Chesapeake Energy Corp. may ramp up more dry natural gas drilling in the Utica Shale this year, but it also is eyeing a backlog of gas and oil opportunities that stretch across the country that only need higher commodity prices to accelerate activity.

The Oklahoma City-based independent, which issued its first quarter results on Thursday, also reported an improving liquidity position after reaching a $470 million agreement with Newfield Exploration Co. to sell close to half of its acreage in Oklahoma's Meramec reservoir within the Anadarko Basin (see related story).

"Chesapeake is delivering on all four of the focus points for 2016 that we stated in February: maximizing liquidity, optimizing our portfolio, increasing cash flow and reducing debt," CEO Doug Lawler said during a conference call.

Since he came aboard in the summer of 2013, Lawler has whittled Chesapeake's enormous onshore portfolio, selling more than $10 billion of assets from a land mass mostly strung together by former CEO Aubrey McClendon. Lawler, a former Anadarko Petroleum Corp. executive, had pledged in February to scrape another $1.7 billion of properties from the lineup this year.

Chesapeake now is producing about 1.8 Bcf/d in the Marcellus Shale, said Executive Vice President Frank Patterson, who oversees the northern division. The company also has more than 1 Bcf/d of gas that is available to ramp up rather quickly, including about 350 MMcf/d that is deliberately shut-in, 200 MMcf/d from wells that need "minor repairs" and about 450 MMcf/d from nearly 100 wells that are "sitting back," waiting to be completed.

Bringing on more gas in the Marcellus is a given if prices cooperate.

"We have gas that we can manage with no decline, basically, which is a great opportunity in the Marcellus," Patterson said. Chesapeake had no gas volumes that it was "counting on" from the proposed Constitution Pipeline, which is gasping for air after being denied a key water quality permit by New York regulators last month (see Shale DailyApril 29). Chesapeake also had a "small amount" of gas that it had planned to transport through the Northeast Energy Direct pipeline project, which was canceled last month (see Daily GPIApril 21). "Of course, that is apparently gone now," Patterson said. "But we have the opportunity to manage this field nicely with no decline in production and very little capital."

Chesapeake is not putting a lot of capital into the Marcellus "because it doesn't need capital," Patterson said. "As far as monies being spent in the field, it is going to the Utica...and we are going to be putting on additional Utica dry wells this year and next year and growing some additional Utica dry wells going forward."

Marcellus continues to be a "core asset," even though it has been considered for sale in the past. "There are parts of the Marcellus that might not be core, and we would consider that with the right price," Patterson said. However, the "Utica, we're pretty happy with our position."

Getting the gas out of Appalachia "is a key issue, and we'll continue to monitor that and be ready to invest there when the opportunity presents itself," Lawler said.

In another gassy asset, the Haynesville Shale, Chesapeake brought on its first two 10,000-foot wells, both coming on at 22 MMcf/d and nearly 8,000 psi, said Jason Pigott, who runs the southern operations.

"We expect to get the cost down on these wells to about $8.5 million," Pigott said. "What's great about that for me is that a couple of years ago when I came into the role the teams were making 4,500-foot laterals at $8.5 million a well. So we've seen wells that are twice as productive at the same cost we were two years ago, so it's been a huge efficiency gain for us." Chesapeake plans to keep running three rigs there this year and continue to pull down its drilled but uncompleted backlog. "We had 31 wells in inventory at the beginning of the year and expect to be at eight wells by the end of the year."

Chesapeake is earning "close to 20% returns at the strip," Pigott said. "It's hard to explain how impactful these long laterals have been to that play out there, because we're...seeing no degradation in performance with these 10,000-foot wells..."

In addition, Chesapeake has more upside in the extended Haynesville after recently completing its first 7,500-foot lateral Bossier well in the extended Haynesville, which is flowing at around 17 MMcf/d at 7,300 psi.

As to where money could be directed if commodity prices move higher? Pick a play, said Pigott.

In the Midcontinent, where the company has an estimated 1.5 million net acres, there are "really strong economics. And then our Eagle Ford Shale has experienced a renaissance as well with the longer laterals...Preferentially if we're spending more dollars, those plays always look really strong." In the Eagle Ford this year, plans are to drill 9,800-foot laterals, "which is nearly double what they were a couple of years ago."

Returns today in the Eagle Ford "are about the same as when oil was $80," Pigott said. "It's significant how much of a change the Eagle Ford team has made there. We had wells coming on a year ago at 500 b/d. Our latest wells are coming on close to that 1,000 b/d. So we've had just a huge transformation in the Eagle Ford team over this first quarter here that for me, again, if I'm fighting for capital, that's the area I want to send it first."

The company's cash costs "continue to decline, and we remain sharply focused on improving our margins through continued progress with our midstream and downstream partners," Lawler said. "As a result, we have recognized incremental improvements in both our production expense and our total gathering, processing and transportation expenses and revised our 2016 guidance accordingly."

Production, adjusted for divestitures, averaged 672,400 boe/d in the quarter, up 1% from a year ago. Chesapeake produced 276 Bcf of gas, 95,700 bbl of oil and 70,700 bbl natural gas liquids. Realized gas prices averaged $2.29/Mcf in 1Q2016 from $2.35 in 4Q2015 and $3.67 in 1Q2015.

Chesapeake, which at one time had more rigs working in the U.S. onshore than any company, operated only eight rigs during the first three months of this year, from 54 a year ago and 14 in the fourth quarter. In the latest period, 57 gross wells were completed, down from 261 year/year and 85 in 4Q2015. Wells spud (gross) declined to 41 from 244 a year ago and 66 in 4Q2015, while connected wells fell to 80 from 262 in 1Q2015 and 100 in 4Q2015.

Improved efficiencies sent drilling and completion costs to $281 million from $1.3 billion a year ago and from $405 million in the fourth quarter.

Net losses totaled $964 million (minus $1.44/share) in 1Q2016, compared with a year-ago net loss of $3.78 billion (minus $5.72). Chesapeake said the "primary driver" to the quarterly loss was the result of an $853 million price-related impairment on the carrying value of oil and natural gas properties. Adjusting for the one-time charges, the net loss was $120 million (minus 10 cents/share), versus year-ago profits of $42 million (11 cents).

Revenues declined by 39%, partially offset by improvements to production expenses and general/administrative expenses. Average production expenses fell by 31% year/year and 7% sequentially to $3.36/boe in 1Q2016. G&A expenses were down by 23% year/year and 3% sequentially to 79 cents/boe. Total capital investments were about one-third lower than a year ago at $365 million.

Chesapeake continues "looking at all options to ensure liquidity," and continued to be in "close alignment" with midstream partners to reduce gas gathering, processing and transportation agreements, CFO Nick Dell'Osso said.

Chesapeake's debt, closely followed by the investment community, saw its principal balance at the end of March fall slightly to $9.4 billion, from $9.7 billion at the end of 2015 and $11.5 billion at the end of March 2015. In April, Chesapeake amended its $4.0 billion facility, which matures in 2019, and agreed to pledge additional assets as collateral (see Shale DailyApril 11).

The company also reiterated that it is targeting asset sales of $1.2-1.7 billion of total gross proceeds from asset divestitures by year-end, with most expected to be completed by the end of September. For the expected $950 million in net proceeds currently closed or signed, the net reduction to production is projected to be 35,000 boe/d, 60% weighted to gas.

Since February, Chesapeake has layered on additional hedges for 2016 to help increase cash flow. It has about 476 Bcf of remaining 2016 gas production hedged at $2.71/Mcf and 18.2 million bbl of remaining 2016 oil production hedged at $46.32/bbl, which represents 64% of gas production and 69% of oil output from 2Q2016 through 4Q2016.