New oil shock ahead as $100 spike looms

Oliver Morgan and Heather Stewart
Sunday April 30, 2006
The Observer

Experts: Natural Gas Economy Losing Steam

Drivers, of course, can respond immediately to high prices by traveling less. It's harder for people to turn down their natural-gas heat. ''As soon as companies that control the resource figure out how to keep prices high, they'll do it, and I believe that's what were seeing in gas,'' says Ezra Hausman, analyst for Synapse Energy Economics in Cambridge, Mass.

Some Midwestern cities are accusing producers of doing it by collusion. In an antitrust lawsuit, they suggest that producers have reached either a secret agreement or tacit understanding to bottle up production.

''I think the increase in prices is a designed thing,'' says Charles Wheatley, a lawyer for the 18 communities from Texas to Indiana suing five leading gas producers in federal court.

They haven't found a smoking gun proving that. Yet, in Associated Press interviews, some industry executives acknowledge that, during their 1999 sessions, members of the Petroleum Council talked privately of a supply and price crunch in the near future — purportedly as a result of external factors.

Why, then, didn't they warn people? Former council leaders indicated that they wanted to keep pressure on demand. ''We needed to give comfort to our customers that gas was going to be available,'' says Joe Foster, a retired gas executive who was council chairman in 1999.

Shackouls, his successor, puts it this way: ''We were doing it to grease our own wheels.''

In the end, the council issued its reassuring report, and demand stayed strong.

On the other hand, industry leaders insist that collusion to sit on supplies cannot happen. After all, the five leading producers supply less than a fifth of domestic natural gas. So if they were to charge unjustifiable prices, smaller ones could undersell them, right?

Maybe not, if producers are more unified than they seem. Many small producers own rights, not rigs. They take a back seat to bigger companies that actually do the drilling under joint ventures, shared leases and royalty agreements.

Former federal energy regulator John Wilson estimates that the five producers named in the antitrust lawsuit can influence most domestic output through such arrangements, without changing their official production figures.

''Prices have stayed up because people in control of supply decided they could keep them up,'' says Wilson, who has supported the lawsuit with his analysis.

''That's not how we operate,'' answers Bob Davis, a spokesman for lead defendant Exxon Mobil Corp. ''This concept … is simply ridiculous.''

And ridiculous it would have been a generation ago, when government regulators set prices across the whole marketplace.

Since the 1990s, the marketplace itself has increasingly set producer and pipeline prices under pressure from new hordes of traders, many betting on the future prices of natural gas. In theory, traders would enable better deals through the magic wand of competition. And the theory seemed sound in the first years of market pricing, when supplies were robust.

During the production-pricing bind, though, something else appears to have happened. Conditioned by an irrepressible string of price increases, futures traders — who contract for future gas deliveries at fixed prices — tend to settle at even higher fixed prices, many analysts believe. Since the market uses these fixed prices as a reference point for its day-to-day prices, overestimates by traders can turn into self-fullfilling prophesies.

''One thing that's out there that I think is a bit of a negative is: Traders love volatility,'' says Reliant Energy's Langdon, who once worked for a predecessor to disgraced energy trader Enron.

Middleman traders — also children of deregulation — now sell much of the gas, taking their cut without producing or transporting it. They were supposed to bring better deals to buyers, but not everyone's so sure they do — even setting aside outright market manipulations blamed on traders like Enron in recent years.

''I sometimes wonder if these are the prices that would really be arrived at, if the user of the gas was dealing with the producer of the gas,'' muses Foster, the former Petroleum Council chairman.

Others harbor deeper doubts. Is real competition possible, they wonder, for a product that buyers absolutely need? They're not like shoppers, after all, who can simply shift to a cheaper product on the store shelf — maybe apples instead of peaches.

''I think it is very difficult, if not impossible, to foster truly competitive markets when you're dealing with energy,'' says Tyson Slocum, a consumer advocate at Public Citizen.

At six-years-and-counting, you might think supply has to expand to meet demand before long. Yet there's little sign of it yet. The industry's supply group warns of more upward pull on prices.

Even the administration of President Bush, a former oilman, hasn't come close to opening enough federal land to drilling and stripping away enough bureaucracy from permits, the industry complains. ''Our natural gas supply problems are man-made by legislation and red tape,'' groused chairman Larry Nichols of producer Devon Energy in March.

Optimists point to projections of multiplying imports of frozen liquid gas, which is warmed back to its original state in this country. However, those predictions may also veer off target.

Terminals to liquefy and regasify don't come cheaply, and investors shy away without assurance of safe supplies well into the future. Terminals typically run into a tsunami of domestic opposition, with the huge tankers and storage tanks feared as targets for attack.

''We're much more in the public eye because of the ships, because of the concern about terrorism,'' says Frank Katulak, president of the Distrigas liquid gas operation outside Boston, which wants to build a new terminal offshore.

Even with more terminals, a global supply means a world market. The United States already competes for such gas with fuel-starved Europe and will increasingly confront demand from the hulking economy of China.

More buyers means more demand, which means higher prices. By then, these could seem like the good old days.

EDITOR'S NOTE — Jeff Donn often covers energy as the AP's Northeast regional writer, based in Boston.

Shell: Mars repairs ahead of schedule

The Gulf of Mexico’s largest producing oil platform knocked off-line by Hurricane Katrina could be running again in May, just before the start of this year’s hurricane season.

Shell Exploration & Production Co., a unit of Britain’s Royal Dutch Shell PLC, said April 20 repairs to its Mars platform will be finished in April, with partial production restored in late May. Hurricane season starts June 1.

The platform represents about 5 percent of the Gulf’s daily oil and gas production, which before the hurricane stood at 140,000 barrels of oil and 150 million cubic feet of gas a day.

Originally, Shell did not expect the platform to be producing until late 2006.

Marvin Odum, the company’s head of exploration and production for North and South America, said two factors put Shell ahead of schedule: immediate and accurate damage assessment and purchasing the right pipeline repair equipment before the hurricane hit in late August.

The quick assessment enabled Shell to lease one of just two barges available worldwide capable of moving a toppled rig structure to shore.

Below the surface, Shell was already working to remotely repair pipelines at depths reaching 2,700 feet with equipment it purchased when production began 10 years ago.

“Getting that barge and having everything else in stock, then being able to put them to use right away saved us many months of time,” Odum said.

Crew of 500 lived on ship

Additionally, Odum said assembling a work force that lived for weeks at a time on an adjacent ship was crucial. The crew of 500 included engineers, geologists and technicians.

With oil prices above $70 a barrel, companies like Shell have every incentive to resume production as soon as possible.

“We expended every resource to get it done,” Odum said. “I generally don’t think people understand to what lengths we went to return all this production as quickly as possible.”

The company said its Katrina-related damages in the Gulf range between $250 million and $300 million.

Odum said Shell’s estimates placed the Mars platform in the hurricane’s eye for about four hours, absorbing 80-foot waves and wind gusts reaching 200 mph. The platform’s oil derrick blew away, and pipelines and the rig that repairs wells were damaged. But Odum said it could have been worse.

“The structure itself — the platform, the tendons, connections to Gulf — sustained no damage, so the platform did what it was designed to do,” he said. “There were no problems with the wells, not a drop of oil spilled and no gas was released, so that was encouraging to us.”

On April 19, the U.S. Minerals Management Service reported 87 production platforms still out of commission following hurricanes Katrina and Rita.

The Mars platform is located about 130 miles southeast of New Orleans. Shell operates the platform and has a 71.5 percent working interest. BP has the remaining working interest.

—Associated Press

Agrium to decide on coal project in July

Company is close to finishing first phase of feasibility study that’s likely to decide the fate of huge Nikiski fertilizer plant

Allen Baker

For Petroleum News

This coming summer will provide a crucial “litmus test” on whether Agrium Inc. and other potential investors pony up well north of a billion dollars to convert coal into feedstock for the Canadian company’s giant Alaska fertilizer plant.

That’s what Bill Boycott, general manager of Agrium Kenai nitrogen operations, told Alaska legislators April 19.

“If the opportunity is strong enough, it will be fundable,” Boycott told a Juneau hearing of the Senate Finance Committee. “And we will have the participants and the partners to move forward. Or it won’t, and we’ll continue our search for natural gas and likely watch our business prepare to wind down on the (Kenai) peninsula.”

If the Blue Sky Project gets the financial support of Agrium and potential partners, the Nikiski facility could be doubled in size. A gas feedstock derived mostly from Beluga coal shipped across Cook Inlet will completely replace natural gas that currently feeds the fertilizer plant, perhaps as early as 2011. The complex would export around 2 million tons of fertilizer to customers around the Pacific Rim.

Otherwise, the second-largest nitrogen fertilizer plant in the U.S., with a replacement cost estimated at $1.5 billion or more, will almost certainly close down.

Twin projects

Both Agrium and Usibelli Coal Mine Inc. have been working on their parts of the puzzle, which would tap the huge Beluga coal deposit across Cook Inlet from Nikiski for something like 4 million tons of coal a year. The coal would be shipped across the inlet in 12,000-ton barges, with a backup supply from Healy shipped south to Anchorage by rail, then loaded into barges there.

Once it reached Nikiski, the coal would be pulverized and then burned in a specialized gasification plant to produce a gas rich in hydrogen and carbon dioxide, explained Boycott and Agrium spokeswoman Lisa Parker.

The hydrogen from that process would be combined with nitrogen from an air separation facility to produce anhydrous ammonia. Adding some of the carbon dioxide to the ammonia would turn it into urea, another fertilizer product.

The purity of the feed gas would immediately boost capacity by roughly 20 percent compared with natural gas, he said.

Enhanced oil recovery

But not all of the carbon dioxide from the process would be used in the fertilizer operation, so Boycott has been talking up the potential for using the gas as an injectant for Cook Inlet’s aging undersea fields.

“We would have significant incremental CO2 available to support an enhanced oil recovery operation in the Cook Inlet,” he said. What he means by significant is an estimated 7,000 tons a day, even without recovering the carbon dioxide from the power plant needed to supply electricity for the complex.

The upshot could be extracting as much as 300 million additional barrels of crude oil from Cook Inlet fields, he said.

Dwindling gas

The natural gas from the Cook Inlet region that has been turned into fertilizers in Nikiski since 1968 is running out.

Almost since Agrium purchased the plant from Unocal in 2000, it’s been touch and go to find sufficient supplies of natural gas to keep the complex in operation. The plant has been running at only half of its capacity since November due to supply issues, and Boycott says that executives “don’t see a chance of restarting (full operations) with natural gas.”

The company only has enough committed gas to keep up at current rates until October. Agrium has asked for proposals for gas supplies after that, “trying to get an extension of the commercial life” of the facility, he said. But even if suppliers turn up for this next round, the crystal ball looks cloudy at best later in the decade.

So if the plant has a future, that future is almost certainly tied up with coal.

Huge power plant

Alaska’s power grid is just about as dependent on natural gas from the Cook Inlet region as Agrium itself, and that fact provides another piece of the economic puzzle the company is putting together.

The power plant needed to supply 90 megawatts needed for the industrial processes could also export significant amounts of electricity for other consumers in the region, according to Boycott, replacing some of the system’s aging gas-fired generators.

The power plant alone will cost $600 million to $700 million. “With Alaska’s 900 megawatt grid, that’s a difficult expenditure to support,” Boycott notes. It would be a big stretch for Alaska’s electric cooperatives and the municipal utility in Anchorage.

“We believe with this project we have a foundation to establish the coal infrastructure (at Beluga), and also an immediate demand for 90 megawatts,” he said.

“We provide the foundation necessary and the economics to support a power plant that we really need in this state.”

With the limitations of the current power line to the major load in Anchorage, the Nikiski complex could export around 60 megawatts, according to Boycott, with a potential to reach 130 to 180 megawatts if an upgraded line were added to take more power to the north.

$28 million next step

Boycott said he was headed for Kansas City after the Juneau hearing to talk with engineers from Black & Veatch Corp. and Uhde GmbH about design issues. Those companies formed an alliance in 2004 to work on coal gasification using Shell’s coal gasification technology. Heat material balances will be done by Shell.

It’s all part of the $4 million being spent on the initial phase of the feasibility studies. Most of that work should be finished in the next couple of weeks.

“We will know at the completion of that work whether we should move forward,” Boycott told the lawmakers. The second phase will be a lot more expensive, at $28 million, and “what we’re saying is that we would fund phase 2 by July or we would …” He hesitated before adding; “That’s really a litmus test for us.”

“Assume the answer is yes,” he continued. “What we would like to do is create a bankable commercial deal.

“And when I say bankable, what I’m talking about is firm contracts for the supply of coal, for the offtake of the fertilizer, for the offtake of the power. And then a lump sum turnkey engineering contract with a process performance guarantee, so that we’ve really done our best to manage the risk.” The design of the engineering contract would take up an estimated $13 million of the phase two cost.

All that would create a blueprint “that we can then take to Wall Street and finance. And that’s really how we’re looking to finance it.”

Even Agrium, a power in the fertilizer industry with $4 billion in sales and $283 million in profits last year, doesn’t have the heft to do the deal alone. If the project goes ahead, the cost will be second only to the trans-Alaska oil pipeline among Alaska’s commercial projects.

Government partnering

For the phase two work, Agrium is looking for partners, and also for a bit of a lift from Uncle Sam and Uncle Sourdough.

The company has been talking with U.S. Sens. Ted Stevens and Lisa Murkowski about a federal contribution, Boycott said, and Agrium wants the state to put in a chunk as well.

“We are looking to both the federal government and state government for some level of support at that level,” he said. “We’re looking at $5 million in phase 2 funding (from the two governments.”

Beyond that, Boycott said, the company might be able to take advantage of some federal tax credits to encourage new energy technology. Some grant funds were included in the recent energy package approved by Congress and President George Bush, but those grant funds are very limited and Agrium won’t be trying to tap that source, he said.

BP sells Gulf of Mexico shelf properties

Apache buys BP’s last producing GOM continental shelf properties; $1.3B purchase second it has made from British giant

Ray Tyson

For Petroleum News

BP says it decided to sell the last of its producing properties on the Gulf of Mexico’s continental shelf because they no longer muster up to BP’s investment standards, not because of an increasing threat of hurricanes, which is said to be causing some producers to rethink their future on the shelf following last year’s devastating storms.

“Over time, they (shelf properties) have become less and less competitive for continued investment in BP’s global portfolio,” BP spokesman Ronnie Chappell told Petroleum News April 24.

E&P independent Apache, a master at squeezing new production from old fields, announced April 19 that it agreed to purchase BP’s remaining shelf properties for $1.3 billion. In 2003, Apache acquired mature BP properties in the Gulf and North Sea for the same $1.3 billion price, as well as $200 million worth of aging self assets from Shell.

The recent deal with BP includes 18 producing fields (11 of which are operated) covering 92 blocks with estimated proved reserves of 27 million barrels of liquid hydrocarbons and 185 billion cubic feet of natural gas. Apache said it identified 50 drilling locations on the properties and an additional 4 million barrels of liquids and 26 bcf of natural gas in probable and possible reserves.

Some of the fields are subject to exercise of preferential rights to purchase by other interest owners, which could take up to two months to resolve, Apache stressed.

Nonetheless, “nearly half of the reserves in the transaction are in properties in which we already own an interest, including the Grand Isle 40s/West Delta complex — one of the largest fields ever discovered in the Gulf,” said Steve Farris, Apache’s president and chief executive officer.

Apache said that from April through year-end 2006, the acquired BP assets are expected to provide average daily production of 7,100 barrels of oil, 1,500 barrels of natural gas liquids and 108 million cubic feet of natural gas, and generate $320 million in operating cash flow. Apache is currently the second largest producer on the shelf.

Despite selling all if its producing assets on the shelf, BP remains a major player in deepwater Gulf of Mexico, as well as an active participant in the relatively shallow waters of the shelf, where BP is pursuing high-risk, high reward “deep-gas” and “ultra-deep” exploration opportunities.

Apache addresses hurricane threat

Apache, whose shelf infrastructure was severely thrashed last year by hurricanes Katrina and Rita, went to great lengths in justifying its second acquisition of BP properties in the Gulf of Mexico. In addition to the standard press release, Apache issued a separate “White Paper” on the subject, and held a conference call to brief investors on the pending deal with BP.

“The exposure of oil and gas companies to the risks of operating in shallow waters of the outer continental shelf of the Gulf of Mexico has come under increasing scrutiny in the wake of … Katrina and Rita,” Apache acknowledged in its White Paper.

Apache added that because of rapid natural production declines on the shelf and hurricane-related disruptions, “conventional wisdom has suggested that the shallow Gulf is dead as a viable oil and gas province and that it’s time for current and … prudent operators to consider reducing their exposure and reallocating their assets. Some, analyzing the risk and reward of the shelf in their portfolios, already have begun to do so.”

Apache was down around 23,000 barrels of oil per day at year-end 2005 because of hurricane damage, representing a little over 30 percent of the company’s pre-storm production of 75,000 barrels per day. Apache also expected to be down around 20,000 barrels per day for the remainder of 2006.

Moreover, roughly 11,000 barrels per day of BP’s shelf production remained shut-in at the time of Apache’s latest announcement, according to BP transaction statistics compiled by Apache. In fact, more than 20 percent of all Gulf production affected by last year’s storms was expected to be shut-in going into this year’s hurricane season.

Investors like deal

Still, investors liked the latest BP-Apache deal. On April 19, the day of the announcement, Apache’s stock rose as high as $73.90 per share before closing that day at $73.73, a gain of 5.1 percent over the prior day’s close of $70.13. A week later Apache’s stock was trading at more than $73 per share.

BP’s Chappell said that the increasing threat of hurricanes in the Gulf played no role in the company’s decision to sell its shelf assets, reiterating that “we recognized it would be very difficult for these properties to successfully compete for investment dollars within BP.”

Apache publicly thanked BP for cleaning up its hurricane mess before deciding to sell the last of its producing shelf properties. “BP has won Apache’s admiration in the very responsible way they have handled their exit … and at a substantial cost, because it was the right thing to do,” Apache’s Farris said in a written statement.

Apache, in language obviously designed to usurp the hurricane threat and justify its latest shelf acquisition, said the recent deal is not only an excellent fit for BP, but for Apache as well, and that prior shelf acquisitions have resulted in big profits for the company.

Farris said that by year-end 2005, Apache had recovered its original shelf investment, paid for additional capital incurred and generated in excess of $1 billion of free cash, with proved remaining reserves from the properties of 270 million barrels of oil equivalent.

Apache: not all eggs in one basket

Over the years, Apache has drilled more than 350 wells on its $2.7 billion in acquired shelf properties and reinvested in the Gulf more than $2.3 billion of the $6.2 billion of cash flow generated from company operations, Farris said.

“The shelf provides some the best margins, highest returns and most free cash flow of any region in Apache’s worldwide portfolio,” he added. “By extending the lives of these fields, Apache is doing its small part to help meet rising global demand for oil and gas.”

However, Apache was quick to note that aside from its profitable shelf investment, the company does not put all its eggs in one basket. Apache said that after its latest deal with BP closes, the shelf would represent just 21 percent of Apache’s worldwide production, up from 18 percent pre-deal, and 15 percent of the company’s worldwide reserves, up from 14 percent pre-deal.

Apache also said that once the transaction closes, overall company debt is expected to be below 23 percent of total Apache capitalization, indeed an enviable debt-to-cap ratio for any E&P company.

Apache said it would purchase BP’s remaining producing shelf properties through the issuance of commercial paper, adding that the deal should close by the end of this year’s second quarter.

Alberta aboriginals and Shell team up

Gary Park

For Petroleum News

From a whirlwind of events in the Alberta oil sands there was a ground-breaking deal between Shell Canada and a northern Alberta aboriginal community to jointly develop leases.

The pact significantly advances plans by the Fort McKay First Nation to enter the commercial oil sands world in a way that could spell untold riches for its 500 residents.

A complex exchange of options and a possible land swap culminates a decade of talks involving 8,200 acres and a possible 500 million barrels of recoverable bitumen worth US$35 billion at today’s prices.

The Fort McKay Group of Companies, which is already a major supplier of services in the oil sands region valued at about C$100 million a year, is now planning to add a private company to the stable.

Fort McKay Chief Jim Boucher said that depending on how much of the project his community is prepared to shoulder, the company could be delivering production to Shell Canada’s nearby Athabasca project by 2012 or possibly earlier.

Those volumes would become part of Shell’s long-range objective of raising Athabasca output from 155,000 barrels per day to 500,000 bpd.

The transaction involves Shell’s Lease 90, which the company obtained rights to from the Alberta government before title was transferred to the first nation as part of a comprehensive land claim settlement with the Canadian government.

Fort McKay has the option of acquiring Lease 90 at a pre-determined price per hectare, in return for which Shell, under a lease swap arrangement, has the right to lease other adjacent Fort McKay lands.

Preliminary engineering work planned

The partners have agreed to conduct preliminary engineering work through SNC Lavalin to determine the extent of Fort McKay participation once the scope of a commercial venture has been determined.

Boucher said his community is conscious of the impact development could have on Fort McKay’s land and its traditional way of life, but the deal also gives the residents an opportunity to “participate fully and build a long-term economic vision.”

He said an anti-fur lobby in the 1980s virtually wiped out the economic viability of aboriginal communities in the region and most are still having difficulty finding alternative sources of income.

Breaking into the oil sands sector will give Fort McKay a chance to control its economic destiny, Boucher said.

He said that if there were no integration of Fort McKay leases with Shell Canada’s operation, the first nation would still have an opportunity to develop expertise that could eventually be applied to the leases.

It could also let Shell Canada take full charge of the development and pay Fort McKay royalties.

Shell Canada Chief Executive Officer Clive Mather said that although there is more work to be done, the agreement “has the potential to return real value to both Shell and Fort McKay for many years to come.”

All for one, one for all

Mackenzie explorers want gathering and main pipelines under one regulator

Gary Park

For Petroleum News

The pace of future natural gas development in the Mackenzie Delta-Beaufort Sea region may hang on whether Canada’s National Energy Board agrees in June to assume jurisdiction of both the gathering system and main line, submissions to the board have warned.

Having already missed a deadline to contract for firm capacity on the two systems, six members of the Mackenzie Explorer Group have told the federal regulator there is an “urgent need” to resolve an impasse in negotiations with Imperial Oil, the lead partner in the Mackenzie Gas Project.

In a motion filed in April, the MEG members — Anadarko Canada, BP Canada Energy, Chevron Canada, Devon Canada, EnCana and Nytis Exploration — want the National Energy Board to issue an order to establish a “single” pipeline that would fall under the board’s jurisdiction.

The MGP proposal is currently structured so that the main line would be regulated by the board, while the gathering system (a 115-mile network to deliver gas and gas liquids to Inuvik, where they would be separated for delivery to southern markets, and a 280-mile liquids pipeline to Norman Wells) would fall under the Canadian Oil and Gas Operation Act.

MEG: concerns over tariffs, access

MEG said in its filing that uncertainty surrounding the question of whether the board will regulate tolls and tariffs on the gathering system have made it “commercially impossible” for its companies to sign the contractual commitments required by Imperial.

MEG has also expressed concern about whether the terms and conditions under which Imperial is offering access to the gathering system and the prospects of expanding the gathering system under its current design are fair and reasonable.

The group said its members and “other prospective shippers” have rejected Imperial’s ultimatum, including a Feb. 15 deadline for producers to sign contracts, regardless of the consequences.

Imperial has until May 5 to respond to the MEG filing and until then is not discussing the contents of its submission.

However, Imperial has warned that the Feb. 15 deadline “reflects the latest possible date to modify the gathering system design to provide capacity of more than 1.075 (billion cubic feet per day) without compromising the proposed” 2011 project start-up date.

Devon Canada Vice President Michel Scott told Petroleum News MEG would “never rule out having a negotiated deal,” even with the dispute heading for a regulatory hearing.

But he emphasized that failure to make progress on the commercial negotiations with time running out meant that “going to the NEB was the only action we had left.”

Scott insisted MEG remains “very supportive” of MGP and views the filing of its motion “very much as business as usual.”

He said MEG is anxious not to cause any delays in the current rounds of public hearings.

Hearing scheduled June 2

The NEB has scheduled June 2 in Yellowknife to hear arguments from those who have filed submissions.

Scott said that whatever decision the regulator makes will be assessed at that time.

What the group wants is clarity on the regulatory framework to speed up future development of gas discoveries outside the three Mackenzie Delta anchor fields owned by Imperial, Shell Canada, ConocoPhillips Canada and ExxonMobil Canada, he said.

It also believes that if the Canadian government is going to put public money into the Mackenzie project “there should be benefits for the public,” Scott said.

The previous Liberal government said it was open to sharing some of the project “downside risks” by possibly accepting gas in lieu of royalties, guaranteeing gas in excess of that available from the anchor fields, offering a “profit-sensitive” royalty scheme or making federal investments in some of the project components — options that the new Conservative government is still pondering.

The current design capacity of the gathering system dedicates 830 million cubic feet per day from the anchor fields, leaving 245 million cubic feet per day for MEG members and other third-party producers. The mainline has an initial capacity of 1.4 billion cubic feet per day.

Gathering system could be bottleneck

But MEG said in its filing that Imperial appears to view the gathering system as one to serve the anchor fields, with