Hydrocarbon dichotomy

Oil jumped by a record-breaking 17.8 percent from January to November of last year, according to the state Oil Conservation Division. Once full tallies are in for December, last year’s output is expected to surpass 80 million barrels for the first time since 1978.

At the other extreme, natural gas fell by 9.5 percent from January to November, reflecting the largest single-year drop since production began trending downward in 2002. Annual output is now at its lowest level in more than 20 years.

	Volatile revenue sources Even small shifts in oil, gas prices affect N.M. Page 7

It’s been the same story every year since the recession ended in 2009: A historic revival of New Mexico’s Permian Basin Oil Patch thanks to consistently high crude prices and modern drilling techniques, offset by a rapid decline in the natural gas-rich San Juan Basin because of a surge in output elsewhere in the country that has pushed prices to 10-year lows.

“In our neck of the woods, activity is excellent,” said Raye Miller, president of Regeneration Energy Corp. in Artesia. “But the San Juan Basin is a different world.”

Crude’s bounce back

Those trends are expected to continue through 2013 and beyond, since natural-gas prices remain stubbornly depressed, while crude prices are still robust.

That’s been the case since 2010, when oil and gas prices moved in opposite directions, pushing the Permian Basin into a boom cycle, and the San Juan Basin into long-term recession.

A Patterson Drilling Co. rig drills for natural gas on the outskirts of Artesia. The Navajo Refinery is seen in the background. (JOURNAL FILE)

Both basins were hit hard when the economy collapsed in 2008. Oil prices plummeted from a historic high of $147 per barrel to below $35 by 2009. Dry natural gas fell from about $6 per 1000 cubic feet or Mcf to about $3 per Mcf.

But by late 2010, crude had rebounded to about $80 per barrel, and to more than $100 in early 2012. In contrast, dry natural gas fell to as low as $2 per Mcf, and even now remains at about $3.70, said George Sharpe, investment manager with Merrion Oil and Gas Corp. in Farmington.

“Prices need to climb to at least $5 (per Mcf) to stimulate drilling and see some recovery here,” Sharpe said. “We’re not doing anything in the San Juan Basin now.”

Prices remain low because of the shale-gas boom in the Northeast, Midwest and South, which has flooded the market with natural gas, plus relatively mild winters in recent years. In addition, San Juan Basin producers earn less than companies in other places because gas there has few liquids, such as propane and butane, which can earn a $1.00 to $1.50 premium on top of payments for dry natural gas.

San Juan woes

Consequently, San Juan production has plummeted, largely reversing gains achieved during the region’s boom period in the 1990s. San Juan output peaked in 2001 at 1.684 billion cubic feet of natural gas, but by 2011, it had fallen 25 percent to 1.263 billion cubic feet.

The natural-gas rig count has dropped from nearly 40 prior to the recession to just six today.

“There’s just nothing economic at these prices,” Sharpe said. “The rigs that are running are serving big companies like ConocoPhillips and XTO Energy to keep some level of infrastructure in place. They’re just drilling the cream of the crop to keep things going.”

Aztec Well Servicing in Farmington, which has 13 rigs, is only operating four now in the San Juan Basin, said Executive Vice President Jason Sandel.

“Other companies that used to work here are either long gone or have folded up shop,” Sandel said.

Some investors are optimistic that the Mancos Shale, a hard-rock layer rich in liquid fuels that rests in between the San Juan’s softer, sandstone-based dry gas beds, could generate an oil boom in the area. But producers say exploratory drilling is still too new to project production potential.

Mancos Shale under study

“We’ll need at least another year of production data to confirm if that play will be viable,” said Tom Mullins, co-owner of Synergy Operating LLC in Farmington. “For now, we’re still waiting for natural-gas prices to improve, and unfortunately, it seems like it’s going to be a long wait.”

At the other end of the state, the Oil Patch is seeing its best days since the early 1970s. Notwithstanding some ups and downs, New Mexico’s oil output had fairly steadily declined for nearly four decades, from a peak of 128.15 million barrels in 1970 to a record low of 59.2 million in 2007.

Output remained flat during the recession, but after prices spiked again in 2010, production began an upward trend that has gained momentum each year since. With an estimated 80 million-plus barrels in 2012, output has climbed 35 percent in the past five years.

High prices have made expensive, modern drilling techniques profitable for producers. That includes hydraulic fracturing, where operators inject water laden with sand and chemicals at high pressure into wells to bust open layers of hard shale rock, followed by horizontal drilling to enter sideways into underground pools of hydrocarbons that eluded producers before.

Many operators have also replaced old, three-wheel tricone digging bits with polycrystalline diamond drill bits. The newer bits use cutters to scrape, gouge and bust up rock formations, making the process faster and more efficient.

Those techniques, which are pumping a lot more crude, plus today’s high oil prices, are fueling the boom.

Billions invested

Large companies have invested billions of dollars in new wells and operations. Devon Energy Corp. of Oklahoma, for example, increased its rig count in New Mexico from three in 2010 to ten today. It’s now drilling 100 new wells a year, up from 40 before.

“Between 2010 and 2012, we spent about $1.1 billion in southeastern New Mexico,” said spokeswoman Cindy Allen. “Our New Mexico wells are delivering some of our best economics in the Permian Basin.”

Apache Corp., the top Permian Basin operator in West Texas and New Mexico, invested nearly $4 billion on both sides of the border from 2010 to 2012, according to a recent company report.

Roughnecks work on a Mack Energy Corp. drilling rig near Hobbs in 2010. High prices have made expensive, modern drilling techniques profitable for producers. (journal file)

High returns make new wells profitable even for small companies like Regeneration Energy, which employs only four people, said Raye Miller. That firm invested $24 million to drill three wells since the company formed in 2011, and it will invest about $14 million in two more wells this year.

“It’s very expensive, especially for a small company like ours, but at current prices, if the resources we bring up are enough, we still make a profit,” Miller said.

‘Drilling tons of wells’

The surge in oil, as well as Permian natural gas – which, unlike in the San Juan, is rich in liquids – has created a processing and pipeline bottleneck, said Greg K. Smith, senior vice president for Permian and Mid-continent business units at DCP Midstream, the country’s second-largest natural-gas gatherer and processor.

“Things have really busted loose,” Smith said. “Producers are drilling tons of wells and doing things faster than we can get pipeline capacity built. We’re trying to catch up.”

DCP is adding hundreds of miles of new pipelines. It’s also expanding gas-processing plants to separate dry gas from liquids, with 90 million cubic feet of capacity added at New Mexico-based plants in 2012. But Smith said it’s not enough.

“We have another processing plant with 75 million cubic feet of capacity under construction now, but we still have to build more,” Smith said. “We have a number of other projects planned for West Texas and southeast New Mexico this year.”