Tens of billions of barrels of crude have been coaxed, flowed and pumped for the better part of a century from the Permian Basin, the heartland of America's oil business. The megafields sprinkled throughout the basin were workhorses for many companies, generating copious amounts of cash that were reinvested elsewhere. The West Texas basin has long relied on Big Oil to carry the flag, produce the most oil and employ the most people. But the Permian is also a high-cost area, and during the last turbulent decade assets have been gradually consolidating away from the majors to the smaller players. The region has suffered as Big Oil companies exited one by one, taking many high-paying jobs with them. Lately, that trend has accelerated. 1999 was particularly trying: Conoco and Chevron each cut more than 100 office jobs in Midland, and the merger of Exxon and Mobil caused the loss of 170 jobs. This spring, West Texas reeled again when BP Amoco announced it would eliminate nearly all of Arco's 160 Permian jobs in Midland and close the office. It plans to slash its annual spending in the basin by one-half from as much as $150 million per year in the past. "The Permian Basin is an epicenter of change," says Bill Marko, Houston-based vice president of special projects for Madison Energy Advisors. "Assets there continue to change hands." In addition to basin changes that resulted from the Exxon-Mobil merger and BP Amoco's acquisition of Arco, recent deals include Permian operator Titan Exploration's combination with Unocal's Permian business, forming Pure Resources; the BP Amoco and Shell sale of Altura Energy to Occidental Petroleum; Devon Energy's purchases of PennzEnergy and Santa Fe Snyder; and the marriage of Anadarko Petroleum and Union Pacific Resources. All told, properties making more than 675,000 barrels of oil per day abruptly have new owners. The basin as a whole produces about 2 million barrels of oil equivalent (BOE) per day, 55% oil and 45% gas. "More than a third of the total production in the basin has just moved from one owner to another," says Marko. And, more than 55% of the production of the Top 20 operators has been affected in these transactions, he says. Still, the changes are not necessarily all grim. "These massive ownership shuffles could help reawaken the basin," maintains Marko. "The Permian assets comprise a considerable portion of companies such as Occidental Petroleum and Pure Resources. These firms will emphasize the basin, and look to grow their production in the Permian. We will see more drilling and workover activity." Certainly, the service sector will also benefit. Another plus-the ownership shifts are bringing welcome liquidity to the basin, he notes. Indeed, whether it is due to a new zest among independents or just price euphoria buoying activity in all classes of companies, the rig counts in the Permian are double last year's levels. In mid-June, 135 rigs were turning to the right in Texas Railroad Commission districts 7C, 8 and 8A and in southeast New Mexico. Rigs, crews and materials are in capacious demand. In short, this is an exciting time to be an independent in West Texas. "People won't recognize the Permian Basin in a year," says Marko. Leading this change is Occidental Petroleum, now the big kid on the West Texas block. The firm recently closed on its $3.6-billion purchase of Altura Energy Ltd., the partnership involving the Permian properties of BP Amoco and Shell. Proved reserves attributed to Altura are estimated at a minimum of 850 million BOE, accompanied by between 250- and 300 million BOE of probable and possible reserves. Occidental placed the assets of Altura in Occidental Permian Ltd., a limited partnership. In addition, Oxy USA Inc. already owned and operated Permian wells, and these were added to Oxy Permian as well. Operations on the properties were combined. Oxy now holds the undisputed distinction of being the largest operator in the Permian. "The Altura properties, combined with the prior Oxy holdings, produce 163,000 BOE per day," says Pat Oenbring, Houston-based president and general manager of Oxy Permian. That's just the beginning. Oxy plans to put its own stamp on its stewardship of the former Altura assets. While Altura had emphasized CO2-enhanced recovery operations, Oxy seeks to expand production by concentrating more on conventional plays. "We're going to substantially increase the level of exploitation drilling on the former Altura properties," says Oenbring. "We'll be extending existing production trends, drilling infill wells, pursuing waterflood expansion opportunities and pursuing a variety of natural gas plays." These same strategies have been quite successful on the original Oxy properties, which complemented the purchase of Altura nicely, he notes. For 2000, Oxy plans to spend $100 million in the Permian Basin, split $70 million on the former Altura properties and $30 million on its original holdings. That should equate to about 200 wells, says Oenbring. Anticipated spending for the combined assets in 2001 will be between $150- and $200 million. "Cash flows for the basin are very strong right now, and that stimulates additional capital projects." Given those levels of spending, Oenbring predicts Oxy will be able to increase production by 3% to 4% annually during the next few years. "We're combating a 5% decline on our 160,000 barrels per day, but we're optimistic we can add production. We have plenty of opportunities," he says. Despite its spotlight on conventional production, Oxy retains a strong interest in new CO2 floods, a technology in which Altura reigned. "A key piece of the Altura acquisition was not only the properties, but the firm's expertise in CO2 flooding," says Oenbring. Oxy plans several new grassroots CO2 floods, along with expansions of existing floods. "We have more than 10 individual CO2 projects that we'll be implementing during the next five to 10 years, depending on our initial success," he says. "We intend to capitalize on the CO2 knowledge not only in the Permian Basin but also worldwide." Indeed, half of the reserves Oxy acquired from Altura lie in Wasson and Slaughter/Levelland fields, both immense, mature CO2 floods near Denver City and Lubbock, respectively. The old fields chug along, with remaining productive lives of 25 to 50 years. Managing costs in the aging fields poses an ongoing challenge, says Oenbring. "Altura was a cost leader in the basin, and its costs per barrel were significantly lower than its peers," he says. "We plan to improve on that record." Wasson and Slaughter/Levelland still offer some infill drilling and a small amount of exploitation work, and new CO2 floods started in their general vicinity will be able to capitalize on existing infrastructure. Proportionately speaking, however, more of Oxy's growth potential is in the Midland-Odessa area and to the south, Oenbring says. Oxy maintains a 60-person office in Midland, and a 150-person office in Houston. Including field personnel, Oxy Permian has 850 employees, about 85% of whom were previously with Altura. "The former Altura properties make up a substantial portion of Occidental's worldwide assets, and as long as we can continue to deliver good returns on projects, the Permian will command a sizeable percentage of our capital budget," says Oenbring. "It's an exciting time for us, and we're enthusiastic about the basin." Another independent with a substantial stake in the Permian is Dallas-based Pioneer Natural Resources Co. This company grew up in West Texas, leveraging its activity there to launch into enticing plays in places such as the deepwater Gulf of Mexico, South Africa, Gabon and Argentina. Pioneer started in the basin in 1962 through one of its predecessors, Parker & Parsley Petroleum, and has been in the basin since. The Spraberry Trend forms the backbone of Pioneer's Permian operations. The company operates almost 4,000 wells in West Texas, 95% of those producing from the Spraberry. It holds 375,000 gross acres in the trend, with deep rights on 130,000 gross acres. It has net reserves of 200 million BOE in the basin, and gross operated production of 50,000 BOE per day. The basin hosts a third of Pioneer's reserves. "We plan to continue to grow that reserve base, and we have more than 500 locations remaining in the Spraberry," says Scott Sheffield, Pioneer chairman and chief executive. This year, as for the past several, Pioneer will drill about 125 Spraberry wells and spend about $20 million in the basin. "The Permian offers us growth in reserves, but at our size now we can't grow production without making an acquisition," Sheffield says. "Our drilling program aims to keep our production levels flat, and we invest a substantial amount of the cash flow we derive from the Permian in areas that have higher growth potential." Befitting that strategy, Pioneer plays the basin with a keen eye to costs. "We have divested most of our properties with high operating costs," says Sheffield. "Even though the Permian Basin has a lot of romance, it's also one of the highest operating cost areas in the United States. In the last five to seven years, we have invested heavily in efforts to lower our operating costs." Indeed, Pioneer enjoys extremely low operating costs per barrel, says Sheffield. "We operate our Spraberry wells for $3.20 per BOE, and that figure includes $1.20 per barrel in taxes. We have automated a majority of our wells and introduced technologies, such as telemetry, which allow us to understand immediately what's happening downhole." Enhanced recovery in the Spraberry also offers staunch promise. Pioneer is involved in a pilot project with the Department of Energy, part of the DOE's Reservoir Class Field Demonstration projects. CO2 injection at the Midland County pilot will start later this year. The $13-million project is shared 60% by Pioneer and 40% by the government. "The Spraberry Trend covers a very expansive area, measuring 150 miles long by 75 miles wide," says Danny Kellum, Pioneer executive vice president, domestic operations. "We are very interested in CO2 technology, because the Spraberry had original oil-in-place estimates of 12 billion barrels. With primary recovery processes to date, we have recovered only about 8% to 10% of the oil in place. If we can capture another 5% through secondary and CO2 recovery, we're looking at some pretty tremendous numbers." For 2001, Pioneer plans to keep five rigs active in the Spraberry and devote between $20- and $30 million to the Permian. At least $5 million of that will be earmarked for projects beneath and outside of the Spraberry Trend, says Sheffield. "We have a considerable amount of acreage that could be prospective for the deeper horizons below the Spraberry," says Kevin Schepel, worldwide exploitation manager. "More than 40 anomalies have already been identified-mainly in the Wolfcamp, Strawn and Devonian-on 400 square miles of 3-D seismic." Success has also come lately on a Wolfcamp play in Irion County. The firm has drilled three 8,500-foot vertical wells in its 18,000-acre My Way project, just outside San Angelo. "We've been finding carbonate buildups with more than 200 feet of pay that can produce at initial rates in excess of 1,000 barrels per day," says Schepel. "The wells then level off around 200 barrels per day and hold steady." The company has an inventory of nine prospects in the play. Another firm with deep roots in the Permian is Midland-based Pure Resources Inc., which was formed in May by a combination of Unocal's Permian Basin business and Titan Exploration Inc. At its effective date of January 1, 2000, Pure had reserves of 1.02 trillion cubic feet equivalent (Tcfe) of gas and production of 230 million cubic feet equivalent per day, about 60% gas and 40% oil. Unocal holds about 65% of the shares of the new company. Pure, with 210 employees, now ranks as the largest publicly held Midland-based E&P company. "Where once the majors dominated, today the independents are the new power in the Permian," says chairman and chief executive officer Jack Hightower. About 80% of Pure's assets lie in the Permian Basin; the remainder are in the San Juan Basin of New Mexico and in central and South Texas. In the Permian alone, the firm holds approximately 1 million gross acres of leasehold and operates about 850 wells. "Our focus is to acquire and exploit assets, and very actively explore in the Permian Basin," says Hightower. "The basin has produced approximately 43 billion BOE, and engineering studies say it can produce another 14- to 15 billion BOE. Even though people sometimes see it as a sleepy, mature area, the Permian is one of the most important basins for the future U.S. production base." For its part, Pure intends to reinvest a significant portion of the cash generated by its Permian properties directly back into the basin. "We budgeted $117 million for 2000, and so far we've spent about $60 million. Between now and the end of the year, we're going to be very busy," Hightower says. "We have nine rigs running now." New technology is now available in the Permian Basin, specifically in the ability to drill horizontal wells in deeper formations. "Developments such as geosteering, underbalanced drilling systems and improved bits allow operators to successfully drill longer laterals, stay in zone and drill in hard rock formations," he says. Pure is particularly intrigued by the section from the Devonian down to the Ellenburger, in the deeper portion of the Delaware Basin. "We're focused on this deeper drilling, and we own a working interest in most of the major Delaware Basin gas fields." The company especially likes the emerging Montoya play. The Montoya reservoir lies below the Devonian; old vertical wells would deliver only as much as a million cubic feet of gas per day. The drilling is expensive-the formation is more than 14,000 feet deep, and the laterals are in the 3,000-foot-plus range. But today, with the technology to drill horizontal laterals and properly fracture the reservoir, wells can deliver more than 10 million cubic feet of gas per day with reserves of 15- to 20 Bcf per well, says Hightower. In a similar vein, Pure is developing a horizontal Devonian play in Pecos County's Gomez Field. Gomez has produced 5 Tcf of gas, principally from the Ellenburger formation at depths of around 22,000 feet. Pure is presently drilling a well in Gomez that will have a 3,000-foot horizontal lateral in the Devonian, says Hightower. The wells will cost about $7 million completed-drilling is very tough because the higher portion of the reservoir is 100% chert. But, the payoff could be major league, as Pure owns significant acreage in the highest structural position in the field. Another Pure project is a 600-square-mile, 3-D seismic shoot in the western Delaware Basin, in Reeves and Culbertson counties. Exxon Mobil is its partner. "We've had this project in progress for a year and a half," Hightower says. "It's the largest contiguous proprietary 3-D shoot in the U.S. Only five wells in that entire area were drilled to the Devonian formation." Pure plans two wells at its Paragon project this year, targeting the Devonian, Fusselman and Montoya reservoirs. The Permian Basin mainstays of waterfloods and enhanced recovery projects are also essential elements of the Pure portfolio, he adds. About 25% of Pure's oil production is under waterflood, and on an unrisked basis, the company estimates it has 98 million barrels of potential with secondary recovery projects. Too, CO2 projects figure strongly in its plans. Pure now operates three ongoing projects initiated by Unocal, two at Dollarhide and one at Reineke fields. "We also have a pilot project that was initiated by Titan," says Hightower. "During the next few years, we anticipate implementing up to five more projects. As the technology and the access to the technology has improved, smaller companies can now operate CO2-injection projects very effectively and economically." The potential is tantalizing: "On an unrisked basis, we have almost 92 million barrels of potential with CO2 recovery," he says. Not all the Permian assets are moving from majors downward to independents. Houston-based Apache Corp. purchased West and South Texas properties from privately held Collins & Ware Inc. recently, gaining reserves of 496 Bcfe of which a third are Permian. With the acquisition, the larger independent's gross operated Permian production rose from 21,000 to 25,000 barrels per day. The company also produces 55 million cubic feet per day of gas, and another 4,000 barrels per day of natural gas liquids. The basin is a crucial cog in the far-flung independent's portfolio: In 1999, it drilled 60 wells in the basin and spent about $35 million. This year, it expects to drill more than 100 wells, says Craig Clark, Houston-based executive vice president for Apache's U.S. operations. The company employs about 100 field people in the Permian, and maintains a seven-person office in Midland. The $320-million Collins & Ware deal provided yet another brick for Apache's Permian foundation. The company was an early participant in independents' move into the old basin: in 1991, it bought the first large package of properties that passed from a major to an independent in the Permian-MW Petroleum from Amoco. Permian properties-containing about 3,000 wells-accounted for two-thirds of the deal. Apache followed that purchase with a big buy of Permian assets from Texaco in 1995. "In the early 1990s, we saw some things in the Permian that we still see there. It's a very good place to add reserves," says Clark. "We liked the Permian's oil production, its long-lived assets and its exploitation opportunities. We saw an opportunity to add value. We believed that we could enhance the oil production via recompletions, workovers, new wells, artificial lift, and secondary and tertiary recovery operations." While the Permian Basin generally doesn't fare well when measured by financial yardsticks such as rate-of-return, the margins can be tremendous, says Clark. "We run our business not on price, but on a margin basis. And, the Permian offers very low finding costs. For us, the basin is a critical area in which to exploit assets." Apache's strategy focuses appropriate technology on its acquired properties. "We don't think that we are smarter than anyone else, but we do focus capital on these old properties. What we do ranges from running new logs in old wells, drilling with smaller rigs, drilling horizontal laterals, and in some cases, using a workover rig to drill shallow wells." The approach has paid off nicely. Apache's most active properties are Northeast Drinkard Unit in Lea County, New Mexico, and North McElroy Unit in Crane County, Texas. Under Apache's husbandry, both assets are producing at 20-year highs, Clark says. Apache traded Altura Energy for the Northeast Drinkard Field in early 1998. Since then the firm has drilled about 80 wells, tripling oil production and quadrupling gas production. "Northeast Drinkard is a very immature waterflood, by West Texas standards," says Clark. "The field has a 35% oil cut, and it's only about 15 years old. It was making around 700 barrels of oil and 4 million cubic feet of gas per day when we bought it. Today, we make 2,100 barrels of oil and 16 million cubic feet of gas per day." Northeast Drinkard, productive from the Clearfork, was drilled on 40-acre spacing, but the pattern of well placement was erratic. "We're filling in the pattern to a classic five-spot, and we're taking the spacing down in most cases to 20 acres." North McElroy, a San Andres field formerly owned by Texaco, is Apache's oldest Permian property. The field was discovered in the 1930s and drilled on five-acre spacing. "Still, we've increased production from 3,000 to 4,000 barrels per day. It's basically a giant waterflood conformance project," says Clark. "We've looked at everything from reservoir compartmentalization and missed zones to flood efficiency and injection patterns." Apache plans to take the same approach to its newly acquired Collins & Ware properties, especially two San Andres floods located near Lubbock. One of the natural progressions in the oil business occurs when large companies pull up stakes and relocate to a bigger oil hub. Inevitably, some of the employees decide to stay in the hometown and strike out on their own. That's the case with Concho Resources Inc., a Midland-based firm founded in 1997. Partners Tim Leach, David Copeland, Steve Beal and Dave Chroback came from senior management positions with Parker & Parsley Petroleum Co. "When we started, the only asset we had was a conference table," says Leach, president. Concho quickly managed to raise $82 million in equity to acquire properties. "We built Concho through about a half-dozen acquisitions." Today, the firm employs 45 people, operates in excess of 500 wells, and produces 20 million cubic feet of gas and 3,000 barrels of oil per day. Concho's 2000 budget calls for it to spend $30 million drilling 95 wells in the Permian. Currently, it is running three rigs in New Mexico and two in Texas. A good portion of its efforts center on its 100,000 net acres in southeast New Mexico. Its leases are well positioned in the Morrow pinch-out play, which extends for 75 miles across the northwest corner of the basin. Some tremendous production has been found there recently, and the area is red hot. The Morrow tests in this play average around 9,000 feet in depth, and reservoirs can contain 2- to 15 Bcf apiece. Drilling costs are in the neighborhood of $600,000 per well. "We plan to drill 20 to 30 Morrow wells this year," says Leach. The Morrow channels are identified via 3-D seismic data. "The 3-D has been instrumental in helping us define the channels in the Morrow, and reducing the number of dry holes." At its Tomcat project in Lea County, Concho is developing Delaware production. Too, the firm produces a good bit of Spraberry oil on the Texas side of the basin. Concho also operates the West Broadview Unit, a Clearfork waterflood near Lubbock that contains about 30 wells. "We can maintain our current level of drilling activity on our existing acreage for the next three years," says Leach. "We can grow our company at an acceptable rate with that drilling, and be very selective about the kinds of acquisitions we are making to complement that growth." Some of the most exciting drilling news coming out of the Permian these days is being generated by CMS Oil & Gas Co. Presently, CMS is completing the Industrial #601-H, a Midland County well boasting the longest horizontal lateral yet drilled in the Permian. The well was drilled vertically to 11,700 feet, then kicked sideways for 9,417 feet in the Devonian. The borehole snakes beneath Midland, within the city limits. The well joins eight other CMS producers, all drilled since mid-1999. At press time, the company was making 15 million cubic feet of gas and 600 barrels of condensate per day from its Devonian wells, and running two rigs in the play. CMS opened a Midland office in late 1998. "We were looking for a place where we could leverage our knowledge of tight gas sands and unconventional reservoirs," says Houston-based Bradley Fischer, president and chief executive officer. "Tight rocks and low permeability reservoirs are a strength for us, and we knew how to operate cost effectively in those kinds of reservoirs. The Permian Basin interested us because a number of our employees had worked there during their careers." General manager Luis Acevedo was selected to head a small team scouting opportunities suitable for CMS. Concurrently, Texaco, Mobil and Arco Permian were having some success in drilling tight carbonate rocks at Bryant G. and Parks fields, south of Midland. "We studied that area and decided that we could extend the play into Midland Southwest Field," says Fischer. CMS identified a productive area within the old Devonian field, discovered in the 1960s. Using horizontal drilling, it has expanded the boundaries of the field up to and underneath the Midland city limits. A typical well in the horizontal Devonian play is drilled vertically 12,000 feet, then laterally more than 6,000 feet. Initial production levels for the long horizontals are more than 5 million cubic feet of gas per day, with 100 barrels of condensate per million cubic feet of gas.. "The gas is very rich, about 1,300 Btu. Its high quality brings a premium in the market," says Acevedo. CMS can drill and complete the tests for about $1.5 million apiece. "We are continually improving on that figure. We've drilled the longest and the fastest wells in the entire basin, by a fairly significant margin." The firm initially thought it would have to make an acquisition to acquire a land base in the closely held basin. "But, our team has been very effective at straight-up leasing, and we have yet to make an acquisition," says Fischer. "All of our opportunities have been prospects we have generated in-house, then leased in the conventional manner." Remarkably, CMS amassed a 20,000-acre position in the horizontal Devonian play before it kicked into high gear. A Spraberry project in Reagan County is its second area of interest. CMS has acquired more than 20,000 acres about 60 miles south of Midland, near Big Lake. "We mined the public records and found a place where we could box in a significant amount of acreage," says Fischer. To date, CMS has drilled 20 wells in the Spraberry. "These are conventional vertical wells, but we have put a lot of effort into understanding the geology. The Spraberry is often seen as a low-risk, marginal play, and people generally try to minimize data acquisition and cost," says Acevedo. "We take a more technical approach, running openhole logs and mud logs. We've identified some of the better sands in the Spraberry, as well as uphole potential, and we've tried to invest the funds necessary to gather data and optimize our drilling and completion efforts." Fischer believes that CMS has been successful in West Texas because it put good people on the ground in Midland and gave them the time to develop ideas. "We've been very fortunate to hire first-class people from the Midland area," he says. "Also, the Permian has solid infrastructure. That allows us to get quick hook-ups and quick revenues from our wells. And, the community is very supportive of the oil industry. We've been welcomed, and we work well with the regulatory agencies and the city government." The Permian is a very promising growth area for CMS, concludes Fischer. "Overall, we have exceeded all of our expectations there." Fayetteville, Arkansas-based Southwestern Energy Co. is another relative newcomer to the basin that has racked up a string of successes. Since its entry into West Texas in late 1997, Southwestern has been involved in the discovery of numerous fields, including sizeable Morrow accumulations at its Gaucho and Logan's Draw projects in southeast New Mexico. Indeed, Southwestern is currently developing eight Morrow/Atoka discoveries in the Delaware Basin. "We like the Permian because it is a world-class petroleum province," says Al Stevens, Houston-based senior vice president. "The source rock is extremely rich, the reservoirs are abundant, and the complicated stratigraphic and structural history allows for the formation of a multitude of traps. All that adds up to opportunities." Another attraction is that the Permian has not been as heavily explored with 3-D seismic as other domestic basins, he says. "We're participating in another generation of exploration. The Permian is now an independent's play. It needs savvy companies that can take advantage of its complexity, but at the same time companies that can keep overhead low." Richard Lane, vice president of exploration, notes that most of Southwestern's activities thus far have been in the Delaware Basin portion of the Permian. The company drilled just seven wells in the basin in 1997; this year, it will drill 58. At least half of its wells target Atoka or Morrow objectives, he says. "We have a few higher-risk projects in the deeper Pre-Pennsylvanian section, and the remainder of our wells are drilled to Permian objectives." Land is the most difficult resource to obtain, he says. "Held-by-production acreage is a major challenge. Land is still the king. To be successful, a company like ourselves has to finesse its way into working some of the hundreds of square miles of major-controlled HBP acreage." From a corporate perspective, the Permian supplies the medium-risk portion of Southwestern's portfolio. The company has added 50 Bcfe of reserves since 1997, at a finding and development cost of less than 80 cents per thousand cubic feet. Strategic targeted acquisitions with upside are also a strategy, and last year, the firm spent $9.4 million to purchase properties from Petro-Quest. In the deal, Southwestern acquired 12.9 Bcfe of reserves, 8,000 net acres and additional exploration prospects. Its net production from the area is now 17 million cubic feet and 860 barrels of oil per day. "We try to keep our overhead low, our data costs down, and get ourselves into low-cost acreage positions," says Stevens. "For us, the quality of the geology is always first, but good landmen are crucial to success." Southwestern plans to spend $15 million in the basin this year, about 25% of its corporate drilling budget. "We're more budget-constrained than opportunity-constrained," says Stevens. "As we go forward in the E&P arena, the Permian Basin will be a big part of our future," comments Harold Korell, Fayetteville-based president and chief executive officer. "The basin has been good to us; our successes have each spawned additional development drilling and our activity keeps building. "The Permian is a world-class basin. Oil will still be produced there when our grandchildren are geologists." ENHANCING THE FLOW One of the more compelling moves in the Permian Basin's shift from major to independent control has been the takeover of Shell CO2 by Kinder Morgan Energy Partners LP. In April, Houston-based Kinder Morgan increased its holdings in Shell CO2 from 20% to 100%. The natural resource transportation firm paid $185.5 million for assets that included 5 trillion cubic feet of CO2 reserves, extensive pipelines and surface infrastructure. At the time of the sale, Shell CO2 was delivering 400 million cubic feet per day to its customers. About 150,000 barrels of oil production per day are attributed to CO2 enhanced recovery in the Permian Basin, the global stronghold of the technology. Some 55 CO2 injection projects are presently active in West Texas. Cumulatively, CO2 recovery has added more than 600 million barrels to the basin's production since 1972. The rebound in activity evident throughout the Permian is only now beginning to hit the CO2 market. "We are just starting to see an uptick in CO2 sales this year over last year's levels," says Chuck Fox, engineering vice president, Kinder Morgan. When oil prices plummet, operators tend to preferentially increase the amount of water they inject into their CO2 floods, he notes. Too, if projects are near their termination, operators may discontinue purchases of new CO2, although they still recycle CO2 already present in the reservoir. "We tend to lag higher activity levels brought on by higher oil prices by about nine months," Fox says. Growth for the CO2 suppliers and transporters will come from new projects and expansions of existing ones. "No new projects were started during 1999, but we are talking with companies that are planning start-ups in early 2001," he says. "We are seeing interest, particularly from larger independents." There are again as many candidate fields left in the Permian as are already under CO2 flood, says Fox, although the yet-to-be flooded fields are generally smaller than the in-place projects. Expansions of existing floods will likely supply more robust growth, since such augmentations require only incremental investments. "Our strategy is to create a market for our product," says Fox. "We have the molecules, the transportation and the technology. We also offer financing-the ability to help our customers by taking a working interest or net profits interest in their fields in exchange for the CO2. We see the Permian Basin as a place where we can achieve long-term, stable cash flows." Almost immediately after buying the Shell CO2 assets, Kinder Morgan also purchased a 71% interest in Sacroc Field from Devon Energy Production Co. for $55 million. Also in the deal was an 81% interest in the 150-mile Canyon Reef Carriers pipeline, running from the Val Verde Basin to Scurry County, Texas. The 50,000-acre Sacroc Unit, in Scurry County, was the first CO2 recovery project in Texas and currently produces 8,700 barrels of oil per day from 1,500 wells. Kinder Morgan also acquired minor interests in two other CO2 floods. "Although it's unusual for a midstream company like ourselves to move into the upstream, we were particularly interested in Sacroc," says Fox. "The field is our largest single contract, and we have done extensive research on its CO2 needs. We knew that we could supply the focused engineering effort necessary to bring the flood to the next level. We also wanted the pipeline, which is in an area where we believe we can expand CO2 flooding."