Chesapeake Energy Corp. is making solid headway in reducing its well costs, with each specific play scrutinized by one team to improve across-the-board metrics, CEO Doug Lawler said Wednesday.
After coming aboard last summer, Lawler set to work to repair the balance sheet and reduce overall costs -- in particular, well expenses that have stymied exploration and production (E&P) operators in variable unconventional basins. Today, one team is assigned to one play, which has resulted in higher estimated ultimate recoveries (EUR) and optimized capital spending.
The changes have resulted in unexpected dividends in, for instance, the long-neglected Haynesville Shale, where the company first raised a rig in 2008 (see Daily GPI, March 26, 2008). Chesapeake is one of the few big independents that has the confidence to revive the dusty program -- only better this time and at less of a cost, said Lawler.
Chesapeake disclosed in early February that it was restarting its Haynesville project (see Shale Daily, Feb. 6). The company has been criticized by some analysts because even though gas prices are higher today, there's a higher margin in oil. But that's just on paper. It's not what Chesapeake expects for the future, and it's not what it is seeing on the ground today.
Haynesville is about as deserving for funds as any other play, according to the CEO.
"On breakeven gas prices, the Haynesville is one of the most attractive" as far as metrics. Because the field's team has been able to reduce all of the well costs, it's made it a must play for the portfolio.
"When you can crush $1-2 million from well costs, that's a huge driver," Lawler said. "We have new strategies for the operations to increase EURs, capitalize on a supply chain...It drives that breakeven price down considerably...
As U.S. gas prices fell over the past few years and operators pulled their money, "what took place in the Haynesville was not necessarily a positive thing" he said.
"Our focus in the Haynesville is almost surgical and precise, and we know exactly what we need to do to drive the cost down, recognizing it as we speak. The competitiveness, in terms of not only our portfolio, but what it can do for us, in the portfolio. There's also longer-term obligations. We have very, very strong assets that are capable of providing gas to the domestic market, but more important, to the global market," as liquefied natural gas export terminals are built nearby along the Gulf Coast.
"We think the opportunity there, rather than looking at what the breakeven price is, I prefer to focus on the fact that the work that's being done to drive the cost [down] is an immediate value to the company."
Senior Vice President (SVP) Jason Pigott, who directs the Southern Division's operations, said optimization is key in the Haynesville. The E&P now is drilling cross laterals to complete more feet per well and maximizing the length of wells in the play. It's improved overall well economics.
Most of the Haynesville wells today are spaced on 160 acres, but "the advantage will come later with pad drilling." Chesapeake plans to take it slowly, watching some of its drilling peers to see what they've done with downspacing.
"The team right now is focused on rock quality, numerical stimulations and well designs," Piggot said. A "rigorous" program is determining infill sizes and pads.
Chris Doyle, SVP of the Northern Division, said Chesapeake also is seeing some "high level color" from the Utica Shale. Because of the optimization gains, "on well costs, we're doing things out there that nobody else can do."
The formerly double-digit million dollar wells have been reduced in the Utica to "the low $7s," he said. "Most recently, we had some sub eight-day wells," that allowed production to ramp up sooner and more efficiently.
"We're not only attacking the cost side, but the EUR side," Doyle said. "We are looking for completion efficiencies, tighter cluster spacing...What we are seeing across the play, we are seeing many of the same things across the portfolio."
There isn't much anybody can do about Mother Nature, however. Freezing weather in the Midcontinent, flooding in South Texas and a natural gas liquids (NGL) processing plant in Appalachia dug into Chesapeake volumes in the final three months of 2013.
Production during 4Q2013 actually was 2% more than in the year-ago period, but it fell 1% sequentially on the bad weather.
Pigott said the southern operations were impacted equally on a net boe basis because of freezing weather in the Midcontinent, an oil-producing area for Chesapeake.
"The challenge of snow and ice made it difficult to pick up oil loads," Pigott said. "In South Texas, we had a significant rain event that caused some flooding, washed out some roads, and prevented some of the wells coming on...Those major events equally impacted us."
In Appalachia, NGL processing was down because the Natrium Processing and Fractionation Facility in West Virginia was out of commission, said Doyle. Natrium, which began operations last summer, returned to service in late January after a fire in September shuttered the facility (see Shale Daily, Oct. 18, 2013; Aug. 26, 2013). Chesapeake has commitments to supply the Appalachia-to-Texas Express (Atex) pipeline, which it was unable to meet (see Shale Daily, Dec. 5, 2013).
The Natrium volumes were backed up, but they weren't lost, Doyle noted, but Chesapeake only recently was able to process gas at the facility.
The Utica Shale operations also have been impacted by some rough weather in January and February, "which isn't surprising given the weather," said Doyle.