San Juan Basin Revisited

Oilfield workers confer at BP Americas’ Durango #603 coalbed methane well pad in La Plata County, Colorado. The vast San Juan Basin, which bridges northwestern New Mexico and southwestern Colorado, contains the largest natural gas field in the U.S., based on proved reserves.

The San Juan Basin, a circular and nearly bowl-shaped depression straddling northwestern New Mexico and southwestern Colorado, is one of the most prolific gas-producing regions in the U.S.

It contains the nation’s largest natural gas field, based on 2007 proved reserves, in more than 26,000 square miles of sedimentary rock more than two and a half miles thick in places, ranging in age from about 570 to 2 million years. New Mexico contributes about 70% of the gas production of the basin, where typical well depths range from 2,000 to more than 7,500 feet.

Early pioneering work by Amoco Production (merged with BP Plc in 1998) resulted in the first coalbed-methane well drilled in 1977. Unfortunately, at the time gas prices were soft and coalbed-completion techniques were still in their infancy.

Yet, intrepid explorers continued to find ways to exploit the basin and optimize drilling and completions through the 1980s (thanks to a period of tax credits for unconventional natural gas sources) and 1990s.

Today, majors, independents and privately held E&Ps count on the estimated 12.9 trillion cubic feet (Tcf) of recoverable reserves remaining in the major producing formations— the Dakota, Mesaverde, Pictured Cliffs and Fruitland coal—to provide a platform of core assets for their businesses. And, although the basin has been in development mode for quite some time, oil and gas companies remain enthused about its potential.

BP America Inc., based in Houston and a subsidiary of BP Plc, has some $2.4 billion dedicated to the basin. It plans to boost its share of ultimate recovery of coalbed-methane gas from southwestern Colorado by an estimated 1.9 Tcf, by drilling 1,000 infill wells (180 of which have been completed to date) during the next decade. The investment will maintain BP’s current net production of 800 million cubic feet per day in the area.

“In La Plata County in Colorado, we have a major position in the Fruitland coal,” says Jeff Braun, San Juan performance unit leader for BP America. “We operate about 1,200 wells there, producing about 600 million cubic feet a day.”

BP’s other major operation, in Farmington, New Mexico, produces another 250 million per day from 2,300 wells in the Dakota and Mesaverde formations.

Although San Juan gas prices had fallen to about $2.50 per million Btu in June, BP has no plans to exit the area.

“That’s low, compared to last year when the Henry Hub price averaged $9, and the San Juan price was around $6.50 to $7,” says Braun. “It presents a big challenge.”

Braun notes that despite the deflated gas price, most oilfield costs remain stuck at 2008 levels. The company is responding by adjusting drilling and workover activity and negotiating with equipment and service providers to reduce costs. Chemicals, well services and completion costs are all fair game, he says.

The San Juan is a challenging environment or small independents and majors alike, says Jeff Braun, San Juan performance unit leader for BP Americas.

“We were running two rigs in the basin, but reduced that to one rig in June. That’s a matter of adjusting the activity to ensure that we preserve cash flow. As the recovery happens, we will go back in with our second rig.”

Braun’s other strategy is to maximize efficiency. Because BP has been producing in Colorado since the 1920s and has legacy assets and efficiencies from its large-scale operations (supplying 1.5% of the nation’s gas), it has no plans to shut in any San Juan wells or hedge its gas.

“We have a great incumbent position here, and decades of reserves,” says Braun. “There is no doubt that this is a challenging environment for small independents and majors alike. But we know the recovery is going to happen, so we are positioning ourselves to continue to develop these resources in a strategic manner for the long term.”

Along with such large-scale development comes environmental responsibility. “In New Mexico, across all our wells and facilities, we changed over to low-bleed control valves and significantly reduced bleed-off emissions,” says Braun.

“In Colorado, as we designed our infill development program, we worked with the county and the state to develop 2 Tcf of resource in a way that reduces our environmental footprint with regard to drill-pad size, noise and greenhouse-gas emissions.”

To reduce emissions, the producer is working in tandem with La Plata Electric Association of Durango County, Colorado, to build all-electric wellsites where possible. With supplemental funding by BP, the power company installed power transmission and infrastructure at some drillsites, thus removing the need for diesel generators.

In general, BP plans to use a factory approach to drill more than 700 new wells, for which it has obtained regulatory infill approval. The company also plans to construct associated field facilities. To minimize environmental impact, BP will drill almost all its new wells from existing well pads, using existing roads and pipelines where possible. At present, the producer typically drills one well per pad, but going forward it is committed to drilling multiple wells on existing pads whenever possible.

Coalbed-methane exit

Elsewhere, D.J. Simmons Inc., a family-owned limited partnership headquartered in Farmington, New Mexico, has exited the coalbed methane business altogether. The company now operates about 80 natural gas wells on 8,000 producing acres in the San Juan. It also has assets outside the basin, altogether producing some 5 million cubic feet of gas and 100 barrels of oil per day.

“We are waiting for gas prices to go back up, but we certainly aren’t panicking or selling anything,” says A. B. Geren, chairman of the board, D.J. Simmons Inc.

“We drilled about 60 coalbed-methane wells in the past,” says A. B. Geren, a 1949 Texas Aggie alum and chairman of the board. “Several years ago, we sold them all to Koch Industries, a company that could take advantage of the tax credits associated with them. Now we have gas wells in the Mesaverde, Dakota, Pictured Cliffs, and Gallup sandstone formations.”

Geren, a second-generation oilfield veteran who turned 87 in June, has been through the downcycles before, so he and president and chief executive John Byrom know how to work the economics. Byrom served as the president of the Independent Petroleum Association of New Mexico during 2008.

“Right now, gas prices are very low, which affects the economics on even shallow wells,” Geren says. “During these cycles in prices, the San Juan gas netback is usually a dollar less than the Henry Hub price.”

The company has been in the basin since 1952. To its credit, D.J. Simmons has survived the cycles and used each to gain experience with various adverse conditions and to build coping strategies. Sometimes those strategies boil down to simply “wait and see.”

“We are waiting for gas prices to go back up, but we certainly aren’t panicking or selling anything. Our bankers are still very happy with us,” says Geren.

Byrom admits that, in early 2008, when commodity prices drove the company’s valuations very high, he could have been tempted to borrow substantially from the firm’s bank, the Bank of Oklahoma. “But I wasn’t and we didn’t,” he says. “When our reserves value dropped in the spring, our borrowing base was reduced as well. Yet, we were well below the borrowing-base ceiling, so we were not forced into a fire sale of our properties. That is the death spiral.”

To cope with the downturn, the management team keeps its debt-to-equity ratio low, hedges production and maintains built-in cost-control mechanisms.

“It’s frustrating to be working so hard on good projects and then watch them flounder while we wait for prices to recover,” says John Byrom, president and chief executive, D. J. Simmons Inc.

As a diversification strategy, Simmons developed two subsidiaries. In 2001, Simmons formed a compressor company, Twin Stars Ltd., which leases wellhead compressors to area operators and maintains them. Since its inception, Twin Stars has grown to employ 30 people and has placed more than 400 compressors at drillsites in the area.

“We also own an oilfield service company, Simmons Well Service, which has two workover rigs and a swabbing unit. Business picked up somewhat after the winter season,” says Byrom.

Byrom refers to seasonal restrictions in the Carson National Forest in the basin’s Jicarilla Ranger District, an area hosting more than 600 gas wells and some 400 miles of roads and pipelines. Most leases include seasonal timing restrictions to balance the public’s need for gas with environmental protection for the Mexican spotted owl’s nesting habitat, cultural resources and wintering big-game animals.

“Proactively, we have also lowered our rig and compressor rates for our customers,” says Byrom. “That cuts into our profits, but it helps them weather the storm, shows that we appreciate them and hopefully gains customer loyalty. It’s a good investment for the long run.”

Fruitland coal

Birmingham, Alabama-based Energen Resources Corp., a subsidiary of Energen Corp., also targets the San Juan Basin as an integral part of its portfolio. Julie Ryland, vice president of investor relations, says that the basin makes up about 55% of Energen’s asset portfolio. The $2.6-billion market cap producer, with additional assets in the Permian and Black Warrior basins and in North Louisiana and East Texas, holds some 1.9 Tcfe of proved, probable and possible reserves.

Energen entered the San Juan Basin in 1997 with the acquisition of 319 billion cubic feet equivalent (Bcfe) of conventional proved reserves acquired from Burlington Resources, an E&P later absorbed by ConocoPhillips. Today, Energen focuses its drilling in the over-pressured Fruitland coal formation. Coalbed methane accounts for 62% of its 871 Bcf of proved reserves in the basin.

Yet, like giant BP and minnow D.J. Simmons, Energen is not immune to the downcycle and has developed coping strategies until recovery. One strategy is to cut its 2009 drilling budget for the basin to an estimated $62.4 million from $166.9 million in 2008.

“The decrease in the drilling budget in the San Juan Basin is reflective of significant cuts in total capital spending companywide in 2009, as a result of economic recession and low commodity prices,” says Ryland. Meanwhile, production is expected to increase to 53 Bcfe in 2009, up from 50.3 billion in 2008, primarily due to the cumulative effect of accelerated drilling in 2007 and 2008.

“We are evaluating all properties and delaying previously identified compression change-out and workover activity until economics are better,” says Ryland. “We are working with service providers to ensure premium services for lower costs and securing services for drilling programs rather than on a well-by-well basis. We are also limiting staff additions.”

Another strategy is to hedge production and equalize cash flow.

“A mainstay of Energen’s risk management is hedging,” says Ryland. “Through this strategy, Energen significantly insulates cash flows and earnings from commodity-price volatility.”

For the company’s total assets, during the second half of 2009, it hedged 75% of its estimated gas production at an average Nymex-equivalent price of $8.09 per thousand cubic feet, 77% of its estimated oil production at an average Nymex-equivalent price of $71.14 per barrel, and 61% of its estimated natural gas liquids production at $1.15 per gallon.

In addition, Energen hedges basis differentials in the San Juan and Permian basins. About 78% of the company’s gas production in the second half of 2009 there has been hedged back to the wellhead, as well as some 80% of its estimated liquids production. Energen also has “substantial hedges” in place for 2010 and 2011, says Ryland.

In second-half 2009, the company plans to drill 44 gross wells (30 horizontals), compared to 72 (24 horizontals) in 2008, with finding and development costs of $0.75 per thousand cubic feet equivalent for probable and $1.04 for possible reserves.

To date, Energen Resources has drilled more than 100 horizontal wells, (representing about 36% of daily production) in the San Juan Basin, targeting Fruitland coal at depths of 3,000 to 3,500 feet, says Ryland. The company’s horizontals and vertical sidetracks are primarily on state and federal lands, some under Navajo Lake. Its longest horizontal well to date is about 5,000 feet.

“The San Juan Basin continues to be an outstanding performer for Energen, which has built its presence in the basin through acquisition and exploitation,” says Ryland. “Over the last 12 years, Energen’s gross operated production has grown from less than 30 million cubic feet per day to almost 210 million.”

Although Energen absorbed some of Burlington Resources’ assets, it didn’t get them all. Houston-based ConocoPhillips kept a big chunk for itself.

“ConocoPhillips is now the largest gas producer in both the San Juan and in New Mexico,” says Jeff Corey, ConocoPhillips’ San Juan Basin development manager. “We acquired those assets through the mergers of Conoco, Phillips and Burlington Resources, completed in 2005. Each of those companies, in their own right, was a large operator in the San Juan.”

ConocoPhillips has six rigs working on its 1.6 million acres in the basin, down from 11 in 2008. Although the company drilled 257 net wells in 2008, it plans to drill only 175 wells this year, a result of “the deterioration of the investment environment and increased regulatory costs,” says Corey.

But the producer is expanding its recompletion program, ramping up from 12 in 2008 to 30 this year, and plans to undertake several hundred workovers by adding shallower zones or plugging existing zones and moving to new zones with perforation and fracture operations.

“Although the industry, including ConocoPhillips, is still learning where and how to best utilize horizontal drilling in the San Juan, we’ve had considerable success in the higher-quality Fruitland coal formation,” he says. The company considers its operations here, which contribute some 1.1 Bcf net per day to its global gas production, to be a core asset in its Lower 48 portfolio.