was chaired by the Honorable Gaetan Caron, Chairman and CEO of Canada's National Energy Board; and included panelists Bob Pickett, Chairman of the Regulatory Commission of Alaska; Jon-Paul Therot, Chairman of the Quebec Energy Board; and Phil Moeller, Commissioner of the Federal Energy Regulatory Commission. I must make the qualifying statement that the government officials from the United States and Canada were not speaking or otherwise representing the official positions of their respective boards, commissions and agencies.

It was an excellent panel discussion. FERC Commissioner Phil Moeller articulated that an Alaska natural gas pipeline is needed. He stated that regardless of what people think about natural gas it will become part of the electricity generation mix. Mr. Moeller even addressed the estimated price tag of the gasline that is approaching $40 billion. He did this by recalling his trip to Alaska's North Slope in the summer of 2008. During a break while visiting various facilities in Deadhorse, he and his colleagues sketched out a "back-of-the-envelope" calculation on the natural gas that is basically being produced but re-injected back into the reservoirs. They figured based on market prices at the time that Alaska producers were re-injecting nearly $35 billion per year back into the reservoirs every year.

Alaska's Bob Picket started off his presentation with a simple but resounding, "Alaska gas is good." He focused his comments on two main points: (1) our relationship with Canada is something the United States should not take for granted; and (2) unconventional gas is not a killer of an Alaska natural gas pipeline. His opinion was that Canada and the United States are the best of trading partners and energy is a key factor in the relationship. If it were not for Canada, the United States would be at the complete mercy of overseas nations for our vital energy supplies. Canada is #1 when it comes to working with the United States. On the same token, it was pointed out that the United States, with its increased domestic production of natural gas, is increasingly exporting more gas to Canada each year. The relationship between the two nations is invaluable. When it came to the discussion of natural gas, whether related to unconventional gas plays or the Alaska natural gas pipeline, Mr. Pickett, was firm, "The natural gas industry creates jobs; it is the cleanest of all hydrocarbons; the gas is domestically produced; it is integral to our energy and economic security; and we need to utilize it more." The loud and clear message delivered by Chairman Picket was, "It is time to stop treating natural gas as an orphan and stop leaving natural gas out of the policy discussions in the United States."

Alaska's natural gas is good!

This week OFC's Environmental Engineer Christa Gunn and I participated in the 2010 Pipe Tech Americas Summit in Houston, Texas.  It was well attended and included an overview on the massive cross-border Keystone pipeline project; emergency repair systems; risk based management; and horizontal directional and environmental air drilling.

As OFC's Director of Permitting, Scheduling & Compliance I was part of a panel discussion on the current challenges facing the pipeline industry.  The panel was moderated by Michael Felt of Universal Ensco and included Joe Paviglianiti of Canada's National Energy Board and Jerry Rau of Panhandle Energy Company. 

Jobs, jobs and more jobs was the focus of the panel's discussion.  I noted that the Alaska natural gas pipeline would be the largest privately financed construction project in the history of North America, creating tens of thousands of jobs over its lifecycle.  I summarized the two mainline natural gas pipeline projects, Alaska Pipeline Project (TransCanada-ExxonMobil) and Denali (BP-ConocoPhillips) and then focused on the recurring theme during the panel discussion: personnel, succession plans for an aging workforce and training.  I explained that Alaska has built a 52-acre pipeline training yard in South Fairbanks. The Fairbanks field site offers an environment that replicates the actual pipelines right-of-way, complete with frigid temperature workspaces, mechanized welding operations, heavy equipment operation, ditching, stringing and other associated pipeline construction machinery. The training facility is focused on training a new and rejuvenated workforce for the Arctic energy industry.

A recent announcement by Progress Energy that it will be decommissioning eleven coal plants by 2017 leaves room for more reliance on clean natural gas, pipeline infrastructure and job creation.  Moreover, with a recent INGAA Foundation report finding that $120-130 billion will be invested over the next 20 years in infrastructure in the natural gas industry, including pipeline construction and connecting arctic resources to support growth in the electric generation and industrial sectors-Alaska's natural gas pipeline projects were front and center.

Earlier this week the Federal Energy Regulatory Commission (FERC) held a public workshop on the Alaska Natural Gas Transportation project Open Season.  Over 100 individuals attended from various private industry groups and state and federal agencies.  Richard Foley and Todd Ruhkamp, FERC Washington DC staff, provided details on the project history, ANGPA, the Open Season process and goals, as well as how to provide electronic comments.  The goal of the Open Season is to promote competition in the exploration, development, and production of Alaska natural gas.  The Open Season process is flexible to allow project sponsors to market the project, yet allow for fair competition among prospective shippers.

The Open Season is held a minimum of 90 days, bids are evaluated, winners announced and precedent agreements (PA) negotiated.  PA's are a sensitive yet key step to the Open Season process where the project applicants and shippers agree on conditions.   FERC provided an example of the Ruby pipeline where it took approximately 2 years to sign the PA's.  Some conditions include options for carbon/greenhouse taxes, anchor PA's are approved by the state Commission, and creditworthiness requirements are satisfied.  Another noteworthy point is no bid can be rejected solely because a bidder has a bid pending in another Open Season.

A question from the audience was: will FERC accept comments after the 60 day window?  FERC would like to see comments prior so they can ensure they meet there timeline and that is one of the reasons they are providing workshops now to ensure the public is familiar with the electronic commenting process.  The workshop included a detailed explanation of the navigation of FERC's various electronic forms of information and communication.  Mailed comments will also be accepted and incorporated into the electronic database.

The FERC was asked to clarify how the process will work for the APP project since it is offering a LNG option.  FERC indicated that APP will provide two separate packages allowing for shippers to bid on both options.  The Environmental Impact Statement (EIS) and National Environmental Policy Act (NEPA) process is separate from the Open Season process however the project description is similar to resource report one, required in the NEPA process.

For those interested in Open Season, here are the FERC points of contact:

Denali and APP filings with FERC are available for review in FERC's Public Reference Room or may be viewed on the Commission's website at http://www.ferc.gov using the "e-Library" link http://www.ferc.gov/docs-filing/elibrary.asp.  Enter the docket number excluding the last three digits in the docket number field to access the document, TransCanada (APP) Docket No. PF09-11-000 and Denali Pipeline Project Docket No. PF08-26-000.  Also, FERC has a general Alaska page, http://www.ferc.gov/industries/gas/indus-act/angtp.asp, which includes a FERC Open Season Fact Sheet.

For assistance, contact FERC at FERCOnlineSupport@ferc.gov or call toll-free, (866) 208-3676, or for TTY, (202) 502-8659.  Richard Foley, regulatory gas utility specialist, Office of Energy Projects, Division of Pipeline Certificates, also can assist with questions. He can be reached at (202) 502-8955 or via email at richard.foley@ferc.gov.

Note: If proceeding(s) are protested, FERC Staff cannot discuss the case except to direct persons to the website.

Last month, I gave a presentation on challenges related to moving energy in the arctic, including moving arctic natural gas to North American markets, at a U.S. government High North Conference hosted by the U.S. European Command.

Experts discussed emerging arctic issues ranging from climate change to increased shipping, from seabed resources to international engagement, from research to strategic public diplomacy. Given my background with the Coast Guard, the Department of Transportation and now Alaska Natural Gas Transportation Projects, I was asked to address challenges related to the safe and environmentally secure delivery of energy resources.

As Alaska residents appreciate, the arctic is an amazing and complex ecosystem with unique characteristics and extensive natural resources. Although it seems obvious, its defining, but not always appreciated, characteristics include extreme cold and seasonal darkness not experienced by most on our planet. At 40 below, Fahrenheit and Centigrade temperature scales register the same, and 40 degrees below F/C poses unique challenges to any activity. Other fundamental challenges include vast distances, storms that dominate any operation, limited port, airport/ telecommunications/road infrastructure and brief summers. All add enormous costs. The arctic also is an ocean undergoing significant change. Sea ice has been diminishing and marine life is changing.
These factors, and the enduring concerns of indigenous people who have lived successfully in the arctic for thousands of years, affect arctic development and transportation.

Energy development in the U.S. arctic is not new. For 40 years, challenges have been met, and technology for exploration, development and transportation has steadily improved. For a natural gas pipeline, discontinuous permafrost and seismic pose particular challenges, but do not appear insurmountable.

By virtue of Alaska’s place on the globe, America is an arctic nation with broad, fundamental interests in the region. National security, economic development, environmental and natural resource issues, and resident indigenous people make the capability to anticipate and address the benefits and consequences of arctic activities essential. And, the proximity of other arctic nations makes close and forward-looking international cooperation imperative, whether the issue is natural gas or anything else.