Pipeline and LNG terminal developments may arrive too late to prevent a natural gas disaster.
For exactly two months, MidAmerican Energy sponsored a $6.3 billion project to bring stranded natural gas from Alaska's North Slope to an adjoining pipeline in Canada. But when Alaska's Department of Revenue rejected MidAmerican's proposal for an exclusive partnership to develop the pipeline, the company pulled out.
"We believed our request to be the state's sole development partner for the initial project development period was reasonable, given the magnitude of the risk involved," says Robert L. Sluder, president of the project company, Alaska Gas Transmission Co.
The Alaska pipeline is not dead; Other companies, including a consortium of oil majors, comprised of BP, ConocoPhillips, and Exxon Mobil, are nursing their own plans to bring North Slope gas to the lower-48 states. But MidAmerican's abortive attempt exemplifies the on-again, off-again saga that has been played out around the project for the last three decades.
Despite its enormous gas resource, the North Slope thus far has been too remote to develop economically. Oil rigs in Prudhoe Bay currently produce significant amounts of natural gas, but with nowhere to sell it they simply inject the gas back into vacated wells, forcing out additional crude oil.
Meanwhile, gas is becoming a scarce commodity in the lower-48 states, and a rising chorus of analysts says a crisis has already begun in U.S. gas markets. "The new market environment is not only defined by higher prices, but also by enhanced price volatility," says a July 2004 report titled . The report, co-authored by Cambridge Energy Research Associates (CERA) and Accenture, predicts that "an event as simple as an abnormally hot summer or cold winter could push prices well above recent levels, to the $6.50 to $8 per MMBtu range in the summer and above $10 per MMBtu during a particularly cold winter." ().
Unfortunately, the problem is exacerbated by the slow pace of progress to build gas infrastructure-not just pipelines like the Alaska project, but also liquefied natural gas (LNG) terminals.
Several LNG projects already have run aground on the rocky shoals of siting and permitting, and others have experienced setbacks and delays. About three dozen LNG projects are moving through the development pipeline, but progress is agonizingly slow. The difficulties are understandable: LNG terminals are complicated and difficult projects, facing the technical and permitting hurdles of a petrochemical plant, a gas-storage facility, and a seaport combined.
Furthermore, in the post-Sept. 11 world, new questions are being asked about the safety and security of LNG facilities, and no one seems to have clear answers to those questions ().
"We've seen a number of projects already move back their online dates," says Michael Zenker, CERA's senior director for North American natural gas. "It has a lot do to with siting and permitting, and also lead time to build cryogenic storage tanks. There's no evidence of acceleration, but lots of evidence of time slippage."
Permitting challenges have changed the landscape enough that no one can say today whether or how many LNG projects will prevail. "The jury is still out on how many will be built in the short term," says Steven Sparling, an associate with Sutherland, Asbill & Brennan in Washington, D.C. "The odds are strong you'll see multiple terminals in the Gulf of Mexico, but it's hard to distinguish which projects are in the lead now, except those that have the first-mover advantage."
Delays or cancellations of LNG projects add strength to a rising storm that could cascade through the economy, not just raising consumers' energy bills but also costing jobs and slowing economic growth, as industrial companies close plants or move them overseas to locations with lower gas prices.
Given such dire consequences, pressure is rising on policy-makers to take action to accelerate gas-infrastructure development. Such actions might include streamlining and clarifying the permitting process, offering subsidies and tax incentives, and lowering regulatory barriers-if only temporarily. How effective such steps might be at averting a natural-gas disaster, however, remains to be seen.
Natural gas production in North America has reached a plateau, despite aggressive well-drilling activity (). "People are asking, why [can't we] just drill our way back to $2 gas prices?" Zenker says. "It's just not possible. Already we are seeing record levels of well completions in western Canada, and onshore rig rates in the lower-48 states are at record levels. But they are not giving us real supply growth because we are seeing smaller reserves per well. These are picked-over properties."
Not all North American gas fields have been tapped out. The storied Arctic frontier, for example, holds 35 trillion cubic feet of proven reserves, and another 140 Tcf are estimated to be unproven. Yet they remain undeveloped-largely because historically low gas prices haven't justified the high capital cost.
Impatient with inaction, two Alaska state legislators launched a ballot initiative in July to tax petroleum companies for the gas reserves they leave in the ground. The move is intended to force the hand of oil and gas majors, whom Rep. Harry Crawford, D-Anchorage, accuses of "warehousing" gas supplies to maintain high gas prices. "They will never deal with it [the Alaska gas pipeline] until that sword is hanging over their heads," Croft told the .
The ballot initiative, however, might no longer be necessary. Today's rate trends might make the Alaska pipeline as economically viable as it ever will be, and at least three groups are pursuing proposals to develop it. For example, Trans- Canada Corp. is working to secure rights-of-way to bring a pipeline along the Alaska Highway, through the Yukon Territory and into Alberta.
TransCanada first mapped out the 2,000-mile route more than 20 years ago. The plan has gone through various phases of development and stagnation, and even now TransCanada seems to be pursuing it without much enthusiasm. "Once the right-of-way lease application is approved, TransCanada would be prepared to convey the lease to another corporation or partnership if appropriate commercial agreements are in place," the company stated in a June 2004 press release. (One of those agreements would be an interconnection contract with a Trans-Canada pipeline at the Yukon/Alaska border.)
Competing projects have been proposed by the aforementioned consortium of oil and gas majors, as well as Canadian pipeline operator Enbridge Inc. of Calgary. The latter proposed a pipeline along the so-called "Northern route," going under the Beaufort Sea to connect Prudhoe Bay with the planned Mackenzie Valley pipeline project.
But although Enbridge has been developing the Northern route concept for at least three years, the company terms its efforts "preliminary." Indeed the pipeline faces an uphill battle, no matter which plan prevails.
"Ultimately, this project will be developed by the parties that can bring together a wide array of public, private, and commercial interests," says Patrick D. Daniel, Enbridge president and CEO.
The most crucial interests are probably the state of Alaska and the U.S. federal government. Alaska's buy-in is vital to ensure the project gains the necessary rights-of-way and state regulatory treatment. And the U.S. federal government could bring expedited permitting, loan guarantees, and favorable tax provisions.
Specifically, in May 2004, the U.S. Senate passed a budget package that included seven-year depreciation treatment for the Alaska gas pipeline, and a conditional tax credit that would limit the pipeline owners' exposure to gas-price risk. Such incentives could be the catalyst that finally makes the Alaska pipeline viable, but they raise controversies of their own.
"It becomes an inflammatory issue in Congress, because people use numbers and words in different ways," says Hal Chappelle, a petroleum industry consultant based in Atlanta, and a member of the National Petroleum Council (NPC) gas committee. "Some people would call this a subsidy, but the producers wouldn't consider it a subsidy. Their view is that they are taking an unprecedented risk on a large civil-engineering project. They are going into uncharted economic territory to bring energy resources to American customers, and therefore it is reasonable to treat their investment in a unique way."
Not everyone agrees, however, that rate support is necessary for the project, given the shortages coming to the U.S. gas market. Even the NPC and the Interstate Natural Gas Association of America have remained carefully neutral on the issue.
"Anybody who can figure out how to get a pipeline into the North American market won't have any problem getting contracts to sell gas," says Ross Tokmakian, a partner with Accenture's North American utility practice. Nevertheless, he says, pipeline builders are largely tied to an investment model that requires long-term contracts to be in place at both ends of the pipeline before a single pipe can be laid ().
The question of price supports notwithstanding, other aspects of the project's development are getting attention at the federal level. Specifically, the resurrected Omnibus Energy Bill includes a section that expedites and streamlines federal permitting processes for the pipeline, which would travel through numerous jurisdictions and face potentially conflicting authorities. "Many jurisdictions, from native interests to any particular local taxing entity along the way, could tie up the project in various proceedings," Chappelle says. "The Energy Bill addresses that in an appropriate way, allowing the permitting to be conducted all at once, rather than in a fragmented, incremental manner."
If enacted, the legislation would be good news for proponents of the Alaska Highway route, but bad news for Enbridge. The bill includes language that effectively blocks the Northern route, prohibiting federal approvals for "any pipeline that follows a route that: (1) traverses land … beneath, or the adjacent shoreline of, the Beaufort Sea; and (2) enters Canada at any point north of 68 degrees north latitude"-the latitude of Inuvik, Northwest Territories, just south of the Northern route's proposed landfall, and near the northern anchor point for the Mackenzie Valley pipeline project.
This is significant because even as the U.S. Congress considers closing the door on Enbridge's Northern route, the Mackenzie project is proceeding steadily. The project, sponsored by a group of companies led by Calgary-based Imperial Oil Resources, is expected to connect about 6 Tcf of stranded gas in Canada's Arctic frontier through the Northwest Territories and into pipeline networks in Alberta. From there, the gas can be transported to almost any major U.S. market.
The project has obtained siting approvals along some sections of its route, and efforts are proceeding to secure additional permits and complete geotechnical engineering. In all, more than a dozen regulatory agencies are involved in permitting and granting rights-of-way for the project.
"We're optimistic to see gas coming on stream before the end of the decade. There has been a real coalescence of the interests of producers and the Northern community of interests, from aboriginal to territorial governments," says Dan McFaddyen, vice president of regulatory affairs and public policy for the Canadian Energy Pipeline Association in Calgary. "They want to see this project happen. Now it's just a matter of getting through the regulatory processes."
The Mackenzie pipeline's 1.5 Bcf/day of capacity, however, would meet less than 15 percent of the shortfall that is expected in U.S. gas markets, and its arrival around 2010 will be too late to relieve growing price pressures in the interim. Thus other alternatives are needed-with or without Arctic gas.
Desperately Seeking Supply
An alternative supply source that was expected to address needs on the Eastern Seaboard is found in the Canadian Maritime provinces. The Maritimes & Northeast Pipeline is now delivering gas from the Sable Island gas field to markets in Canada and the Northeastern United States. The Maritime resources, however, have failed to live up to expectations.
"The Maritimes proved to be disappointing," says CERA's Zenker. "A number of expensive dry holes were drilled. Production from that area is projected to be much smaller than was expected just a few years ago." Geology in the region is more complex than originally believed, Zenker explains, requiring more wells to be drilled at a higher cost. The end result is that the region is now expected to produce about 0.6 Bcf/day, compared with earlier projections of 3 Bcf/day.
Additional gas reserves in the Hibernia field, offshore of Newfoundland, hold potential for future development, but transportation again becomes a problem, requiring the construction of either a new pipeline or an LNG liquefaction plant. Neither solution seems likely to develop before 2012 at the earliest.
Other prospects for North American natural gas supplies involve coalbed methane, mostly in Alberta and British Columbia. A partnership of EnCana Corp., based in Calgary, and MGV Energy Inc., a subsidiary of Houston-based Quicksilver Resources Corp., has completed testing of shallow wells in Alberta and has begun drilling production wells. "It appears that we have defined a large fairway of commercial productive coals," says Glenn Darden, Quicksilver's president and CEO. "The lack of water in these coals makes the economics of this project compelling."
Quicksilver estimates its coalbed methane reserves total about 131 Bcf. Although Canada's total coalbed methane reserves could be huge, the amount of commercially recoverable gas remains uncertain.
More certain resources can be found in the United States, in the Rocky Mountains, and the Deepwater Gulf of Mexico. The Rockies in particular have emerged as the United States' largest gas fields. "The supply picture is robust in the Rockies," says Kirk Morgan, vice president of marketing and regulatory affairs for Kern River Pipeline Co., MidAmerican Energy's pipeline arm. Kern River completed a pipeline expansion in 2003 to bring its total pipeline capacity to 1.7 Bcf/day, and other operators are adding more capacity.
The National Petroleum Council estimates the U.S. Rocky Mountains have 125 Tcf of proven reserves. The problem, however, is that about 69 Tcf of these reserves are inaccessible because they are found under environmentally sensitive land. Thus the lion's share of new Rocky Mountain gas won't be available for U.S. markets unless lawmakers lift environmental restrictions on drilling and production-not a likely prospect for the near term.
"If anything, the pendulum is swinging against implementation of these initiatives right now," Zenker says. "Land access was debated during the formation of the Energy Bill that stalled in Congress, and the issue proved to be intractable."
As gas prices rise, however, policy-makers might become more amenable to easing environmental restrictions in the Rockies. Some improvements might be found in streamlined permitting processes for areas that are already open to gas drilling. For the time being, however, Rocky Mountain gas will remain a limited answer to the gas-supply problem.
Mind the Gap
Gas markets are sending the right signals to both gas developers and customers. But gas supplies are simply too far away-in both distance and time-for developers to fill the gap between supply and demand. Furthermore, no single solution will be adequate by itself.
"Pipelines can't even hope to fill the growing need and offset the domestic sources," says Tokmakian of Accenture. "The Mackenzie Delta will come in, but it won't solve the problem. Neither will Alaska. North American gas supplies face a sustained-decline model, period."
That means North America must begin importing more gas from overseas via LNG terminals. This fact is not lost on the Federal Energy Regulatory Commission (FERC), which has made progress to improve processes for permitting LNG terminals. Specifically, the commission is working to clarify its baseline science models, and to coordinate and centralize project reviews and approvals. "FERC has been careful lately to consider input from other regulatory bodies," says Katherine Yarbrough, a partner with Sutherland, Asbill & Brennan LLP in Washington, D.C. "But someone has to make the final decision, and that obligation is entrusted to FERC for onshore and offshore facilities."
Even so, LNG development must proceed quickly to relieve gas-price pressures. "Given the long lead times involved in frontier gas and LNG projects, it will be several years before rising prices get a supply response," Zenker says. "We need a few more LNG projects to go under construction this year in order for the 2009 online date to be met. That's the signpost we are looking for."
If and when LNG terminals are built, the North American gas market will undergo a transformation. "Eventually gas will become more like oil is today, where we are dependent on international markets for imports," Tokmakian says.
While such energy dependence may bring undesired geopolitical consequences, it also opens up the United States gas market to much deeper global gas reserves, which means a wider array of energy supply options and greater price stability in the long run.
"Getting from here to there is the challenge that everyone has to deal with," Tokmakian says.
Before the next generation of LNG terminals begins receiving fuel from abroad, the North American gas market is almost certain to go through a difficult period. The main questions now involve how long this period will be, and how to get through it as painlessly as possible.
The Trouble With LNG Contracts
Gas pipeline and LNG terminal projects both face a dilemma. Namely, gas purchasers are reluctant to enter long-term fuel-purchase agreements, especially from a facility that won't exist for several years. But at the same time, developers have a hard time securing financing for those facilities without having such contracts in place.
This dilemma is one of the barriers keeping big gas-infrastructure projects like the Alaska gas pipeline from being built.
"The biggest concern on the part of North Slope producers is the risk involved in the capital requirements for the pipeline," says Don Santa, president of the Interstate Natural Gas Association of America (INGAA). "What will make them comfortable is that the risk has been sufficiently mitigated, whether that's with the price floor that they'd like to see, or potentially a risk-sharing arrangement with others who may come in to develop the pipeline."
Second-Guessing by PUCs
Such a risk-sharing arrangement could entail equity investments in the project, or long-term contracts with gas purchasers, such as local distribution companies and generating utilities. The problem, however, is that utility ratemaking authorities are skittish about long-term gas contracts, and understandably so. The last time natural gas experienced a price run-up, in the 1980s, many utilities signed take-or-pay agreements to cover their exposure to rising prices. When gas prices came back down, those agreements didn't look like such a good deal anymore, and ratepayers got stuck with higher-than-market rates.
"If you're a utility buyer in a state where the regulators are telling you that you can't pass through the costs of a long-term contract into rate base, you're not going to sign a contract," says Allan Marks, a partner with the global project finance department of Milbank, Tweed, Hadley & McCloy LLP in Los Angeles. "But if you are in a jurisdiction where you have more latitude, then you will take the risk."
Indeed, some utility rate-making authorities are warming up to the idea of long-term gas contracts, whether with pipelines or LNG terminals.
"We've seen a change of heart by many commissions," says Kirk Morgan, vice president of marketing and regulatory affairs for Kern River Pipeline Co., MidAmerican Energy's pipeline arm. "Contracts can be out of the money for a period of time, and state PUCs second-guess their utilities with regard to contract positions. But we are seeing a change from short-term to longer-term thinking, to prevent what happened to us with supply imbalances and price spikes."
Examples, Morgan says, include the California PUC, which has adopted policies wherein utilities can get pre-approval of long-term capacity agreements so they won't be second-guessed in future rate cases. Another example is the Arizona Corporation Commission (ACC), which last year issued a policy statement saying that it would consider pre-approving gas contracts for Arizona utilities. The commission did just that in late June, when it granted pre-approval of costs related to a block of the $1 billion Silver Canyon pipeline that Southwest Gas plans to acquire from Kinder Morgan Energy Partners, if the pipeline is built.
"Pre-approval of these expenses is a new policy for the commission," says Mike Gleason, ACC commissioner. "This policy is necessary to encourage critically needed additional pipeline capacity to meet our growing natural gas needs."
Other commissions are considering the issue in policy discussions, and further action is expected later this year. "We need some technical guidance on this, and we are hoping to work on it with the DOE [Department of Energy] and NRRI [the U.S. Department of Energy and the National Regulatory Research Institute]," says W. Robert Keating, a commissioner with the Massachusetts Department of Telecommunications & Energy, and former chairman of the gas committee for the National Association of Regulatory Utility Commissioners (NARUC). "There are pros and cons with regard to long-term contracting that we need to study. I'm hopeful that we'll have a recommendation for the NARUC November annual meeting."
NARUC's guidance will be helpful. However, pipeline companies and LNG terminals might not be able to bank on such agreements the way they once could have. "The question for sellers becomes, how creditworthy is the utility?" Marks says. "Just because the utility has permission to put a contract into rate base doesn't mean the utility is creditworthy."
LNG Science: A Moving Target
In the frantic aftermath of the Sept. 11 attacks, the U.S. Coast Guard stopped all shipments of liquefied natural gas (LNG) into Boston Harbor. To reach the Everett LNG terminal, tankers had to cruise past downtown Boston, and officials weren't sure what would happen if terrorists were to attack a tanker, as they did the U.S.S. Cole in October 2000.
The Quest Study
To assist the Coast Guard and other agencies in assessing LNG risks in Boston Harbor, a Department of Energy official asked Quest Consultants of Norman, Okla., to provide a "quick analysis," according to a Department of Energy (DOE) memo. Quest prepared a report over a two-day period and provided it to DOE. Subsequently the Coast Guard re-opened Boston Harbor to LNG traffic and established new security protocols for ensuring the safety of LNG shipments.
That might have been the end of the story, except for the fact that citations to Quest's report soon began appearing in regulatory documents at the Federal Energy Regulatory Commission (FERC) and in application materials submitted by LNG project developers. These citations began raising concerns, in part because the Quest report suggested that the impact of an LNG release would be much smaller than earlier studies had indicated it would, and because the Quest report was being applied to projects other than the Everett terminal, for which it was specifically drafted. The report's principal author at Quest, in fact, charged that it was being "misused" for purposes beyond its intent.
The government's first reaction to these charges was to defend the report. In response to charges that the report's science conflicted with other, peer-reviewed studies, Mark Maddox, a DOE aide, told the Wall Street Journal, "The Quest model is a little bit more sophisticated than some of the other models." But after scientists raised more objections, DOE sought to distance itself from the Quest report. The DOE official who commissioned the report left the agency, and in what Rep. Edward Markey, D-Mass., called "a rather bizarre and Orwellian rewriting of history," DOE spokespeople said the department was "not involved" with the Quest study-statements later attributed to a misunderstanding.
The Sandia Study
Amid a climate of growing concern, DOE and FERC both launched new studies that would be used to build a more adequate science model for considering a variety of LNG projects and scenarios. In December 2003, DOE ordered its Sandia National Laboratories to review three previous studies on LNG hazards, including the Quest report. Later, in January, DOE reportedly expanded the scope of the study to include other, more critical studies, including one that Lloyd's Register of Shipping prepared for Tractebel (owner of the Everett terminal) in late 2001.
The current status of the Sandia study is unclear, and whether it will be subjected to scientific review is doubtful. Sandia officials declined to comment, but other sources tell the Fortnightly that DOE plans to share only certain insights from the Sandia study, citing security sensitivities.
The ABSG Model
In February 2004, FERC commissioned its own study, by the American Bureau of Shipping Consulting Group (ABSG), to review the current science on LNG spill hazards, and to assemble science models for application to LNG project proposals. The report was to be prepared quickly, with the first draft due in mid-March and the final by the end of March. FERC released the ABSG study in May and allowed two weeks for public comment, but the study was not subjected to formal peer review.
Even before the public review period was over, FERC began applying the results of the study, citing it in the final environmental impact statement for the Freeport LNG project. But upon considering the input it had received on the ABSG study, FERC issued a response that effectively made corrections and adjusted some of the assumptions and calculations.
In its response to comments on the ABSG study, FERC indicates that the ABSG models will serve as the commission's baseline technical model for evaluating LNG projects. However, the commission also notes that it will use other literature in its proceedings. It specifically points out that the ABSG study was intended to consider only the consequences of an LNG spill, not the risks of such a spill actually occurring. Thus the commission intends to apply other studies in its analysis of LNG hazard risks, and more broadly, it will adjust its science models as new understanding emerges.
Thus LNG developers can proceed with their project filings with a clearer knowledge of the science FERC will use to evaluate LNG spill hazards. The final chapter in the saga, however, has not been written. Public comments on the ABSG study note that the study does not address some big questions regarding the safety of LNG tankers and terminals-such as, what would happen if a U.S.S. Cole-style attack were carried out against an LNG tanker?
The non-peer-reviewed nature of the ABSG and Sandia studies leaves them open to skepticism, particularly in the context of recent misadventures over the Quest study. Irrespective of the quality of the science contained in the ABSG study, which most analysts seem to agree is fairly sound, the way officials have handled the process raises credibility questions that could come back to haunt LNG project sponsors.
Opponents of LNG terminals will attack the industry and its regulators no matter what they do. But by conducting permitting proceedings in a transparent manner, within a framework based on peer-reviewed science, projects might stand on firmer ground to withstand those attacks. Such approaches will take more time and raise more questions in the short term, but in the long term LNG developers would be better positioned to avoid the kinds of controversy that can bring a project-and an industry-to a screeching halt.-M.T.B.
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