Chesapeake Energy Corp. is ramping down activity across its onshore footprint, dropping most of its rigs by the middle of summer as it waits out the industry doldrums. The Marcellus Shale still suffers from takeaway issues, and the company has doubled its shut-ins in the play to 500 MMcf/d gross.

While the management team waits out a recovery, it is focused on efficiencies by drilling longer laterals, testing new stimulation techniques and horizons, and keeping an eye on base operations.

To do that, it’s relying on a much smaller footprint. Chesapeake began 2015 running around 70 rigs in U.S. onshore, including a few spud rigs, and it averaged 54 overall between January and March. Today it’s running 26 rigs. During the third quarter, the rig count is set to drop to 14.

CEO Doug Lawler told analysts during a conference call Wednesday that the “principal reduction in the capital program is related to activity,” but with efficiency gains now being recognized, “we also expect our capital to improve going forward…” In addition, working with vendors and oilfield contractors is something the company plans to further optimize this year.

CFO Nick Del’Osso, who shared a microphone with the rest of the management team, noted that the pullback in activity has led to a “dramatic reduction in our capital spending rate…Our capital spending on drilling and completions alone in January was approximately $490 million. By the time we get to June, we are projecting around $200 million in drilling and completion capital.

“So while we are doing amazing things in the fields with our assets…, we still believe the prudent approach in the near term is to reduce activity and preserve liquidity and flexibility in the current price environment.”

Senior Vice President (SVP) Chris Doyle, who is in charge of the northern division, highlighted improvements to drilling techniques in the Utica and Marcellus, but they can’t overcome basin pricing. The Utica saw 10% sequential production growth on five rigs and 4.5 fracture (frack) crews. However, by the middle of this summer, the rig count is to be cut to two with less than three crews, to “approximate the level of activity to maintain our lease position,” he said.

Chesapeake early this year had said it would curtail 250 MMcf/d gross from the Marcellus through this year on weak in-basin gas pricing (see Shale Daily, Feb. 25). Curtailments now total about 500 MMcf/d gross.

“Given our ability to rapidly respond to potential market strength, we quickly and prudently reduced activity to one drilling rig and one frack crew to maintain our lease position. We plan to maintain production at that reduced activity, but we stand ready to respond to what the market tells us, regardless of production impacts.”

The focus in the Marcellus this year is to “drive the most value…as efficiently as possible,” Doyle said. “The team is rethinking, re-examining, and going back to test limits of our lower Marcellus position as well as testing the upper Marcellus. While some of this activity has been deferred in 2015, we have ample tests coming our way to validate what this asset will deliver in the coming decades, even with minimal capital investment.”

Del’Osso said overall gas differentials show improvements in 2016, primarily because of “improvements in the forward curve for basis at our sales points.” The company also is working closely with pipeline giant Williams “on mutually beneficial opportunities to improve our gathering costs,” which should “contribute to potential opportunities for improvements in our rates.”

However, finding more takeaway in Appalachia isn’t easy, Del’Osso said. “Those opportunities haven’t proven yet to be actionable in a way that we see value added…If opportunities present themselves to add to that, we would do so. Recently, there have not been any that have been value-accretive.”

Reduced activity but better results is how SVP Jason Pigott, who runs the southern division, described improvements in the onshore. For instance, in the Haynesville Shale, estimated ultimate recoveries (EUR) led to an increase in natural gas-weighted output by 4% year/year. The play straddles the border between East Texas and northern Louisiana.

“Today we can drill wells with 7,500-foot laterals for less cost than we could drill wells with 4,500-foot laterals just a short time ago,” Pigott said of the Haynesville. The first two 7,500 foot lateral tests came online in April, with initial flowback averaging more than 17 MMcf/d. “Successful testing of our enhanced completion designs has opened up development in areas that were traditionally written off in both the Haynesville and the Bossier,” he noted. Among other things, Chesapeake improved its costs in the basin by 42% from a year ago.

“We now have our first 10,000-foot wells on the rig schedule, with completions planned for October, and we fully expect to continue this trend,” Pigott told analysts.

A “traditional contour map” may indicate to some that the Haynesville jobs were in an uneconomic area with 6-8 Bcf/d contour laterals, said Pigott. However, wells drilled so far “have shattered the limitations typically placed on Haynesville development.” The sister Bossier Sands also is contributing, with production up almost 4 MMcf/d on average from two tests. By itself, Bossier holds a lot of future potential.

There’s another big potential for the formation from refracking old wells in the Haynesville that were drilled at the beginning of the unconventional boom. Chesapeake was the first company to build significant operations in the play.

Chesapeake’s total production in 1Q2015 averaged 686,000 boe/d, a 14% increase year/year. Gas production year/year increased to 264 Bcf from 260 Bcf, while oil output climbed to 11,000 bbl from about 10,000. Natural gas liquids (NGL) production fell to 6,800 b/d from 7,600 b/d a year ago.

Net losses in the first quarter totaled $3.74 billion (minus $5.72/share), versus year-ago profits of $466 million (57 cents). Adjusted for one-time items, including the decline in commodity prices and impairments on assets, profits were $42 million (11 cents/share), versus $405 million (59 cents). Total revenue plunged to $2.47 billion from $5.05 billion. Natural gas, oil and liquids revenues fell year/year to $1.09 billion from $1.77 billion, while marketing and gathering plunged to $1.68 billion from $3.02 billion.

Operating cash flow plunged in the first quarter to $910 million from $1.61 billion in the year-ago period. Operating cash in 4Q2014 totaled $829 million.The total income loss from operations was $5.04 billion, versus a profit in the year-ago quarter of $733 million.

Sales fell year/year to $1.09 billion from $1.77 billion. The biggest hit was to NGL sales at $48 million versus $221 million. Gas sales also plunged to $425 million from $1.01 billion, while oil sales declined to $451 million from $922 million. The average gas price in 1Q2015 was $1.61/Mcf versus $3.27 in 1Q2014. The average oil sales price declined to $41.16/bbl from $93.60, while NGL prices fell to $6.99/bbl from $29.23.