Recently, Pioneer Natural Resources Co. (NYSE: PXD) has been using dissolvable plugs in Permian Basin wells.

In the Eagle Ford, such plugs dissolve in about 17 hours, eliminating the need for coil tubing to drill them out.

The ground beneath the Permian, though, is about 150 degrees cooler and the plugs take significantly more time to dissolve. They will have to be modified before they represent a repeatable improvement.

In a $50 per barrel WTI world, E&P companies have set about making efficiency and expense-reduction initiatives a priority.

While such measure are worthwhile, for all the effort on innovation none trump the most meaningful value drivers: liquidity, leverage and hedging and growth prospects, said Eric Otto, analyst, CLSA.

Since the November decline in oil prices and the loss of $550 billion in market capitalization in the oil and gas sector, capital has flooded the industry in a vote of confidence.

Companies are seeing advantageous declines in service costs and are working on innovative ways to save money. But they’re also holding back production and letting rigs roll away.

Otto held discussion with nine companies, including some of the largest operators in the Eagle Ford, Permian and Bakken. His analysis shows that while efficiency and expense-reduction initiatives will increase value, they continue to matter much less in the long term.

“We could be wrong, however, if oil prices remain elevated and increase from current levels,” Otto said.

Otto spoke with Apache Corp. (NYSE: APA), Cimarex Energy Co. (NYSE: XEC), Continental Resources Inc. (NYSE: CLR), EOG Resources Inc. (NYSE: EOG), Laredo Petroleum Inc. (NYSE: LPI), Oasis Petroleum Inc. (NYSE: OAS), Sanchez Energy Corp. (NASDAQ: SN), Whiting Petroleum Corp. (NYSE: WLL) and Pioneer.

Otto downgraded EOG, Pioneer and Cimarex noting that they are led by strong management teams, have good liquidity and operate in some of the most productive areas.

However the companies are “now at the high end of their respective trading ranges.”

“In our view, they offer very limited upside potential, given their growth prospects and our oil price estimates,” he said.

The Companies

At Apache, no part of the company’s capital chain isn’t subject to price concessions. However, prices for pressure pumping hadn’t fallen by February but are now starting to tumble.

That indicates further downward pricing bias, Otto said.

In the Permian Basin, Apache is seeing about 30% reductions in drilling and completion costs, but horizontal well discounts haven’t been as robust.

Based on fourth-quarter 2014 lease operating expenses (LOE), Apache should be able to realize a 10% cost reduction, with the primary drivers being fuel, water handling and contract labor, which make up 70% of the total.

“The biggest opportunity for reductions is contract labor, which had been widely used by industry prior to the downturn in oil prices,” Otto said.

Apache is now using a five-year strategic plan across its areas of operation while running on three oil price scenarios:

1) The upside, in which oil rallies within 18 months to $80 flat and stays there for five years;

2) The base case, utilizing strip pricing; and

3) The downside, at $50 flat.

Cimarex Energy remains focused on spending only cash flow plus cash on hand, though it could add a seventh rig to its operations.

Service companies have reduced rates more quickly than in the past for Cimarex and completion costs, as an example, have declined by about 15%.

Cimarex’s current guidance for LOE are to stay within the range since the company based guidance on the lower-cost operating environment.

The company is generally working toward optimizing to reduce costs. Toward the end of the year, for instance, a gathering agreement in Culberson County, Texas, could improve realizations by about $2 as long as the gravity remains below 60 degrees API. In Culberson County, Cimarex operates the Wolfcamp D and production in Wolfcamp benches C and A.

Otherwise, there are “no current game changers on operating expenses,” Otto said.

Unlike other companies, Cimarex is not trying to delay completions to take advantage of potentially higher commodity prices in the future. The company has a robust inventory, giving it the ability to drill to create value.

“In the Cana, there is a built-in lag between drilling and completing wells, as the process for the development drilling is to start from the middle and drill out entire sections, followed by hydraulic fracturing of the section,” Otto said.

In May 2014, Cimarex purchased Cana-Woodfard acreage for $497.4 million and Devon Energy Corp. (NYSE: DVN) purchased a 50% interest in the assets.

Cimarex operates two of the sections, which take 35 days to drill a well and five days to complete it.

Completions will start in July and wells are expected to come online in the second half of 2015.

About 40% of Cimarex’s $1 billion capex will be spent in the first quarter of 2015.

More Cost Cutting

Continental said its costs have come down by 12-15% and could drop as much as 20% by the end of the year compared to fourth-quarter 2014 levels across the board. But it is still slashing rigs.

“The potential for 20% reductions is based on the company’s experience working with contractors and the severity of cuts they have seen to date,” Otto said.

The company has dropped to 28 rigs—10 in the Bakken and 18 in the South-Central Oklahoma Oil Province (Scoop), a more aggressive reduction from expectations of 31 rigs.

Cycle times have been an area of focus and the company hopes to continue reductions during the course of the year.

Continental is also moving toward standardized completions to further reduce costs and gain efficiencies.

“Continental Resources sees a supply/demand rebalance over the next few months and is more constructive than EIA estimates,” Otto said. “The current expectation is that the rebalance could occur in the third quarter of 2015” based on their focus on rig reductions and production growth.

EOG has said it will defer 350 well completions in 2015 based on their view for both oil prices and service costs. It will continue to build inventory throughout the year and will make the decision in September based on returns, not just oil prices.

EOG put its plan in motion at the beginning of 2015 when it had already seen 5% price savings. Since then, costs have fallen another 10-30% in March.

“For improved targeting, EOG is trying to optimize placement of a lateral within a 10-foot window versus 50 to 100 feet previously and believes this could result in materially better well productivity,” Otto said.

That could lead to more productive wells, but the process is still early in development.

E&Ps And Midstream

At its April 13 investor meeting, Laredo Petroleum caused some confusion about its location counts. De-risked locations stand at 4,830 including 3,980 that are development-ready.

Laredo Midstream Services (LMS) is still being treated as part of the company’s consolidated financials and the company has not asked the IRS for a review related to “qualifying income” related to LMS.

The company still remains focused on additional hedging opportunities 12-18 months out.

Oasis Petroleum continues to delay completions and management said the industry is still in a transition period as it takes time for the overall supply growth to stall out.

For Oasis Midstream, discussions about a possible sale or IPO continue, but the IRS has indicated they have completed their review process for “qualifying income” without making a determination on treatment of specific activity.

Questions related to expense trends will be addressed during the company’s first-quarter 2015 earnings call.

If Pioneer signed up for a 1,500 HP rig today in the Permian Basin, it would cost $20,000 per day, down from $26,000 in the summer of 2014. The company has also systematically cut costs: 5% by mid-January, 7% by February, 9-10% by 1 March and currently by 13%.

Pioneer is also working on efficiency by continuing its completion optimization activities in the Spraberry/Wolfcamp and relocated field personnel from the Eagle Ford. Their job: identify the ideal recipe for completions.

For example, wells are potentially more productive with increased fluid and less sand, which has long-term implications.

Pioneer is also still in the process of divesting its Eagle Ford Shale midstream company and could lead to a near-term announcement.

Sanchez Energy is talking down prices rather than changing its well designs, reducing costs through negotiations.

However, the company will next look to redesign wells as they balance cost and efficiency.

Sanchez continues to power down rigs and will have two working by June. Day rates in the Eagle Ford currently stand at $18,000.

Sanchez Energy is also considering monetizing its midstream assets though “this is likely a longer-term exercise that is currently centered on how to set up a midstream entity and accounting discussions, particularly historical financials,” Otto said.

Whiting said its cost decreases will start to show up in the second half of 2014. Service companies have reduced costs by 5-10% and are now moving toward 15-20% reductions, with some authority for expenditures (AFEs) showing reductions of 30%.

In the Bakken, Whiting said some wells now cost about $7 million, down from $8-9 million. The goal is to drive costs down to $6.5 million.

Bakken demand for drilling and services has collapsed and many providers are being forced to work below breakeven. In the Niobrara, wells had been at $6 million and the company has drilled some for $5 million, with a goal of $4.5 million.

“Whiting continues to throw a little science at wells, but is primarily focused on reducing well costs while keeping productivity flat,” Otto said. “Efficiency initiatives are focusing on optimizing well size, reducing stages and increasing entry points and slickwater fracks.”

Contact the author, Darren Barbee, at dbarbee@hartenergy.com.