When it comes to the netback price Rocky Mountain producers receive for their gas at the wellhead, there is good news and bad news. The good news is that forward markets anticipate fairly narrow gas-price differentials after much-needed pipeline capacity comes on stream in 2008. Canadian gas imports are expected to continue to decline as well, further reducing gas-on-gas competition and price disparity.

The bad news is that Rocky Mountain producers face dismal price differentials right now. At press time, the spot price at the Opal, Wyoming, hub was $3.84 per MMBtu or $2.60 less than the Henry Hub price. Three weeks earlier, the differential was as wide as $4.10, according to Bentek Energy LLC in Denver.

So, Rockies producers are playing the waiting game. They are forced to accept less than optimal prices for their gas production while elsewhere prices soar, until new transportation capacity, particularly the Rockies Express Pipeline, comes on line early next year. Rex has already finalized long-term, firm transportation contracts with a number of shippers for virtually all of the 1.8 billion cubic feet per day of new capacity.





The perennial tug-of-war between rising production and pipeline constraints will occur again, because the region has so much potential to produce more gas. How much gas? Estimates vary by consultant and government agency. But according to Scotia Waterous' most recent U.S. Quarterly Market Review, the Rockies contain 31% of the remaining onshore U.S. gas resource potential (185 trillion cubic feet equivalent) and 22% of the proved reserves (64 trillion cubic feet equivalent).

The region boasts unconventional tight gas, multiple stacked plays, coalbed methane basins and long-life reserves (defined as greater than 16 years) that support repeatable drilling campaigns. New technology in seismic, directional drilling and multi-stage fracture stimulations also will contribute to substantial production growth in the future.

According to New York consulting firm PIRA Energy Group, between 1999 and 2005, Rocky Mountain dry gas output rose almost 75% due to rising production from the Powder River, Raton, Piceance and Green River basins.

"We are victims of our own success," says Marc Smith, executive director of the Independent Petroleum Association of Mountain States (IPAMS), an association representing more than 400 independent producers, service, supply and financial companies in the Intermountain West.

"There has been tremendous growth in Rockies gas production over the past decade while other regions were declining. Today we are near or at pipeline takeaway capacity. Everyone is very focused right now on trying to keep pipeline capacity ahead of production to reduce price volatility in the markets."

There is no question that unconventional gas resources will be an increasing portion of the North American gas supply portfolio, and that includes production from the Rockies, according to Walter (Skip) Simmons, Houston-based principal of consulting firm Wood Mackenzie, who is deeply involved in North American gas research.

Exploiting these resources requires unique technology, so development costs are generally higher. That's all the more reason why a supportive Henry Hub price path and reasonable price differentials, relative to Henry Hub, are essential if operators are to develop these western supply regions.









Price differentials

From a gas-price perspective, Simmons says, 2007 will be another difficult year for producers in the Rockies. However, new takeaway capacity, along with new gas processing capabilities and associated NGL (natural gas liquids) export pipelines, will soon provide some relief.

Regional price improvement may last until 2010, at which time additional pipeline takeaway capacity to and from Cheyenne, Wyoming, will probably be required. Expanding Rex to 2.5 billion cubic feet per day is feasible and is the optimum choice. Cheyenne Plains also has expansion capability, he says.

Meanwhile, regional spot prices continue to lag behind those at Henry Hub, where the Nymex prices settle. Until new takeaway capacity comes online, gas will continue to hit bottlenecks such as the Cheyenne and Opal hubs. Additionally, any unforeseen local outages will have a huge impact as there just aren't enough alternatives to existing pipeline infrastructure to get the gas to market.

Case in point? Two maintenance outages occurred in the same week in June, on the Trailblazer and Northwest pipelines. As both were temporarily taken out of service, a major basis (price differential) blowout occurred. The negative differential at Opal, Wyoming, soared to $6.71 per thousand cubic feet and Cheyenne's negative differential was a painful $7.72.

"Had those planned outages been scheduled for different weeks, there wouldn't have been such a large basis differential. Producers and FERC should take a look at that in the future," says IPAMS' Smith.

In the near future, regional gas producers' waiting game could be rewarded. "Producers have recently seen some netback recovery, such as the recent bounce at the Opal Hub when the gas price rose by $1.36 to reach $3.86 per million Btu and Cheyenne gained $1.26 to reach $3.29 per million Btu in June," says Smith.

The markets predict higher Rockies gas prices starting in April 2008, according to Terry Ciliske, a principal at Envantage Inc., a consulting firm based in Cleveland, Ohio. "You can see that the forward markets are anticipating the price impact of the pipeline capacity available early next year," says Ciliske, referring to Envantage's Natural Gas Pipeline Infrastructure Outlook.







"The Rockies' gas differential will narrow from about $3.25 this December to about $1.25 next April, and should be fairly stable until about 2011. Again, in 2009, the price is up due to further eastern pipeline expansion. Even though gas prices are low, they are higher than they were four or five years ago," he says. "Producers are drilling in anticipation of new capacity on the pipelines."

Another trend that may benefit Rockies producers is the beginning of an expected decline of Canadian gas imports in the near future, says Ciliske. Reduced Canadian gas well completions in the past six months are one factor. But because Alberta oil-sands production uses large quantities of gas, and more large-scale oil-sands developments are expected, exports to the U.S. are expected to further decline.

Existing oil-sands operations use about 9.3 billion cubic meters of gas per year, he says. That amount is expected to more than double to about 20.6 billion cubic meters per year by 2010.

A number of Canadian shippers have let their contracts on TransCanada PipeLine Co. expire, anticipating that capacity won't be needed because the gas will stay in Alberta. Ciliske notes that TransCanada may convert a portion of its gas pipeline to syncrude service, causing Canadian gas exports to further decline.

Exports to California are already falling, even though new gas-fired power plants are being built near Kern River Pipeline, according to Ciliske. Both of these events affect Rocky Mountain gas demand. As each Kern River power plant is built, less swing gas is available to back-fill lost Canadian volumes going to California.

U.S. gas storage may be a problem too, putting downward pressure on spot prices in the near term. According to A.G. Edwards & Sons Inc. at press time, gas in storage totaled about 2.52 trillion cubic feet, or 17% above the five-year average.



Pipeline expansions

As Rockies gas production rises, it exceeds pipeline capacity to move it to market, and producers are always caught in the middle.

"The price differential has widened significantly over the past couple of years as supply grows faster than increases in pipeline takeaway capacity," says Ciliske. "We're facing the same situation as before the Kern River Pipeline expansion."

The Kern River Pipeline, which runs from southwest Wyoming to Las Vegas and southern California, was expanded in 2003. Before the expansion, the Cheyenne Hub differential to Henry Hub was $2 per MMBtu.

"About 60 days after the pipeline came online, the differential collapsed to about $0.60. But since the expansion, there hasn't been any substantial new pipeline capacity built, and gas is once again bottlenecked in Cheyenne," says Ciliske.

New gas flows are normally extracted first from areas that earn the greatest netbacks, once all relevant costs of getting the gas to market have been taken into account. Sometimes the simple fact that pipelines are inherently discrete, linking gas resources with specific markets, can become a roadblock to investment. Unless there is ready access to a hub to reduce the sensitivity to the consequences of any one link in the network going off-line, it's difficult to ensure least-cost flows and higher netbacks.









As these potential supply resources are developed, producers are anchoring major regional pipeline construction from these western supply areas to points east, an undertaking essential for price support. A recent Wood Mackenzie study shows that overall market-access pipeline projects on the drawing board total more than $8 billion, but they should provide approximately 8 billion cubic feet per day of new takeaway capacity from the Rockies.

Of particular note is the much-anticipated Rex. The $4-billion, 1,678-mile pipeline, one of the largest U.S. gas pipeline projects in decades, will connect Rocky Mountain gas to attractive markets in the Midwest and East. The line runs from Rio Blanco County, Colorado, to Monroe County, Ohio. Rex is a joint development of Kinder Morgan Energy Partners LP, Sempra Pipelines & Storage, and ConocoPhillips.

The second phase to be built, Rex West, to Audrain County, Missouri, is expected to be in service by year-end. The third segment, Rex East, from Audrain County to Monroe County, Ohio, will be in service in 2009.

"This new west-to-east pipeline is one of several that will create a needed basis bridge to narrow and somewhat stabilize price-basis differentials to Henry Hub for most western U.S. markets and supply points," says Wood Mackenzie's Simmons.

"Some negative basis price volatility may remain in certain regions, particularly in the summer months, but in the longer term, the completed pipelines do provide a reasonably stable platform that will support ongoing western resource development."

Other Rockies pipeline expansions are due as well that will help producers narrow the price differential and improve their netbacks. In 2006, TransColorado Gas Transmission Co. installed capability to reverse directional flow on its system, providing gas producers operating in the developing Unita/Piceance basins of eastern Utah and western Colorado the opportunity to transport their gas eastward to the Cheyenne Hub in Colorado and from there to Midwest markets.

TransColorado plans to expand its northern flow capacity in 2008, giving producers greater access to Midwest markets in addition to their traditional Western regional market.



Wyoming state involvement

Producers and investors are not the only groups to gain if Rockies gas transportation problems are solved sooner rather than later. The states themselves have much to gain, in the form of higher tax revenues from additional gas output.

Says Brian Jeffries, director of the Wyoming Pipeline Authority, a state entity in Casper: "As the revenue interests of the state of Wyoming are tied to the prices received for natural gas, it is in the interest of the state to encourage producers to enter into agreements for pipeline capacity more promptly than the producers otherwise would."

If so encouraged, the time during which heavily discounted prices prevail could be shortened and the state's revenues improved. Although some pipeline expansions have periodically relieved price pressure, increased production has once again overwhelmed the pipeline grid, he says.

"Severance taxes, ad valorem taxes and the value of state and federal royalty interests are impacted when the Rocky Mountain region reflects a discount to national gas prices," Jeffries says. "It is in the interest of the state of Wyoming that new pipeline capacity be built quickly to alleviate these periodic discounts and minimize the interval when significant discounts apply."

Even without government support, gas markets eventually encourage capacity additions, but some of the financial benefits can be lost due to lengthy decision-making. Pipeline expansions take between 18 and 36 months following execution of binding agreements with shippers willing to pay for the expansions.

Typical 10- to 15-year contracts require that the shippers pay fixed monthly fees, or demand fees, as part of the tariff to the pipeline company regardless of the actual use of capacity by the shippers, he explains. Generally, expansions do not move forward until 90% or more of the proposed costs have been covered by these fixed obligation contracts, he says.

Such long-term obligations pose significant risk to producers and shippers. If there is a delay in production, a shipper must still pay for pipeline capacity for which there is no immediate need. There are opportunities to resell this capacity, but there is no guarantee the shipper will recover the full outlay.

No wonder many shippers wait until the certainty of production improves. By the time they are sufficiently convinced that the expansions are in their individual interest, production in the Rockies has already grown, the gas grid has begun to fill, and unfavorable price differentials occur until the pipeline expansion is complete.

Rex, when completed, will narrow regional gas-price differentials and improve producers' netbacks for a few years, until that pipeline, too, is full to the brim.







LNG'S IMPACT

Imports of liquefied natural gas may eventually exert negative price pressure on Rocky Mountain gas prices. Most analysts agree that LNG will become an increasingly important part of total North American supply, therefore the question isn't if, but when and how often. The projected forward price path at Henry Hub supports LNG imports, and LNG will compete, under certain conditions, with Rocky Mountain gas.

LNG receipts during the summer when electric demand is peaking should cause minimal impact to the Rockies price, according to analysts. But there is likely to be significant impact in the spring and fall shoulder months, when overall gas demand is down, internal Rockies demand has not yet increased, and overall storage status could be bearish.

Imported LNG will be increasingly competitive with U.S. gas as the costs of liquefaction and regasification come down, although construction costs have risen in the past two years. These vary based on a number of factors, including land costs. The most expensive location is the West Coast, followed by the Northeast, the South Atlantic and the Gulf Coast region.

Total capital costs for liquefaction, shipping and regasification fell from about $494 per thousand cubic meters in 1995 to about $387 per thousand in 2000, and are projected to fall to $292 per thousand by 2010, said the 2003 World Energy Investment Outlook published by the International Energy Agency.

One near-term threat to Rockies gas prices could be from Sempra LNG's Energia Costa Azul regas terminal under construction in Baja California, Mexico.

To support gas flows into the U.S. from there, the North Baja pipeline operated by Sempra and TransCanada Corp. will reverse its gas flow and be expanded. Once reversed, the pipeline could deliver up to 2.7 billion cubic feet per day into California and Arizona, possibly as soon as 2009.

When the Baja LNG terminal is complete in 2008, it will serve certain local power plants with imported gas instead of Rockies gas. The only barrier to this scenario? Inadequate pipeline capacity to move gas from south to north within California. Presently, California gas flows from the north (via Canadian exports) to the south.

Rocky Mountain basins may lose a portion of that potential market

Comments