"U.S. gas markets are headed for a train wreck next winter," says Marshall Adkins. In a recent report, the Raymond James & Associates analyst maintains that natural-gas supply in the U.S. is falling well short of demand. He predicts that as the summer gas injection season progresses, gas prices will ramp up into the $4-per-thousand-cubic-feet range. "There is a high likelihood that the U.S. will actually run out of gas this winter even if the temperatures are warmer than normal," he says. Prices in the latter half of the winter could even spike above $10 per Mcf for short periods of time. That's the kind of forecast that has the industry looking hard at gas basins throughout the country. And one basin popping up on radar screens lately is the little-known Arkoma. The Arkoma lies tucked into northwestern Arkansas and northeastern Oklahoma, wedged between the Ouachita Mountains to the south and the Ozark Platform to the north. The small basin measures just 50 miles wide by 250 miles long, but it is stuffed with natural gas. The U.S. Geological Survey has estimated the basin's discovered reserves at 14.4 trillion cubic feet (Tcf), about two-thirds of which resides in the Oklahoma portion. Estimates are that another 4- to 10 Tcf remain to be discovered, including coalbed gases. The Arkoma abounds with gas because it hosts more than 30 productive reservoirs that are criss-crossed by a network of normal faults. Throughout the Pennsylvanian-age, deltaic pulse after deltaic pulse fed into the tide-dominated basin from the north. Further embellishing the geology, the sedimentary section in the southern part of the basin is greatly expanded, and compression from the Ouachitas thrust deepwater deposits, including turbidites and older carbonates, toward the north. All this complexity combines to yield a surfeit of traps. One of the Arkoma's original players is Southwestern Energy Co. The Fayetteville-based company has been active in the basin since it was spun off from its parent, Southern Union, in 1943. In its first year of exploration, Southwestern found the 220-billion-cubic-foot (Bcf) White Oak Field; it followed that massive find with the 1950 discovery of the 100-Bcf Lone Elm Field. The company has long been a force in the Arkoma: it has drilled just under 10% of the 13,000 producing wells in the whole basin, and it operates 20% of the 5,900 producing wells on the Arkansas side. "Southwestern's goal is to become a leading independent E&P company," says Harold Korell, president and chief executive officer. "We are striving to achieve 10% annual growth in production and reserves, to reduce production expenses, and to add $1.20 to $1.30 of discounted value for each dollar invested." In its efforts to grow, Southwestern has added to its low-risk, stable Arkoma Basin holdings a medium-potential portfolio of properties in the Permian Basin and a high-potential group in the Gulf Coast. Still, the Arkoma provides the foundation of Southwestern's reserve base. Of the 355 Bcf equivalent (Bcfe) in proved reserves that the company posted at year-end 1999, some 200 Bcfe lies in the Arkoma Basin. Of the 32.9 Bcfe Southwestern produced last year, 62% flowed from the Arkoma. Its average net production in the basin is 55.6 million cubic feet per day. Last year, the company spent $16.5 million in the Arkoma Basin to drill 40 wells; 28 of those were successful. Southwestern added 18 Bcf of reserves in 1999 from the Arkoma, posting a finding and development cost of less than $1 per Mcf. "The Arkoma is our home," says John Thaeler, Southwestern's Arkoma asset team manager. "This is the low-risk part of our portfolio, and a big part of our reserves." The company has an enviable acreage position, claiming 290,000 gross and 232,000 net acres. About 65% of that acreage is developed. Much of that prime holding lies in the fairway, an area lying roughly between townships 10 north and 7 north. The Mulberry Fault, a system of normal faults with about 2,000 feet of throw, defines the fairway's northern edge in Arkansas. North-south trending sands cut by east-west trending faults create the discrete reservoir compartments that are the heart and soul of Arkoma production. A typical fairway well recovers between 750 million and 1 Bcf of gas and costs about $250,000 dry and $400,000 completed; well depths run from 3,000 to 7,000 feet deep. Success rates, thanks to the multiple reservoirs, are quite high, generally in the neighborhood of 75%. Despite these good results, drilling in the Arkoma Basin has ebbed and flowed over time. In 1958, air drilling was introduced, doubling penetration rates. Gas drilling, using the pressured gas from nearby producing wells, also caught on. Many of the large fields were found in the mid-1950s to 1960s, when major oil companies moved into the Arkoma. The old basin's activity peaked in the mid-1980s, when companies such as Arco, Texaco, Occidental Petroleum, Santa Fe Energy and Santa Fe Minerals were eagerly pursuing the deep Arbuckle and thrusted Spiro-Wapanuka plays. At roughly the same time, another breakthrough in drilling technology shot new life into the shallow zones. Flat-bottom bits-percussion tools operated by compressed air-tripled penetration rates again. Oil-based muds also came into use, a development that greatly helped with the sloughing shale problems that were particularly prevalent on the Oklahoma side. Dale Kardash, staff production engineer, notes that in the Arkoma a third to a half of total well costs are spent in the completion phase. "The advent of foam fracturing in the 1970s was also very important for the Arkoma," he says. "Technology continues to march on in the Arkoma, even though it's a mature basin." Yet, the fairway is a depleting asset. Says Thaeler, "We still drill good wells there, but these reservoirs decline at 12% to 15% each year, and there is less potential over time. To maintain our production and reserve base, we have to step out. We're working our way south in Arkansas, and we're working outside the normal Fairway areas in Oklahoma as well." Most of Southwestern's Arkoma drilling now falls outside of the traditional Fairway. "We have a tremendous data base in the southern portion of the basin, and that's the direction we are exploring," says Bill Winkelmann, staff geologist. This year, Southwestern is focusing its efforts on the immense Ranger Anticline in Yell County, in an area dominated by Ouachita thrusting. The company has been successfully developing reserves in the Upper and Lower Borum at Waveland Field, and now is stepping out to the east along the crest of the 60-mile-long feature. In the Ranger area, completed wells cost close to $1 million, mainly due to the multiple stimulations that are required, but can recover reserves on the order of 3- to 5 Bcf apiece. Also, the company has expanded into Oklahoma, both developing its own prospects there and taking interests in outside-generated deals. In 2000, Southwestern expects to participate in more than 60 Arkoma wells, operating about half. Of the company's $55.4-million E&P budget this year, $17.9 million will be devoted to the basin. Its efforts will be split equally between Arkansas and Oklahoma, as it seeks both to maintain production levels and to replace production. "We try to challenge conventional wisdom," says Thaeler. "We ask ourselves, is there a scientific foundation for the conventional wisdom in the Arkoma? That's how we have to approach mature basins." Arkansas Western Gas Co. is a natural-gas utility that is a subsidiary of Southwestern Energy Co. "AWG's fate has been intertwined with the Arkoma Basin since 1929," says Charles Stevens, senior vice president. From an initial 87-mile pipeline carrying gas from Clarksville to the communities of Fayetteville, Springdale and Rogers, AWG has grown to 400 miles of gathering system and 50 miles of transmission and storage lines in the basin, and 134,000 customers in Arkansas. "In a normal year, we run about 25 Bcf through our system," says Stevens. "That's a mixture of about 18 Bcf for residential and commercial heating load and 8 Bcf in industrial load." AWG's peak day to date occurred in 1996, when it delivered 226 million cubic feet. "If we hit a peak day today, it would push us well over 250 million cubic feet per day because of customer growth. In the Fayetteville-Rogers-Bentonville corridor, we are growing 4% to 5% per year; overall the whole system is growing about 2.5% to 3% per year." What's happening with AWG mirrors what is happening with the natural-gas industry nationwide. "For years and years, if we needed more gas the producers in the basin just drilled more wells," says Stevens. "That's all changed now. We need more gas than we can buy from behind our gathering system, so we also buy off the interstate lines. As we go forward, we will be buying more and more gas off the interstate lines." Another firm with a long-time stake in the Arkoma-first on the Oklahoma side and now in Arkansas as well-is Houston-based Vastar Resources, one of the basin's top producers. "Certainly, the Arkoma is the jewel in the crown for the Midcontinent region for Vastar," says Maureen Johnson, Houston-based Midcontinent production manager. The well-known Wilburton Field is Vastar's biggest position, but the company also has assets in Oklahoma's Kinta, Red Oak and South Panola fields, as well as in Arkansas. "We cover the Arkoma Basin reasonably well," she says. Jeff Fisher, Midcontinent engineering manager, notes that Vastar operates 350 Arkoma wells and holds nonoperated interests in another 250 wells. Its gross operated production in the basin is 120 million cubic feet per day. "We drill 30 to 35 operated wells per year, and we've been running a three- to five-rig program. We participate in another 20 nonoperated wells each year." The company devotes $35- to $40 million per year to the Arkoma, making the basin one of its largest onshore focus areas. Vastar's business strategy in the Arkoma has been to develop legacy assets and acquire new assets, and to extend both through drilling, says Johnson. The company has been particularly successful at enhancing its position in South Panola Field, a highly thrusted, deep Spiro play in Oklahoma's Latimer and LeFlore counties. South Panola wells range from 15,000 to 17,500 feet deep. The play is very complex, with high stakes and high rewards. On the upper end, a Spiro well can make 15- to 20 Bcf, initially flowing at rates of 5- to 10 million cubic feet (MMcf) per day. "South Panola has yielded some of our best wells, and some of the best wells in the state of Oklahoma," says Fisher. "Not many companies compete with us in the play because it's so complex." "Playing the Spiro is technically challenging," says Johnson. "We've used 3-D seismic to help us and we've used our stratigraphic understanding to reduce geologic risk. We've also been able to drop our drilling costs from $4 million to as low as $2.5 million per well." The cost savings have mainly come from hard-won experience, she notes. "We're a long-term player in the basin, and that's paid off for us. And by driving drilling costs down, we've gained a competitive advantage in the thrusted Spiro play and we earn a competitive rate of return." Vastar's anchor asset in the Arkoma continues to be Wilburton, the field that sparked Arbuckle fever more than a decade ago. It has produced 1.8 trillion cubic feet of gas, 350 Bcf of that from the Arbuckle. "Although the Arbuckle in Wilburton Field is fully developed and steeply on decline, our total production in the field has been stable over the last several years," says Johnson. Indeed, Vastar has increased its overall Arkoma production by 25% in the last three years, and last year it replaced 160% of its production. The company has a two- to three-year portfolio of prospects. "We find that as we drill more wells in these multipay fields, we find more opportunities," says Fisher. That's certainly been the case in Wilburton. "The percentage of reserves attributed to the Arbuckle has been declining, but our total reserves in the field have also remained stable," says Johnson. In the last five years, Vastar has been developing both Spiro, Cromwell and Simpson reservoirs between 10,000 and 13,000 feet. "We shot a 3-D seismic survey over Wilburton in 1997, and that replenished our portfolio. We've stayed very active there." Vastar also plays at the other end of the spectrum, drilling much shallower and less complex wells on the Arkansas side. Like others, the company also is investigating the emerging coalbed methane play in the basin. (See sidebar, "The Next Powder River?") "We also continue to buy assets. In the last three years, we've acquired or traded for about $80 million worth of properties," says Fisher. Vastar's acquisitions account for about one-third of its current production and capital activity. "We see opportunities to continue to consolidate," says Johnson. "Certainly for us, the Arkoma offers enough attractive opportunities to compete with other domestic areas." Given its inviting qualities and the enthusiasm the industry has for domestic natural gas, it's hardly surprising that the Arkoma also has been attracting interest from companies that are not traditional players in the area. Certainly, Cross Timbers Oil Co. has made the most impressive entry into the old basin. The Fort Worth-based outfit has gambled big on the Arkoma's potential, spending $468 million on two major acquisitions in the last year. The company bought interests in 2,500 wells and 435,000 net acres of leasehold, formerly owned by Ocean Energy Inc. and Tulsa-based Spring Holding Co. The 480 Bcfe of proved reserves raised Cross Timbers' 1999 year-end reserve total to more than 2 Tcf. About 90% of its new properties lie on the Arkansas side of the basin, and the purchases have vaulted Cross Timbers into a leading role. The company is now the largest gas producer in Arkansas, making 120 million cubic feet per day net. "We wanted to get into the Arkoma Basin for some time," says Keith Hutton, executive vice president, development and exploitation. Cross Timbers' strategy is to bring current technology and innovative techniques to underexploited basins, striving to attain a 50% to 100% gain in reserves and production levels. "The Arkoma Basin shared many of the attributes that we've seen in other areas. We saw many enhancements we could make on the production side," says Hutton. In particular, Cross Timbers saw potential in reducing the relatively high line pressures common in the Arkoma. "We've done well in the San Juan Basin by lowering pressures. Many of these wells produce into 200-psi lines, and we can pull them down to 20 or 30 psi," he says. "We saw a lot of upside there." Cross Timbers also plans to add artificial lift to a number of the producers. "In their previous production, the wells were strong enough to produce without artificial lift, but many are now at the point where they do need it," says Hutton. "It doesn't take much water to load up a gas well to where it doesn't produce at full capacity." Too, the Arkoma's multiple pays and complex structural geology were appealing. "We have done really well with complex areas in the past," says Hutton. "It means there is a lot of compartmentalization in the reservoirs, and that's opportunity for us." The independent also intends to reprocess existing 2-D seismic lines, to better delineate faults and reveal smaller reservoir compartments that might have been missed in the past. "We'd like to shoot some 3-D surveys as well and see how they work, both in the developed field areas and in the more exploratory areas," he notes. "We also want to use some different logs, such as dipmeters, formation microimaging tools and so forth, to help tell us the location of the sand channels and angles of the faults." For 2000, Cross Timbers will drill 28 net and 45 gross wells, and complete 45 net and 75 gross workovers. Its $12.8-million capital budget for the basin favors the Arkansas side, with about 75% of the funds devoted there. On existing wells, the company will add wellhead compression, commingle zones, add artificial lift, and restimulate and recomplete zones. "Some Arkoma wells are natural completions, and a common fracture treatment has been in the 30,000-pound range. We're looking at bigger fracs in certain areas, in the 150,000-pound range," says Hutton. Exploratory work, while not the main focus of Cross Timbers' efforts, will consist of deeper tests in existing fields, trend extensions, and some wildcatting on acreage in the Fort Chaffee area. "We also have an area in Oklahoma where we've drilled a successful Cromwell test, and we're working on some prospects in Arkansas south of our main acreage position." Already, Cross Timbers has identified 180 well locations, following the current rules of the Arkansas Oil & Gas Commission. "We think that the Arkoma will provide us with lots to do for a long period of time," says Hutton. The Arkoma is an integral part of Chesapeake Energy Corp.'s drilling program and asset base as well. By Arkoma standards a relative newcomer, Oklahoma City-based Chesapeake became involved in the basin about six years ago, although the company's cofounders have been involved in the basin since 1983. Now, however, the company is strongly ramping up its presence there. At press time, Chesapeake was in the process of acquiring the entire Arkoma Basin assets and reserves of Denver-based Barrett Resources Corp., as well as two other smaller acquisitions. Prior to the acquisitions, Chesapeake owned reserves of 50 Bcfe in the Arkoma; after the deals close, those reserves will jump to 80 Bcfe. Not including the leasehold currently being acquired, Chesapeake already holds 300,000 gross acres in the Arkoma, all on the Oklahoma side. About 75% of that position is undeveloped. The company focuses on Oklahoma because it believes that its familiarity with and experience in dealing with Oklahoma land issues and the Arkoma's complex geology provides it with a strong competitive advantage there. "The Arkoma will take on even more prominence for us in the future," says Mark Lester, senior vice president of exploration. "We have doubled our presence in the basin during the past year." For 2000, the company intends to spend at least $10 million of its $150-million company-wide 2000 drilling budget in the Arkoma. Chesapeake's primary targets are the Middle Atoka and Spiro sands, mainly in Latimer, LeFlore, Haskell and Pittsburg counties; it also has positions in McIntosh, Sequoyah and Coal counties. "We plan to keep two rigs active for the foreseeable future, in addition to activity related to an extensive coalbed methane joint venture we have just formed," says Lester. (See sidebar "The Next Powder River?") One of its rigs will be drilling 14,000- to 16,000-ft. Spiro wells and the other will be drilling Middle Atoka wells in the 5,000- to 9,000-ft. range. "We can drill and complete the shallower wells for $400,000 to $700,000, and a 16,000-foot thrusted Spiro well for $2.5 million," he says. Chesapeake employs 2-D seismic data to delineate the faulting and productive trends, especially in the overthrusted Atoka play. "We have also acquired 100 square miles of 3-D seismic, which we use to pinpoint undrained fault blocks and additional drilling locations. "We see a lot of upside potential in the Arkoma Basin in the Middle Atoka sands, and there's a great deal of drilling that remains to be done," says Lester. The Arkoma, like many other Lower 48 basins, is home to a vibrant community of local and private independents. Fort Smith-based Hanna Oil & Gas Co. is one of the local success stories. Jim L. Hanna, a landman who originally hailed from Wichita Falls, Texas, founded the private firm in 1969. Hanna, currently the chairman of the company, came to Fort Smith with Bridwell Oil & Gas Co. in the early 1960s. "We operate about 120 wells, and we have an interest in an additional 450 wells," says Hanna. "We put together leasehold positions and sell prospects." "We are deal-oriented," says his son, Bill, who serves as president. "We look at things from the land side of the equation. The deal drives us." The company rose to prominence in Arkansas in 1972, when one of its first operated wells blew out flowing 100 million cubic feet per day. "At the time, the Lincoln well was one of the biggest wells drilled in the state of Arkansas," says Bill. "It had a huge influence on our company. The Lincoln has produced more than 15 Bcf and is still producing, and it is the root of our company. That well allowed us to do more things." The Hannas still see opportunity in the Arkoma. "We try to look at the trends differently," says Bill. "New thinking in an old area is a great way to explore, and we've done really well with that. For instance, in some areas we play certain sands that we think trend east-west." Prospecting outside of the fairway has also been Hanna's strategy. "In the past three years, our largest Arkansas prospects have been south of the fairway," says Bill. "For 2000, our drilling program is mainly in 6 north. That area has multiple sands, and we can put together good-size acreage positions." The company also plays the Oklahoma side of the basin, and some of its best producers are Hunton, Spiro and Cromwell wells. "There's not much open acreage on the Oklahoma side, so we mostly put together farmouts for those prospects," he says. One positive development many operators remark upon has been the improvement in the marketing situation in the Arkoma. "Years ago, we had only one choice for getting to market," says Bill. "Today the basin has four or five different gatherers, and we have four or five good, big transmission pipes that we can get our gas to. It's good to have a competitive environment." Last year, Hanna Oil & Gas posted a 75% success rate. It drilled 12 to 15 operated wells and had nonoperated interests in about the same number. "We drill about the same program year in and year out, and if we keep our success ratio in that same range, we do fine. We've had a good string of success, and we're been able to put together profitable years," says Bill. Like other operators that call the Arkoma home, the company also has looked outside the basin for growth opportunities. For the last 13 years, it has pursued interests in Canada, mainly nonoperated working interests in southern Alberta. Hanna Oil & Gas also owns several service companies that cater to the needs of the small Arkoma independents. "We're pretty diversified," says Jim Hanna. Son Mike, president of the service companies group, handles Quick Lay Pipe Co., Quick Transports Inc., Quality Completions Inc., Property Transfer and Quik Chem Inc. "We started some of these service companies to facilitate our own work," says Mike. "Large companies tend to like to work with large companies. Small independents have a tough time getting jobs done because of the restraints large service companies put upon them, from pricing structures to utilization requirements." The Hanna service group works for more than 25 companies. "Activity has been slow for the last year or 18 months, but it is now picking up. Finding people to operate the rigs is already a problem," says Mike. Another private E&P firm with strong service ties is Oxley Petroleum. Mike Oxley, president and chief operating officer of Tulsa-based Oxley Petroleum, was the driving force in New Prospect Drilling. After almost 20 years in the drilling business, that firm sold its seven-rig fleet to Nabors Drilling about 18 months ago. Oxley Petroleum Co., founded in 1962 by John C. Oxley and John T. Oxley, develops properties in the Arkoma and Anadarko basins. The company's early success was scored in the late 1960s in Oklahoma's South Quinton Field in Pittsburg County. John C. Oxley spearheaded the company's development of several 30- to 40-Bcf wells in the Pennsylvanian Red Oak sands, drilling up a six- to seven-mile, narrow sand channel. Today, Oxley Petroleum owns interests in several hundred wells and holds a substantial acreage position in the basin. "Currently, we're running two rigs, drilling for Middle Atoka sands in two areas in eastern Oklahoma," says Oxley. Southwestern Energy is a 50-50 partner in both projects, Ashland in Pittsburg County and Cherokee in LeFlore County. At Ashland, the partners have drilled six successful tests out of six attempts; at Cherokee, they have scored 10 producers out of 13 tries. "We've had our share of success," notes Oxley. "We're typically finding 2- to 4-Bcf wells in our Ashland project in the Middle Atoka at about 7,000 feet. The Cherokee wells are of similar magnitude." This year, Oxley plans to drill 20 to 25 wells. "We like to operate everything that we do," he says. "We concentrate primarily on the Oklahoma side, developing our own prospects. We see more opportunity on the Oklahoma side, but we have a sizeable acreage position there. That gives us opportunities that other operators might not have." Contemporaneous with Mike Oxley selling New Prospect Drilling Co., he formed New Prospect Co. This oilfield services company has about 90 employees and engages in wellsite and office engineering; road, location and pipeline construction; and wellsite data collection and pumping services. "We knew that the basin needed solid engineering," says Oxley. "We can provide that-we have lots of experience. Over the past 20 years, we have drilled and completed more than 700 wells, representing 4 million feet of hole." New Prospect's clients are both large and small independents, says Jerry Rusnak, executive vice president. "When companies try to grow through mergers and acquisitions, they have to evaluate a very large number of new properties very quickly. We can help them with that." Too, new owners like to operate a large number of wells with a very small overhead. "They usually plan to do that by using new technologies, and we can help them with that as well." "We've been in this basin 20 years, and we've gone through a lot of tough times," says Charlie Newman, vice president of operations. "We've learned what we know the hard way. Right now, business is good, and we're trying to hire more people. We're busy and we expect to get much busier." Indeed, with active new players, unflagging optimism among the traditional operators, and stable-to-higher 2000 drilling budgets, the Arkoma Basin looks ready to enjoy yet another resurgence.