Weathering a dramatic downdraft in crude oil prices is no easy matter. When these downdrafts come, they typically come sharply, sometimes savagely. And few have been more disruptive than the recent plunge in West Texas Intermediate (WTI), which dropped some 25% from a mid-June price of about $106/bbl to a recent range of $75 to $80/bbl.

In an industry renowned for having to ride out such storms, some E&Ps are better equipped than others to find shelter. For these, the next leg of the journey will likely entail fewer forced tack changes. And for a very few, the turmoil of the past several months may have given rise to an opportunity—perhaps an acquisition—that wouldn’t have happened in a calmer climate.

What are the qualities needed to survive—perhaps even prosper—despite a darkening commodity price backdrop?

Obviously, E&Ps with higher levels of hedging at attractive prices have better protection against commodity price weakness. Balance sheet strength is another vital issue. This includes a focus on overall debt levels, timing of maturities and access to greater liquidity. Furthermore, what are the prospects for asset sales, or dropdowns of assets to a subsidiary? Is financing available for drilling to hold acreage considered strategic? How quickly do wells pay out?

These and other factors may to a large extent determine the degree to which E&Ps engage in “scenario planning.” This process involves projecting levels of capex or, for example, the number of rigs running in a play, at higher or lower levels, depending on the unfolding strength or weakness of commodity prices. Capex and cash flow can thus track each other within targeted norms, helping companies avoid an unanticipated level of “outspend.”

Hedging and more

Newfield Exploration Co. offers an example of such flexibility in setting capex levels—but within a relatively tight framework by virtue of its having established an unusually rigorous hedging program.

“Newfield is the best-hedged company within our coverage universe,” said Dave Kistler, managing director and co-head of E&P research at Simmons & Co. International, adding the company has “distinguished themselves versus their peers as a result of their proactive risk management.”

Under Newfield’s hedging program, 81% of the crude oil production Simmons projected for the company in 2014 is hedged with floors of about $90/bbl, while 78% of projected natural gas is hedged with an average realized price of $4.10/Mcf. For 2016, some 60% of estimated crude production is also hedged with floors of about $90/bbl.

“While we readily acknowledge that hedges don’t necessarily insulate the equity from commodity-related pullbacks, it does insure cash flows and the ability to execute upon the company’s three-year plan,” Kistler said. He noted that every $10/bbl decline in crude oil prices impacts Newfield’s cash flow by $65 million per year—an amount considered manageable.

Newfield’s recent capex projections have been based on a $90/bbl price assumption under its three-year plan. For 2015, Newfield has guided to a capex level of $1.6- to $1.8 billion, although final approval of its spending is not expected until February.

In the meantime, the company is running differing scenarios with oil prices ranging from the mid-$70s to the mid-$90s, CEO Lee Boothby told investors on the third-quarter earnings call. However, with the backing of its strong hedge book—the value of which Boothby cited as nearly $500 million—the company does not expect to stray far from its prior plans.

“Our three-year plan outlined expected annual investments of $1.6- to $1.8 billion in the 2015-2016 time horizon,” Boothby said. “These are still appropriate bookends today, with an $80/bbl oil price likely to shift investment levels towards the lower end of this range. At the low end of our investment range, I’m confident we can still deliver strong production growth in 2015.”

Even as analysts trim 2015 capex assumptions toward the low end of guidance, Newfield’s oil volume growth is still projected to show healthy gains. For example, although Simmons cut by 5% its overall 2015 production estimate for Newfield, the company’s crude oil component is still expected to increase by 20.2% over its recently upgraded full-year guidance for 2014.

Investment continues to be focused on liquids-rich plays, with the majority of capex earmarked for the Anadarko Basin, where Newfield is increasing production from its Stack and Scoop plays, as well as its recently disclosed Springer Shale play. Natural gas assets are held by production and are described by Boothby as “a great option for future investment.”

The planned divestiture of its Chinese assets is another step aimed at bolstering Newfield’s ability to move forward with its domestic drilling plans in an uncertain commodity price environment, although the exact timing of a sale is unclear. Street estimates are for proceeds of around $500 million or more.

Production growth at steady capex

For Devon Energy Corp., a 10% jump in its stock on the day of its third-quarter earnings release resulted from several factors.

Chief among these was Devon reiterating guidance for oil production to grow by 20% to 25% in 2015—but with the critical accompanying news that 2015 capex was projected to remain at a “similar” level to 2014, i.e., requiring no increase. In addition, Devon disclosed a continued strong hedging program, a positive operations update, and the prospect of future financing sources being generated by “dropdowns” of midstream assets into its EnLink Midstream subsidiary.

Devon set the stage for potential outperformance by beating third-quarter oil expectations and guiding full-year 2014 production 3% higher, from 11% growth to 14%, with no increase in capex. This step was one that “should turn the skeptics into believers” as far as Devon’s progress in “reinventing” itself over the past year, said Sameer Uplenchwar, senior analyst with Global Hunter Securities.

Like Newfield, Devon has protected a good portion of its projected cash flows through an active hedging program. For full-year 2015, through a program of swaps and collars, the company has more than 50% of its expected oil production hedged at an average floor price of about $91/bbl. For natural gas, it has around 30% of its expected production hedged at an average floor price of about $4.20/Mcf.

Partially shielded from recent commodity weakness, Devon is pushing ahead on several important fronts.

In the Permian, for example, it has achieved “outstanding performance” in its Bone Spring horizontal program, where 30-day IP rates have increased from 575 bbl/d to more than 750 bbl/d. Also, Devon’s first Wolfcamp B test was successful, with a 24-hour IP of 1,500 boe/d and an EUR of 600,000 boe.

In its Cana-Woodford play in the Anadarko Basin, Devon has also seen a 30% increase in 30-day IPs, from 920 boe/d to 1,200 boe/d, while costs are said to have increased by less than 3%. Devon plans to accelerate drilling in the play to more than 10 rigs by first-quarter 2015 (including nonoperated activity), up from three operated rigs at the end of the third quarter.

Potential type curve improvements are also considered likely in the Eagle Ford play, which is Devon’s highest-margin asset. Development is currently focused on the lower Eagle Ford, but the company has also identified potential in the upper Eagle Ford. The latter is viewed as prospective across the majority of its 82,000 net acres in DeWitt and Lavaca counties.

Financing options are enhanced by Devon’s midstream operations, which in the Eagle Ford include its newly constructed Victoria Express Pipeline and, in its Canadian heavy oil operations, its Access Pipeline expansion project. These are likely candidates for dropdowns into EnLink Midstream, which analyst Uplenchwar described as a “funding vehicle” for Devon.

“We believe that once cash flow potential is determined for both of these assets, Devon will drop them down into its EnLink Midstream as early as 2015,” Uplenchwar said.

Putting it all together, “we feel very, very good about the portfolio and the opportunity set that we’ve created for the next several years,” Devon CEO John Richels said on the company’s recent earnings call.

“We’ve got over 50% of our oil production hedged at a price of $91/bbl, so we’ve got a lot of price protection from that point of view,” he observed. “And, with the additional financial levers that we have with the dropdowns that we’re talking about doing, we’ve put ourselves into a very good position even if prices stay a little soft in the near term.

“As we get into 2015 and we start executing the 2015 program, we’re really more interested in what oil prices are toward the end of 2015 and into 2016-2017, because that’s when that production comes on.”

The long view

For Anadarko Petroleum Corp., the third quarter provided yet another example of the company’s ability to monetize assets that it had successfully developed and recoup a major portion of its investment. This strategy has been key in the company’s ability to maintain high levels of liquidity as it pursues an exploration program that is essentially long-term in nature.

As an exploration-oriented company used to undertaking projects on a five- to 10-year development cycle, Anadarko is perhaps understandably less focused than are most E&Ps on the near-term price of crude. Growing within cash flow, plus with cash from asset sales, has been a consistent theme for the company. Having ample liquidity—some $8.3 billion in cash and an undrawn credit facility of $5 billion at the end of last September—helps to offset commodity price fluctuations.

“We believe we are one of only a few companies positioned to manage the near-term uncertainty in commodity prices while achieving our long-term objectives with efficient capital allocation,” said CEO Al Walker on the company’s third-quarter call.

During the quarter, Anadarko monetized more than $2.2 billion in assets, emphasizing its “ongoing commitment to enhance and accelerate value through portfolio management.” Asset sales included a previously announced divestment of its China subsidiary for some $1.1 billion. Proceeds of similar size—but not previously signaled—came from the $500 million sale of an 18.67% nonoperated interest in its deepwater Vito development, as well as the signing of a carried-interest, joint-venture agreement in the Eaglebine valued at more than $440 million. Other transactions generated $200 million-plus in proceeds.

Diversification of its asset base also plays to Anadarko’s advantage, given its mix of both conventional and unconventional properties, as well as domestic and international properties. In addition, it benefits from having a midstream capacity, through its majority-owned Western Gas Partners, allowing for the timely installation of gathering and processing facilities. Risks of bottlenecks, as well as of upstream investments being “stranded” or lying “fallow,” can thus be largely avoided.

An example of Anadarko successfully syncing upstream and midstream operations has been in Wattenberg Field, where third-quarter volumes grew by 20,000 bbl/d, or 12%, over the prior quarter. The field is projected to generate more than $500 million of free cash flow this year while also “demonstrating exceptional growth in the years to come,” Walker said.

“We have talked in the past about the importance of controlling wellhead results through aggressive midstream management,” he noted. “Results from this quarter in Wattenberg Field once again put an exclamation point on this cornerstone difference for Anadarko.”

The company appears to be charting a similar course in working with Western Gas in the Delaware Basin, where its midstream affiliate recently made a $1.5 billion acquisition of Nuevo Midstream LLC.

At the time of the announcement, Anadarko had 45 wells producing across 600,000 gross acres in the Delaware, “and all have met or exceeded expectations,” Anadarko stated. Also, early results from wells outside the company’s “high confidence” area continue to be encouraging. Initial wells targeted the Wolfcamp A, and Anadarko said it was also testing other benches as well as several development concepts.

As far as a comparison with Wattenberg Field, Anadarko has said it is “using the same playbook” with the Delaware assets and how they will interconnect with the recently contracted Nuevo Midstream operations.

Acquisition opportunity

For Synergy Resources Corp., acquisitions have also played a part in the company’s development, and it views the pullback in commodity prices as more opportunity than obstacle.

Citing a “lull” in what had been a highly competitive market for assets in the Niobrara Shale play, the Platteville, Colorado-based E&P was able to negotiate a $125 million acquisition of producing properties and leaseholds in Wattenberg Field. Synergy made the purchase from a private party and had in place $230 million in committed financing in announcing the deal.

Just days earlier, on its third-quarter earnings call, co-CEO Ed Holloway highlighted how Synergy’s strategy did not depend on $100/bbl WTI prices. Budgeting for the current fiscal year, ending August 31, 2015, was based on a $85/bbl WTI price, he said, which translated to a net price of $75/bbl. “We weren’t counting on $100 oil to execute our plans and to grow our company.”

Moreover, the company has re-run its model using a $60/bbl net price for oil and $4/Mcf for natural gas, and the EBITDA margin as a percent of revenue was over 60%, he noted. This factored in no benefit from lower drilling and oilfield service costs, he added, which were likely to materialize if oil prices stayed at lower levels.

The strategic acquisition expands Synergy’s core Wattenberg leasehold by about 20% to more than 35,000 net acres. The assets are near the company’s Phelps and Eberle pads, where horizontal wells have had “excellent results.”

The purchase was comfortably financed due to Synergy’s strong balance sheet. As of August 31, 2014, Synergy had cash and equivalents of $34.8 million, with $37 million—unchanged from the year-earlier period—drawn against a then-$110 million borrowing base. The $125 million transaction was comprised of 70% cash and 30% stock.

“We have historically built value for companies we have run, when commodity prices have dropped, by buying assets during these times,” Holloway said.

With such strategies in place, these and certain other E&Ps are likely to successfully navigate the turbulent waters of depressed prices—and emerge still seaworthy on the other side of the storm.

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