Permian Plays

Apache Corp. pumping units punctuate a field of sorghum in Adair San Andres Field, Terry County, Texas.

T?he Permian Basin, worked by nearly 1,700 operators, is one of the most-drilled basins in the world. Reaching from just south of Lubbock, Texas, to just south of Midland and Odessa, then westward into the southeastern part of New Mexico, it involves an area some 250 miles wide and 300 miles long.

For more information, download the Petroleum Basin Petroleum Association Magazine (PDF).

The sedimentary basin holds one of the world’s thickest deposits of rocks from the Permian geologic period and comprises several component basins. Of these, the Midland Basin is the largest, the Delaware Basin is the second largest, and the Marfa Basin is the smallest.

The Permian Basin produces some 1.5 million barrels of oil per day from zones as shallow as 5,000 feet and as deep as 25,000.

The mighty Permian Basin’s long-lived, low-cost producing trends are found in the Midland, Delaware and Marfa basins. It produces some 1.5 million barrels of oil daily.

As attractive as it is, for myriad reasons some E&Ps occasionally want out. For example, Marathon Oil Corp. recently announced its intention to sell a 50% interest in its Big Lake, Burton Flat, Chenot Putnam, Drinkard, Grierson Spring, Herrell, Howard Glasscock, Monument, South Eunice and Vacuum fields, and 100% interest in its Indian Basin Field and gas plant.

Nonetheless, West Texas’ long-lived, low-cost producing trends are still a mainstay for many independents, as evidenced by the Texas Railroad Commission’s November 2008 report that lists another 461 oil-well completions logged that month (in Railroad Commission District 8), with no significant slowdown in sight.

The Permian is not without its challenges. While producers use manufacturing-style operations and enhanced production methods to glean marginally more from each well, they’ve seen oilfield-service costs rise to high levels while oil prices plummeted. Service costs have yet to follow.

But producers have encountered this type of environment before, and they know what to do.

“New plays were energized by the higher oil prices seen up through the first half of 2008,” says independent Taylor Mayne, president of the Permian Basin Petroleum Association in Midland. “One of the bigger Wolfberry operators said $70 oil could still justify activity. Now we are at around $45. Does that mean it’s shutting down? I don’t think so, but now there is definitely a lack of aggressiveness. Permian producers are being cautious.”

Permian Basin plays still add a good balance to a portfolio. “Certainly there are a lot of companies solely focused on this area’s assets, and they have done very well over time.

“Resource plays in the area, such as the Wolfberry, a protraction of the Spraberry, have been ramping up in recent years. As is typical, producers drill multiple wells on a statistical basis, rather than explore for isolated structural or stratigraphic features with only one- or two-well prospects. That has been driving independents’ recent activity.”

Meanwhile, results from the Permian Basin’s Barnett shale have been mixed. Success depends on using the appropriate fracturing and completion technologies for each well, but which is appropriate?

?Permian Basin producers have struck a note of caution since soaring commodity prices in 2008 energized new plays, according to Taylor Mayne, president of the Permian Basin Petroleum Association.

“A successful method of stimulation in one area does not necessarily work as well in another,” says Mayne. “We are only three to five years into the learning curve in the Wolfberry play. There has been some success, but it is in an area with limited infrastructure, so there may be some wells that haven’t been put online that might otherwise be making headlines.”

Also, local rumor is that the Deep Haley, with its overpressured Lower Permian and Pennsylvanian sandstones and carbonates, may be a hot gas play. Numerous wells have been drilled into an older producing region, which could almost be categorized as a resource play, but word is that some of those wells have substantial decline rates.

The current challenge for West Texas producers is reduced revenue due to lower oil and gas prices, but that’s also nothing new. Even during boom times, the Permian is known for being a low-cost producing region.

“That works to our advantage,” says Mayne, “but in some situations our profit margins are not as great as in other areas. So, in those cases, we’re definitely price sensitive.

“Several years ago, when oil prices first climbed to $40 per barrel, service and supply costs were considerably lower. Producers were elated at $40 oil,” he says. But supply and demand fundamentals worked on service costs over time, driving them up. Now, in the downturn, those costs are not falling as quickly as commodity prices. “The profit margins enjoyed on the way up are not there on the way down.”

That lag is the key current concern of Permian producers. Oilfield-service providers have a natural reluctance to lower prices because some expect the downturn is going to end fairly quickly.

A border of pumping-unit silhouettes decorates a building in Midland, Texas.

“But I haven’t heard of any producers that share that opinion,” says Mayne.

Nonetheless, optimism is inherent in the mindset of Permian players, he says. “We maintain an optimistic viewpoint in just about everything we do. However, we plan for the worst-case scenario and hope for the best. We are planning, but not panicking.”

Other concerns include banking relationships, hedging positions, counterparty risks and the global economy—factors that are, for the most part, out of producers’ control, but that are exacerbating the downturn.

“There’s no doubt that oil and gas prices became too high, but there is an overreaction now. The financial crisis is dragging us down. That overreaction should correct itself, although I don’t expect many people are running long-term economics at $70 oil anymore.”

Much of the current Permian activity is being driven by decisions made in 2008 when oil prices soared. For example, Mayne’s own privately held E&P company, Mayne & Mertz Inc., hired a drilling rig in June—at June prices.

“If I were able to make that decision today, I would hold off,” he says. “But I have a contract and liability for the rig. So, consequently, we are drilling the well. It’s probably not something we would have pulled the trigger on if we had flexibility. Other producers are most likely in a similar situation. As these commitments drop off, we will see drilling activity fall.”

Going forward, the domestic rig count may decline by 500 to 600 rigs, according to Mark Urness, a veteran oilfield-service analyst for Calyon Securities (USA) Inc. He also anticipates a 15% decline in worldwide E&P spending in 2009, led by a nearly 25% reduction in North America.

The good news is that many West Texas producers had reduced their debt during the commodity-price boom—in some cases, entirely—which will help protect them from the storm.

Enhanced production

Many West Texas players, such as Denver-based Whiting Petroleum Corp., are making the best of their assets by using every technique up their sleeve, including enhanced oil-recovery methods, to boost production in long-lived fields. Whiting initially entered West Texas through its $345-million acquisition of 41.9 million barrels of oil equivalent (BOE) of proved reserves (59% developed) for $8.22 per barrel in September 2004.

Apache Corp.’s expansion of its facilities in Adair San Andres Field, Terry County, supports its CO2 injection and recycling program.

Whiting uses CO2 flooding to coax its crown jewel, North Ward Estes Field, into increased production. The field, found in Ward and Winkler counties, was acquired by Whiting in October 2005 for $459.2 million.

“We acquired this water and CO2 flood, with proved reserves of 82.1 million BOE per day, for about $5.58 per barrel,” says James Volker, president and chief executive. “At the time, about 36% of that was proved developed.”

The field includes six base leases with 100% working interest in 58,000 gross acres with about 1,024 producing and 349 injection wells. The Yates formation, at 2,600 feet, is the primary producing zone with additional production from other zones, including Queen at 3,000 feet. Whiting also has rights to deeper horizons under 34,140 gross acres in the field.

In May 2007, Whiting initiated its CO2 flood in North Ward Estes and increased production to 100 million cubic feet of gas per day by January 2008. “We are currently injecting approximately 130 million cubic feet of CO2 per day into the Yates formation,” says Volker.

Workmen bolt pipe sections during construction at Apache Corp.’s Adair San Andres Field.

At approximately 20 miles long and three miles wide, the field is one of the largest CO2 floods in the U.S. Whiting has a long-term CO2 purchase agreement with a major supplier to assure CO2 supply for the field.

By November 2008, net production had increased about 33%, reflecting the reservoir’s response to the water- and CO2 floods.

Peak production is expected to occur in 2014 at a net rate of between 10,000 and 13,000 BOE per day, then plateau at that rate for three to five years before beginning a single-digit annual decline during the next 20 years, he says.

At year-end 2007, an estimated 89 million barrels of probable and possible reserves were attributed to the company’s North Ward Estes Field. The biggest challenge has been large front-end capital requirements without corresponding production increases, and the impact of cost inflation.

About $1 billion will be required to fully develop the field, Volker says. Of that, some $375 million of total capex will go toward purchasing CO2, while the balance would primarily go toward converting wellbores to injection and producing wells, and to create or upgrade CO2 facilities and infrastructure. Estimated acquisition and fully developed costs for the field as of year-end 2007 hovered at $16.90 per BOE.

“Our strategy to mitigate the impact of cost inflation has been to purchase equipment well before it is needed,” he says. “We believe we saved millions of dollars with this strategy in 2006 and 2007.”

Nearby, Whiting works its Keystone South Field in Winkler County, holding 100% working interest in the 7,261 gross acres, which are entirely held by production.

The field produces primarily from the Lower Clear Fork formation, although seven other zones are also productive. Gross production from Keystone South was about 1,000 BOE per day in December. The company is experimenting with several horizontal wells there and has implemented a waterflood.

“Our CO2 team in Midland, led by Pete Hagist, is second to none in our industry,” Volker says. “Our Midland team averages about 25 years of experience, primarily in tertiary projects. They employ the very latest technology in reservoir computer modeling and 24-hour surveillance systems to most efficiently implement and manage the field’s water- and CO2 flood.

“With more than 1 billion barrels of oil equivalent originally in place, the North Ward Estes Field is a world-class reservoir.”

Proper proppant

Another Permian player, Houston-based Apache Corp., entered the basin in 1991 by acquiring properties from Amoco Corp.

“It was Apache’s first really large acquisition in the Permian,” says Tom Voytovich, Apache vice president, central region. “At that time, drilling economics weren’t attractive, so we focused primarily on operational issues.”

Apache bought more Permian assets from Texaco Corp., followed by several other purchases, to eventually become the Permian Basin’s fourth-largest producer. “Never have we been more active here than we are right now,” says Voytovich.

Some of the company’s properties in West Texas have been producing since the late 1920s. All of its acreage is held by production.

“We are still drilling wells and getting excellent results,” he says. “Not only are these properties outstanding cash-flow generators, but they also represent an enormous resource potential, which is an important component of our corporate portfolio.” Apache potentially has 600 million barrels or more of oil yet to be developed here.

The company is focused on two primary areas: the Central Basin Platform and the Northern Shelf.

The Central Basin Platform, in Winkler, Andrews, Ector and Crane counties, yields primarily Clearfork and Wolfcamp production at 3,000 to 7,500 feet, with some Grayburg and San Andres production.

Apache works its Northern Shelf play, encompassing Gaines, Yoakum, Cochran and Hockley counties, using CO2 enhanced recovery some 5,000 feet deep into the San Andres formation.

The company is currently expanding its CO2-flood facility at Adair San Andres Field in Gaines County that was acquired from Hess Corp. in 2006, and targets the San Andres and Wolfcamp. The field is Apache’s largest U.S. CO2-flood operation and makes about 2,400 barrels per day from 92 producing wells and 60 injection wells using pipelined CO2 from Sheep Mountain, Colorado.

In West Texas, Apache produces about 40,000 gross barrels of oil, 60 million cubic feet of gas and 750,000 barrels of water per day from some 6,100 wells, including injectors—a fairly typical mix for the Permian. It cycles most of the produced water back into the reservoirs for enhanced recovery.

“We don’t have any ‘fantastic’ wells; we have a lot of good ones,” says Voytovich. “Most of our drilling activity in the Permian involves downspacing and enhanced-recovery optimization, exploiting known accumulations rather than exploring, so our results are both repeatable and predictable.”

While many of Apache’s units are currently on 20-acre spacing, it continues to downspace, and for a very good reason.

“The recent run-up in oil prices allowed us to try things we wouldn’t have normally undertaken, such as aggressive downspacing,” he says. “We’ve seen results from 10-acre drilling that are very similar to our recent 20-acre programs, significantly increasing our inventory of drillable locations.”

In 2008, Apache drilled 145 wells on the Texas side of the Permian. How it drills in 2009 will depend on commodity prices and service costs.

Meanwhile, the company has improved its completion techniques. “We are having a lot of success with that. Through experience, we are learning about how to efficiently access the oil that remains in place.”

The company has improved its hydraulic-fracturing technique and now uses resin-coated sand, which is helpful when producing large volumes of fluid from a well. The proppant stays in place, thus avoiding maintenance issues and downtime. Also, there is commonly more than 1,000 feet of highly compartmentalized productive interval, so the company uses multistage fracturing, typically involving three or four stages per well.

“Our competitive edge is the local expertise of our engineers, geologists and field personnel coupled with today’s technology,” he says. “We leverage that synergy. The lessons learned in our operations are portable across Apache’s large property base, where we generally have infrastructure in place. That minimizes costs for surface facilities and makes these opportunities all the more attractive.”

Although Apache is an international player, the Permian Basin provides a strong foundation for its corporate portfolio.

“It’s because of properties like those in the Permian and other domestic basins that Apache has been afforded the ability to get into the international arena,” says Voytovich. “We have a huge resource here and all the time in the world to develop it as economic conditions and corporate needs warrant.”

Five-acre spacing

Fort Worth-based Range Resources Corp. entered the Permian in the early 1990s via its acquisition of West Fuhrman-Mascho Field. The company has been drilling wells there for more than 10 years, focused in Hughes and Andrews counties and in the Conger tight-gas field in Sterling County.

“Our Sterling County field is like the Energizer Bunny,” says Mark Whitley, senior vice president of Permian and engineering technology. “It just seems to keep on going and never runs out. People have given up for dead these West Texas oil and gas fields many times during the past 50 years, but it’s amazing how many of them have had second and third lives.”

Range’s hundreds of wells drilled in the areas’ tight oil and gas sands have played a significant role in the company’s history, and it continues to acquire properties in producing formations like the San Andres and the Cisco Canyon sands. Its strategy is to buy older properties, redevelop them and drill more wells with tighter spacing.

Range is currently developing the 3,500-acre, 4,500-foot-depth Fuhrman-Mascho Field with a waterflood. While about 500 wells produce some 3,500 barrels per day there, the company has another 1,500 acres nearby, with an estimated several million barrels yet to be recovered.

“We started by drilling wells on 20-acre spacing,” says Whitley. “They looked good, so we drilled on 10-acre spacing and they looked good. We started drilling on five-acre spacing in mid-2007, and they look good, so we have gone to the (Texas) Railroad Commission to get the rules changed. Now we can develop the entire West Fuhrman unit on five-acre spacing if the economics work.”

The Permian Basin is amazing, he says, because “you would think a field discovered in the 1950s would not have that kind of development today, yet it does.”

Whitley credits the basin’s success to the fact that development wells can be drilled much faster now than in the past. Two years ago, it took six days to drill a well there. Now, it takes three.

Much of the speed can be directly attributed to polycrystalline-diamond compact (PDC) bits that improve penetration. They are different from conventional roller-bits with teeth. The PDC bits use compact diamond cutters.

“They can cut a heck of a lot of rock in a very short period of time. But it takes the right bit in the right area, operated by the right people,” he says.

“Our reduced drilling time is also from having experienced crews that know how to run the UT-Patterson rigs we use. When you cut drilling time in half, you save money. Now these fields are producing more than ever.”

Range has an adjacent field, Block 10, which had not undergone any redevelopment work in five or six years. After drilling some test wells, using the same drilling techniques, early results indicate that an extension of the Fuhrman play into Block 10 is quite feasible.

“As we go forward, we’ll continue to look for opportunities to add to our fields in this manner,” he says. “There is a tremendous amount of oil that is going to be left in the ground in all of these fields in West Texas, even with waterfloods and enhanced recovery. So by improving the recovery with downspacing or better stimulation techniques, that’s even more oil that can be produced domestically.”

Organic growth

?Tim Leach, chief executive of Concho Resources Inc., thinks “the Permian Basin is one of the most overlooked areas of opportunity in our industry, thanks to the shale fever sweeping the industry.”

Elsewhere, Midland-based Concho Resources Inc. likes to drill. Formed in 2004, the company is all about the Permian—the source of more than 90% of its assets, producing nearly 7 million BOE in 2008. Concho plans to grow organically by more than 20% per year and increase production to about 10 million barrels in 2009. The company has about 125 million barrels equivalent of reserves in the Permian Basin and an inventory of more than 2,500 drillable locations on 236,000 net acres. It drills an average 400 wells per year and operates 68% of its 3,000 wells.

“We don’t buy anything that you can’t put drilling rigs on,” says Tim Leach, chief executive. “I also think the Permian Basin is one of the most overlooked areas of opportunity in our industry, thanks to the shale fever that is sweeping the industry.”

The company plans to spend up to $500 million, funded by cash flow, with $65 oil, through 2009, which represents a continuation of its current activity. About 65% of its budget will be spent in the Yeso play on the Northwest Shelf in New Mexico that connects with the Central Basin Platform in West Texas. Concho drills down to 7,000 feet, using a 10-acre-spaced, factory-type operation, although it has some prospects at greater depths.

Another 25% of the budget will be going to its West Texas Wolfberry play. The remainder will be spent on its Bakken oil play in North Dakota. Using cash flow for drilling allows the company to reserve its balance sheet for acquisitions, such as its $560-million purchase of Henry Petroleum Co. in July 2008.

Concho has seven rigs at work in New Mexico. Six are vertical, operated rigs running in the Yeso play and a horizontal rig is working the 10,000-foot Lower Abo Wolfcamp oil play—a play initiated by Concho, Chesapeake Energy Corp., Cimarex Energy Co. and a few other independents in 2007. The company also has eight vertical rigs at work in the Wolfberry play near Midland.

?Jack Harper, Concho vice president for business development and capital markets, says the company has a good cost structure thanks to the concentration of its assets.

“We enjoy high cash margins because we are oil focused,” says Jack Harper, Concho vice president, business development and capital markets. “Our cost structure is also good, due to the concentration of our assets.”

Key to Concho’s success is its use of larger-than-normal fracture jobs, modeled after slickwater fracs normally reserved for shales.

“Jim Henry (of Henry Petroleum) pioneered the use of those fracs in the Wolfberry in 2003 and 2004,” says Leach. From Henry, Concho gained some 40,000 net acres of producing and undeveloped properties in the Permian Basin. “Within the past 10 years, new logging and fracing technologies have found oil and gas in many places that were bypassed.”

In fact, new technologies have led to new plays, says Leach. In the southern part of the Permian Basin, SandRidge Energy Inc. is drilling in the relatively new overthrust area.

“Also, the Deep Haley play, being exploited by Chesapeake and Anadarko Petroleum Corp., is another relatively new and exciting play,” says Harper. “The Third Bone Springs play in the southern portion of New Mexico that Cimarex and others are involved in is also new.”

But such success can also create challenges. Independents sometimes find themselves short of frac sand and pipe. Part of that is due to competition with deep shales, which require more pipe and sand. In recent months, some shale plays have cooled, so oilfield supplies are becoming more available for conventional plays.

“It’s not a huge problem for us,” says Leach. “We plan in advance and, as we talk to our large vendors, such as Schlumberger, BJ Services and Halliburton, we learn that they are all adding capacity here in the Permian Basin.”

Concho, along with other area producers, sees a coming challenge in 2009 of maintaining the momentum of its drilling program in an environment of low-priced commodities and high-priced services. “It seems like we are living in a period of commodity-price extremes. We planned our original budget in November at $65 oil and $6 gas, but we are committed to spending within cash flow no matter what commodity prices average for the year.”

Although Concho was formed in 2004, this is not its management’s first rodeo. The team created and sold two earlier versions. As for its Round III exit strategy, Harper says, “Our current assets lend themselves more to long-term growth.

“Also, buying and selling companies is hard on our employees. These days, they are our most important assets, so we want to keep this good group together and keep the company going.”

Inventory to spare

In the Permian, the presence of Los Angeles-based major Occidental Petroleum Corp. is ubiquitous. It’s the largest oil producer in the basin and in Texas.

Tanks loom against the sky at Range Resources’ waterflood program at West Fuhrman-Mascho Field. Some 500 wells produce about 3,500 barrels per day at the field.

Oxy has inventory to spare, with some 1.2 billion barrels of producing and undeveloped reserves here. The company has some 100 employees at its Midland office and another 900 elsewhere in the area, and assets in “every corner of the Permian and most points in between,” says Rick Callahan, operations manager.

“We have a lot of infrastructure to support our production, which is a big incentive to continue to grow our business here.”

The company’s infrastructure runs the gamut from gathering and transmission lines to gas-processing plants, serving its 200,000 BOE of Permian production per day (one-third of Oxy’s worldwide production). This represents nearly 18% of all Permian production.

To increase its Permian holdings, Oxy purchased a 50% interest in Plains Exploration & Production Co.’s assets in the basin in 2007. This past December, Oxy bought out the rest of Plains’ Permian assets.

To further boost production, Oxy joined forces with SandRidge Energy Inc. in June 2008 to develop a new, 450-million-cubic-foot-per-day gas-processing plant in Pecos County and a 160-mile pipeline, which will provide CO2 for Oxy’s enhanced-recovery projects.

Oxy plans to invest $1.1 billion in the CO2 project and will own and operate the facilities. For its part, SandRidge will process its high CO2-content gas at the facilities, market the processed sales gas, then send the separated-out CO2 to Oxy’s enhanced-production facilities. When completed, the project is expected to increase Oxy’s daily Permian production by about 50,000 barrels within five years.

?Occidental Petroleum Corp. is the largest oil producer in the Permian and in Texas overall, with a lot of infrastructure to support that production, says Rick Callahan, operations manager.

Going forward, Oxy is keeping its growth strategy flexible, reacting to changes in commodity- and oilfield-service prices, while running more than a dozen drilling rigs in the area, with a slight reduction in workover rigs.

“Our biggest single focus right now is how to keep costs down,” says Callahan. “The costs of goods and services ramped up to almost ridiculous levels due to supply and demand as the price of oil went up. How to drive those costs back down as quickly as possible is our No. 1 objective.”

Oxy also keeps on top of new technology, looking for new and better ways to implement microseismic, fracturing and logging systems.

“We have deep inventory, so our strategy is to take advantage of that when the costs come down,” says Callahan. “We’re not getting into anything that will lock us into long-term, high-cost contracts. But we have enough inventory for the next 50 or 60 years, so we are going to be here for a long time.”

Sonora Field

Gas producer HighMount Exploration & Production LLC, based in Houston, was formed in July 2007 via a $4-billion purchase of Permian Basin assets from Dominion E&P. Funded by its parent, Loews Corp., the deal included assets in West Texas’ Sonora Field in Sutton, Schleicher and Crockett counties, and properties in the Black Warrior Basin in Alabama and the Michigan Basin.

The bulk of HighMount’s Sonora daily production of more than 200 million cubic feet equivalent comes from deepwater sands of Canyon age and shallow carbonates of Strawn age. However, its production is increasingly supplemented by its nearly 600,000 net acres of Ellenberger, Atoka and Wolfcamp reservoirs.

?Legacy Reserves LP’s president and chief financial officer Steve Pruett says the company is seeing production and capital costs adjust quickly to the economic and commodity-price slowdown.

Today, the company has more than 6,000 active wells and normally adds another 200 to 600 annually. Its 40- to 20-acre-spaced Sonora wells range from 4,000 to 10,000 feet deep, averaging about 8,500 feet, giving HighMount more than 10,000 development locations left to drill.

“Sonora is one of the top 20 gas fields in the U.S., with more than 20 trillion cubic feet of original gas in place,” says Tim Parker, chief executive. “It’s our largest asset and critical to our strategy. During 2008, approximately 75% of our capital investments have been made in the Permian Basin. However, I expect that will decrease substantially in 2009.”

HighMount plans to continue to monitor oilfield costs and commodity prices and will make decisions along the way, taking a long-term view.

“We are a company that is focused on long-life domestic gas production where there are additional investment opportunities,” he says. “We believe in the long-term future of gas. It’s the right time to be looking for more gas because we believe it’s going to be advantaged from a utility perspective, going forward, by any likely climate-change or economic-policy scenario.”

HighMount has identified new zones and new horizons in Sonora that previously had been deemed uneconomic. “We are finding some things that we didn’t expect to see. There is an abundance of potential, even in a 50-year-old gas field, that is very surprising. We are actively pursuing those opportunities right now.”

A hundred little things

Legacy Reserves LP, based in Midland, is an upstream master limited partnership with roots in the Permian Basin.

? “It’s not any one thing, but a hundred little things that you have to do to get that oil out,” says Cary Brown, chairman and chief executive.

It spends about $200 million per year on purchasing oil- and gas-producing assets, invests about 25% of its cash flow into development projects, pays distributions and holds its production flat at about 8,400 BOE per day. It has 45 million BOE (70% oil) of reserves based on year-end 2007 reserves adjusted upward for its 2008 acquisitions. The Permian Basin is ideally suited to its model.

“It has been a wonderful basin for us to play in,” says Cary Brown, chairman and chief executive officer. “There is a lot of oil and gas left in the ground, so it’s a great target for us to continue buying mature, noncore properties where other operators have lost interest.”

Legacy’s engineers are production-enhancement-oriented, using workovers, stimulation and improved-lift equipment to “turn a one-barrel-per-day well into a 10-barrel-per-day well” by spending much less per barrel than drilling.

That said, Legacy is drilling in the Wolfberry, an extension of the Spraberry trend, and has seen some success, but remains a company of production and completions specialists, turning other E&Ps’ discarded assets into gold.

Legacy uses enhanced-recovery techniques and advanced-stimulation treatments, among other techniques, to coax ever more from its wells. “It’s not any one thing, but a hundred little things that you have to do to get that oil out. We think we do those hundred things better than anyone out there,” says Brown.

Robinson Rig #3 drills in Midland County for Summit Petroleum, based in Midland.

Legacy has many targets for optimization, due to its interest in 3,500 wells (75% operated), so costs are an important factor in planning.

“We are seeing production and capital costs adjust quickly,” says Steve Pruett, president and chief financial officer. “We’ve seen the peak already. About 25% of our costs go to electricity, and that has come down. Also, diesel prices have dropped from more than $5 a gallon to below $2.50, and that’s a big factor in service-company costs. We were getting fuel surcharges, and we’re not accepting those anymore.” Legacy, along with many other public E&Ps, is protected from the dangers of low prices for the next few years due to its hedging.

“In the past, E&P companies couldn’t protect themselves against dramatic declines in commodity prices,” Pruett says. “But today, the hedging markets are so liquid that most of the public E&Ps have hedged enough of their production to support their borrowing base. So we are not seeing as dramatic a reduction in capital spending as we would have seen, if not for hedging.”

Legacy has banking and hedging relationships with BNP Paribas, Bank of America, Wachovia, KeyBank, RBC Capital Markets, Bank of Nova Scotia and Fortis. “We always hedge with members of our bank group because this avoids margin calls and preserves our liquidity.”