When two natural gas packages changed hands recently, it pointed the way to a new type of buyer: the municipal utility district and the aggregator of gas for small, locally owned, not-for-profit utilities. These are not your conventional, investor-owned utilities such as National Fuel Gas, Questar Corp., KeySpan or Peoples Energy, or independent power producers like Calpine Corp., all of which have for-profit E&P subsidiaries that operate wells. In March, the Sacramento Municipal Utility District (SMUD) acquired El Paso Corp.'s working interest in the Rosa federal unit in the San Juan Basin, New Mexico. Most of the wells produce coalbed methane. SMUD is looking for more such deals, says Tom Ingwers, a former E&P executive who is SMUD's director of energy trading and wholesale contracts. In December 2002, the Municipal Gas Authority of Georgia (MGAG) bought nonoperated coalbed-methane reserves in Alabama's Black Warrior Basin from Teco Energy Inc., the Tampa utility holding company. MGAG, based in Kennesaw, Georgia, provides gas supply and marketing services for 72 small communities in Georgia, Alabama and Florida that own and operate gas distribution systems. It is looking for more deals as well, says chief financial officer Susan Reeves. Neither buyer wants to form for-profit E&P units, nor will they operate. Williams Production Co. LLC of Tulsa operates SMUD's wells. The E&P unit of Alabama utility Energen operates MGAG's wells. Instead, these buyers have "gone long" in physical supply, securing a portion of the gas supply they will need to service their customers. By owning working interests in reserves and production, they avoid the gas price volatility that makes hash of budgets. In the past 20 years, utilities periodically have entered the business of owning and operating gas reserves, but just as often, they have exited thereafter. Alas, several bought when gas prices were high and then got spooked when their E&P returns failed to match the safe, regulated returns they were used to. "Some of these companies got into trouble when they started owning reserves not just for security of supply, but as a profit center expected to generate a return on investment," says William S. Garner of Petrie Parkman & Co.'s Houston office. The firm represented SMUD. The SMUD deal Each day SMUD uses about 60 million cubic feet of gas to generate 500 megawatts of electricity from three cogeneration plants and one peaking plant. The San Juan interests it bought will supply 15- to 20 million cubic feet of gas a day, about a third of its needs. SMUD plans to build a new 500-megawatt, gas-fired plant in California which will double its gas needs by summer 2005. When SMUD retained Petrie Parkman, the latter researched in which basins it should buy reserves and identified likely sellers. "All power utilities have the same problem-where to get gas supply to turn those turbines, and at what price," says Garner. "These guys are nice partners. They don't want to operate, so a seller could sell down its interest in a well package, retain operations and continue to get an operating fee [in addition to the sales price]." Owning reserves within an integrated utility structure was in fact a successful business model in the 1960s and 1970s before deregulation. That was before utilities and pipelines spun off their gas reserves, as when Panhandle Eastern Pipeline Co. spun off what became Anadarko Petroleum. "By owning reserves, a utility obtains supply flexibility because it knows a portion of its gas is in the ground, and at a predictable cost," Garner says. The deal with SMUD evolved about a year ago when Garner met some California municipal-bond underwriters working on an unrelated deal. They suggested the concept of issuing tax-exempt bonds to finance buying gas reserves. "A light bulb went off in my head," he says. "By using tax-exempt financing, a muni should have a competitive advantage. They have a lower cost of capital compared with other buyers. Also, they have low, or perhaps even no, rate-of-return criteria. All they want is supply." This is not a volumetric production payment or forward-sale structure, where the buyer/end -user gets the right to buy gas at some predetermined price and volume in the future. Rather, the buyer is getting reserves and production now, and need only pay his fair share of lease operating and other costs, Garner explains. "California utilities are asking, 'Why should I buy all my gas under a gas-purchase contract when I may not trust the supplier and its credit, or how the indexed price was prepared? Why don't I just own my own gas and arrange the transportation?" Granted, the utility takes on reserve risk that must be accounted for when negotiating the purchase price, Garner says. But the municipal utility districts (MUDs) of the world may not think this is any riskier than relying on energy merchants or producers, both of whom have exhibited great risks lately. The MGAG deal Harrison Williams, executive vice president with Albrecht & Associates Inc., a Houston-based A&D advisory firm, calls this transaction "the perfect storm" because so many elements of an unusual deal came together, and much faster than was first proposed by the seller. "We had the perfect assets, the right setting, a highly motivated seller, and an unusual buyer," he says. The deal began in the fall of 2002. Gas storage was full; prices were inching up steadily. Utilities such as Teco were under intense pressure to improve their balance sheets and distance themselves from the likes of an Enron or an El Paso. At the same time, end-users such as Municipal Gas Authority of Georgia were also watching gas prices climb. The Black Warrior Basin properties were an attractive package: they are extremely long-life, predictable gas wells. Geographically concentrated, they produce about 38 million cubic feet a day, net. Their decline curve is essentially flat. The seller, Teco, needed to raise cash fast. Its representative who runs nonregulated activities, Roy Eustace, had worked with Albrecht on prior sales. "Roy is one of the most sophisticated oilmen we have met, even though he works for a utility. He just gets its. He knows where the value is," says Williams. Teco wanted to close the sale of the CBM properties in first-half 2003, so the properties were put on the market in October. But as the pressure on utilities grew, barely a month later, Eustace told Albrecht the deal had to close by the end of 2002, despite the looming holiday season. Simultaneously, Banc of America's Mark Shea introduced MGAG, which wanted to see the data room. Several offers came in after Thanksgiving, with MGAG's ahead of the pack, but with conditions. Could they close the deal in time? Ryder Scott Co. petroleum engineers vetted Albrecht's engineering for the buyer and came up with 199 billion cubic feet of proved producing reserves, net. The difference in present value (PV) assigned to them varied by just 3% between buyer and seller estimates. "This is an incredibly pencil-thin width in projections for properties with this long a life," says Williams. The deal closed just before Christmas 2002, as Teco required. Shea got his first muni-as-reserve-buyer deal done. "Today, the MGAG people look like geniuses as gas prices have skyrocketed," notes Williams. This is the first time MGAG has purchased working interests, and it's been a long time since it held direct royalty interests in gas reserves in the early 1990s, says MGAG's Reeves. "For many years we had been structuring prepayments, but they are no longer available in the marketplace due to the Enron debacle. We were particularly interested in these reserves because they are long-lived, so easier to manage, and strategically located." Reeves adds, "We are thrilled with this deal. We are actively looking to acquire more working or royalty interests in low-risk reserves. We like to have a reasonable portion of our gas supplies locked up in long-term contracts." Banc of America says that additional muni clients are looking to procure gas in this way. "The trend is growing," says John Norman, managing director.

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