There is a story brewing in the natural gas markets that, thus far, has been "beyond the reach of a pen." For the first time in nearly 20 years, Rocky Mountain natural gas is competing with Canadian gas and winning-molecule versus molecule. If two to three months mark the beginning of a trend, it could mean even higher gas prices and bright economic times for producers in the Rockies. A collision of production and pipeline capacity circumstances has its roots, as always, in fluctuations in supply and pipeline capacity. Since the late 1980s, according to U.S. Energy Information Administration (EIA) data, nearly every increase in demand in the U.S. has been met by Canadian gas. Low prices in Canada-the lowest in North America from the 1980s to the late 1990s-were a catalyst for Canadian producers to push for the construction of the Alliance Pipeline. The pipeline, with capacity to carry 1.4 billion cubic feet (Bcf) of gas per day, went into service December 1, 2000, and the wellhead price in western Canada improved immediately. Since the Alliance expansion, the AECO "C," which is the largest trading point in the Western Canadian Sedimentary Basin (WCSB), has no longer been the low index on the totem pole of North American prices. At press time, the one-year forward price at the AECO "C" was approximately $0.30 higher than the Rocky Mountain's Colorado Interstate Gas (CIG) index price for the same one-year price strip. North America's lowest gas prices are found in the Rockies. And, these low prices set the stage for an "Alliance-size" expansion of California-bound Kern River Pipeline. In looking back, it is now easy to see that significant expansions in pipeline capacity would solve the Rocky Mountain producer's low-price quandary. However, even as recently as a year ago, not every Rockies producer believed higher prices were inevitable. Producers had suffered through one of the worst spring pricing seasons in 10 years, and early last summer, they were staring down the barrel of possible double-digit (less than $1 per thousand cubic feet) prices for the remainder of the summer cooling season. Kern River expansion This spring, after a volatile and turbulent 18 months, Rockies gas prices improved dramatically. In reality, the solution was only 36 to 42 inches away, albeit, 717 miles of 36- to 42-inch steel pipe, which looped an existing interstate pipeline system. On May 1, 2003, Kern River Pipeline delivered on its two-year, $1.4-billion promise to nearly double its pipeline capacity from Wyoming to California. The Rocky Mountain basis differential had been at its worst 14-year historic level during the majority of 2002. Basis differential is defined as the comparison of a wellhead regional price to another pricing point, such as the Henry Hub, which is in Louisiana and is the pricing point quoted on Nymex. Last summer, the Kern basis differential, which had averaged $0.57 per million Btu (MMBtu) during the prior 11 years, blew out to $1.75 for June to August. In the month before Kern River's expansion, the April 1, 2003, index average for Kern River was $3.26 per MMBtu, with a basis differential of $1.85, when compared with the Nymex-Henry Hub price. On May 1, 2003, the Kern index was $4.28 per MMBtu with a basis differential of $1.08. That represented a $1.02-per-MMBtu price improvement for the index and a narrowing of the basis differential by $0.77 in less than one month. Rockies producers are beneficiaries of Kern River Pipeline's foresight in promoting the 905,000-MMBtu-per-day capacity expansion. Also behind that foresight are shippers that assumed the risk, the electric generators, the marketers and producers. The shippers assumed the risk of paying for multiple years of firm transportation, despite dire predictions that the expansion would be so successful that the price difference between Wyoming and California would narrow, causing the transportation value to be "under water." Too, some of the original shippers on Kern River feared that the expansion would cause a price environment in which it could cost more to ship Wyoming gas to California than the ultimate value received in California. Today, the question foremost in the minds of the expansion shippers is whether the price difference between southwest Wyoming and California will continue to support their transportation cost on Kern River during the next 10 years. Management at Kern River fully expected to complete the project on time and was anticipating a significant improvement in the Rockies basis differential. Perhaps the only surprise was how quickly the pipeline filled. According to Kirk Morgan, Kern River vice president of marketing and regulatory affairs, "On May 1, we had a 95% load factor. We moved 1,659,000 MMBtu per day. The average load factor for the month of May was 99% or 1,720,446 MMBtu per day." Load factor is a comparison of the utilized capacity versus the design capacity for a given pipeline. "Rocky Mountain gas is still the most attractively priced gas serving California, both currently and based upon consensus forward-pricing," he says. Kern River's share of the California local distribution company (LDC) load jumped from 7% to 19% in one month. The gas volume that was ultimately delivered to those utilities (at four different delivery points into California) jumped from 368,000 MMBtu per day for an average day in April 2003 to 950,000 MMBtu per day for an average day in May 2003. Obviously, that volume increase translated to higher prices for Rocky Mountain producers. The real question: Whose gas is being displaced? The quick answer is Canadian gas. PG&E GTN Pipeline PG&E Gas Transmission Northwest (PG&E GTN) is critically aware of the importance of load-factor issues. According to Sandra McDonough, vice president of external relations, PG&E GTN's current system-wide load factor is running at 50%. The pipeline moves western Canadian production from its receipt point at Kingsgate, on the U.S.-Canadian border, south to the delivery point at the California border. PG&E GTN has a total design capacity of 2.9 Bcf of gas per day, and it moved approximately 440,000 MMBtu per day less on an average daily basis in May 2003 than it did in May 2002. McDonough gave several reasons for the diminished load factor on PG&E GTN: Storage is being refilled in Alberta; the higher-value markets along the eastern seaboard of Canada and U.S. are purchasing gas; the economy in the northwestern U.S., specifically in Washington and Oregon, has slowed; a high volume of hydroelectric power is available; and, as aluminum smelters in the northwestern U.S. close (as a result of high gas prices), large volumes of federal power are being released into the existing electrical grid system. At a conference in Florida, when Carl M. Fink, assistant general counsel of PG&E National Energy Group, was asked why PG&E GTN was only half-full, he said, "We're just seeing competition. Alliance pipeline [currently provides] better netback prices [to Canadian producers] and Kern has just expanded by 1 Bcf per day into our market area." If not for firm transportation commitments by shippers to Foothills Pipeline System, and the one-directional deliveries out of the Cochran Straddle Plant in southeast Alberta, PG&E GTN might be flowing even less gas. Foothills Pipeline is the only Canadian upstream pipeline that delivers gas into PG&E GTN at Kingsgate. The Cochran straddle plant, in southeast Alberta and currently owned by The Williams Cos. (and for sale), is the largest gas-liquids extraction plant in North America when operating at its 2.5-Bcf-per-day design capacity. The plant is currently processing approximately 1.3- to 1.4 Bcf per day. It is the only straddle plant supplying gas to Foothills Pipeline. "Straddle" relates to its location on the west leg of TransCanada Pipeline (TCPL) and the western portion of the Foothills Pipeline system. Firm shippers on Foothills Pipeline face a $0.40- to $0.45-per-MMBtu firm transport commitment to deliver gas from the Cochran plant to PG&E GTN at Kingsgate. In today's price-competitive environment, Canadian gas that is delivered to eastern markets enjoys an approximate $0.30-per-MMBtu advantage over western-bound gas. That means it's currently advantageous for shippers to continue to flow gas to PG&E GTN at Kingsgate. Clearly, the shippers on Kern River that committed to expansion capacity in advance of the completion of their electricity-generation facilities found ample market opportunities for their swing gas in California. Approximately 300,000 MMBtu per day of Kern River swing capacity is currently sold at the California border. Both Canadian and U.S. Rockies producers would perhaps place a different spin on what's happening. The Kern River expansion shippers, who were "long gas" and "short market," could be back-filling California demand that is no longer a desirable market for Canadian gas. Another interpretation: Rocky Mountain gas, in head-to-head competition, clearly beat out the Canadian delivery price via PG&E GTN. Whatever the reason, much less Canadian gas is finding its way to California markets today and a significant volume of Rockies gas has taken its place. Sequential decline Experts across Canada and the U.S. have recently registered alarm over the decline of gas production in North America. According to the May/June 2003 issue of Wells Servicing, the natural gas industry should add a new phrase to its nomenclature, "sequential decline." Sequential decline relates to consistent declines in production volumes, quarter after quarter. In mid-June, Canada's National Energy Board announced that a turning point had been reached in western Canadian natural gas supplies. "Exports, which represent about 60% of Canadian production, slipped 8% in March to 301 Bcf, compared with 328 Bcf in the same month of 2002. Shipments to the United States were off 6% in January at 312 Bcf and were down 7% in February at 291 Bcf." In addition, March Canadian gas deliveries to California fell 39% to 29.4 Bcf. To compound Canada's production-decline issues, in a proposed plan by the Alberta Energy and Utilities Board (AEUB), 900 gas wells in the Athabasca oil-sands area in northeastern Alberta will be shut in August 1, 2003. The impact of that action "is far more devastating than numbers show," according to Paramount Energy Trust president Susan Riddell Rose. "If you extrapolate where the industry was going based on the front end of the curve in 1996, you can see that we might have been around 1.5 Bcf per day. The effect of all this [regulatory intervention is the loss of] more than 1 Bcf per day." The controversial policy is being undertaken to preserve the thermal recovery of 100 billion barrels of crude from the Athabasca oil-sands area. The future Rocky Mountain gas producers have a lot to look forward to: declining Canadian gas volumes, the recent approval of the Cheyenne Plains project to move gas eastward out of Wyoming, continued developments on the Grasslands and Bison projects to carry Powder River Basin gas to eastern markets, and the expansion of the TransColorado pipeline system in western Colorado. And, Rockies gas prices and basis differential will be affected when the Kern River power-generation plants are completed. As each plant is built, less Kern River swing gas will be available to back-fill Canadian volumes in the California markets. Perhaps the most exciting event will be realized this winter when the current delicate supply-demand equilibrium between pipeline capacity and productive capacity in the Rockies is affected by local heating demand. Watch for continued closure of the Rockies basis differential and all-around higher gas prices. Through this year and the foreseeable future, the new question in the natural gas industry may well be, "Where's the gas?" John Harpole is founder and president of Mercator Energy LLC, Denver, an energy-services company.