DENVER—Two major producers in Western basins are focusing on bargain prices for services, along with drilling and completion efficiencies, to help wade through a time of depressed oil prices.

Chesapeake Energy Corp.’s (CHK) Jim Govenlock and WPX Energy Inc.’s (WPX) Clay Gaspar recently talked about their companies’ involvement in the south Powder River and San Juan basins, respectively. The two spoke at Platt’s 9th Annual Rockies Oil & Gas Conference held at the end of April.

Govenlock, Chesapeake’s vice president of the Rockies business unit, discussed how the company relaunched its program in the southern Powder River Basin (SPRB)—one of the “toughest areas” for drilling anywhere. In 2012, Chesapeake halted a program that was “not delivering value” and made a conscious effort to reduce costs and innovate with technology to succeed in the complex drilling environment.

He credited the company’s completions team for achieving a 25% per foot drilling cost reduction after being challenged to transform the program.

Like most E&Ps, Chesapeake has reduced its rig program and capex spend for 2015 overall. In January its outlook was for spending of $4- to $4.5 billion with a 35 to 45 rig program; in March it had pared that to 25 to 35 rigs and $3.5- to $4 billion capex. Cumulative net production for the year was expected to fall from about 240 MMboe to 231 to 236 MMboe.

The SPRB’s stacked pay offers a diverse portfolio of gas, oil and NGL, with a mixture of conventional and resource play targets. These include the Mowry, the Frontier/Turner, the Niobrara, the Shannon, Sussex, Parkman and Teapot formations. The company figures the stacked pay multiplies its opportunities from 372,000 net acres to 507,000. It currently has 187 wells drilled in the play with 160 producing, and 27 in inventory, and more than 3,000 undrilled locations. The current production mix is about 41% oil, 41% gas, with the rest NGL. Its leasehold is mainly in Converse County, and to a lesser extent in Niobrara and Natrona counties, Wyo.

Govenlock called the play’s potential “tremendous” and said the company estimates more than 2 billion boe of unrisked recoverable gross resource. Chesapeake has been deciphering the complex geology with the help of 3-D seismic and advanced processing techniques.

The company doubled down on its working interests in the play, said Govenlock, when it and RKI Exploration &Production LLC exchanged properties in the basin last summer. RKI was paid $450 million in cash plus 136,000 net acres, including ownership interests in 68 RKI-operated wells, in exchange for 204,000 net acres, including ownership interests in 191 Chesapeake operated wells.

Now, it is increasing the value of its holdings through capital efficiencies, improved stimulations, longer laterals, full-pad development and less surface disturbance. Drilling advances include a 20% increase in longer laterals, with a 33% cost reduction per foot. It is doing 40% more stages per well, 75% more perfs, and pumping 50% more sand, for just a 10% increase in costs. Overall it has shaved costs per well from $12.2 million in 2012 to $9.2 million in 2015. The drilled price per foot is down 44% from 2012, and the average lateral length is up 31%, to 5,858 feet, with an average 21 stages.

Gross daily production is now about 28,000 boe but topped 33,000 or so earlier this year. Overall, production has risen about 200% since first-quarter 2013. Even dropping from three to four rigs to one to two for the remainder of 2015, and from one frack crew to a half frack crew, the company still looks for 50% year-over-year production growth.

Farther south in the Rockies, WPX is hard at work on its assets in the San Juan Basin, with the benefit of cash from its recent asset sales in the Marcellus and its successful hedging program. These strategies have given the company flexibility in the downturn.

Clay Gaspar, senior vice president of operations and resource development, said the company was aiming to build the “premier Western energy producer.” Its focus is North Dakota’s Williston Basin, Colorado’s Piceance Basin and the San Juan Basin in northern New Mexico. He noted the company had received $600 million in cash proceeds in first-quarter 2015 through the sale of its interest in Apco Oil & Gas International, an Argentine company, and assets in the Marcellus Shale.

WPX has been steadily growing oil production, achieving a current 32,000 bbl/d, up 25% in fourth-quarter 2014 over the previous quarter. San Juan Basin Gallup production is up nearly 400% year over year.

As for that healthy hedge position, it includes 78% of the company’s natural gas, at an average price of $4.09 per MMBtu, and 68% of its oil production, at an average price of $94.88 per barrel.

Gaspar said first-quarter 2015 results were “exceeding expectations.” It has driven down Williston well costs to less than $9 million and San Juan Gallup wells to about $4 million. To capture more oil, it is shifting capital from the Piceance Mancos/Niobrara program to the San Juan Gallup play. The company expected equivalent production to exceed its guidance for the period.

WPX will run one rig in 2015 in the Williston, where Gaspar said it was pursuing “optimal stimulations.” He focused more on the San Juan, where he said the company would average 1.5 rigs in the oil window and .8 rigs in the gas window, while expanding its gathering system. Its spud-to-spud times have fallen to 14 days from 30, more than doubling oil production per day to 12,170 bbl.

In the Piceance, the company has reduced lifting costs to 23 cents/Mcfe. Gaspar said WPX has agreed to a multiyear carry of some 400 gross wells in the Trail Ridge area, for $210 million in value. Additionally, he noted a production sale to an MLP for $355 million. This year the company will average 2.5 rigs in the Valley, Ryan Gulch and Trail Ridge areas, and .5 rigs in the Niobrara/Mancos areas.

Gaspar also highlighted the takeaway options to what he called “premier markets” from the Williston and the San Juan basins. He said firm sales commitments in the latter were expected to provide wellhead netbacks at WTI less $8 to $10 for second-half 2015 and full-year 2016.

Meanwhile, Dave Pursell, another conference speaker, is predicting $85 oil by mid-2016. He is the managing director and head of securities for Tudor Pickering Holt & Co.

Oil prices climbed past $60 in early May, to a 2015 peak, providing some optimism about his prediction.

Pursell also noted that if “everyone dives back in” a period of hyperinflation could follow.

Contact the author, Susan Klann, at sklann@hartenergy.com.