Permian IPO Scuttled; Other E&Ps Likely To Test Market

Southern Delaware producer Centennial Resource Development Inc. dipped its toe in the IPO pool June 22, becoming the first U.S. upstream company to do so in two years.

By July 7, the NGP Energy Capital-backed company apparently had a change of heart and fortunes. Riverstone Energy Ltd. and affiliates signed an agreement to acquire a majority stake in Centennial with an investment of $175 million.

But the ripple effect from Centennial’s bold move may prove to be a turning point for E&Ps in the best resource basins, despite low commodity prices.

Had the company gone ahead with its IPO, it would have been the first U.S. upstream E&P to test an initial offering since June 2014.

Centennial’s IPO was grounded in sound reasoning. Several Permian Basin players have enjoyed success with secondary offerings to fund (and overfund) transactions.

“We suggest that a combination of a relatively strong sale price along with the uncertainty of any public offering caused Centennial to sell rather than test the public route,” said Neal Dingmann, analyst at SunTrust Robinson Humphrey.

But analysts said that more companies will look toward alternatives besides asset sales to exit plays. An IPO can provide private equity-backed companies a way out and potentially command better returns than selling to a larger E&P.

Bill Marko, managing director of Jefferies LLC, said a number of Permian operators have been able to raise equity through secondary offerings despite lower oil prices in the past year or so.

Centennial’s IPO filing is the first of a handful that will likely come out of the Permian, he said.

“I guess they’re the first guys to put their tails in the water since the price went back up,” Marko told Oil and Gas Investor. “It demonstrates that the Permian has the best economics of any of the basins so guys there will probably be the first ones to come back to the market.”

Centennial’s properties consist of large, contiguous acreage blocks in Reeves, Ward and Pecos counties in Texas, in an area about 45 miles long by 20 miles wide.

The company’s portfolio includes 61 operated producing horizontal wells, and it has established commercial production in the Third Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp B, Wolfcamp B and Wolfcamp C.

“We believe our acreage may be prospective for the Second and Third Bone Spring shales and Avalon Shale, where other operators have experienced drilling success near our acreage,” the company’s prospectus said.

The company added one horizontal rig in June after temporarily suspending drilling at the end of March.

In May and June 2016, Centennial closed acquisitions contiguous to its position. In the two deals, the company acquired about 2,400 net acres, most of it operated, adding 250 boe/d of production. This year, the company has spent about $44 million on acquisitions.

The company has a $65 million term loan and $77 million on its revolving credit facility. Its borrowing base is $140 million as of April.

Centennial had intended to use proceeds from the IPO to repay its loan and outstanding indebtedness under its revolving credit facility, SEC filings said. Credit Suisse Securities (USA) LLC and Barclays Capital Inc. were underwriters for the public offering.

Tim Perry, managing director for Credit Suisse USA, said Permian equities are down 8% from where they traded 2.5 years ago—a remarkably stable share price despite the harsh commodity environment since then.

“We haven’t seen any IPOs, as you may recall, I believe the last one was in the summer of 2014,” Perry said at a Society of Petroleum Engineers meeting June 22.

Eclipse Resources Corp., an Appalachian company, was the last U.S. E&P company to IPO.

“Here it is now two years later with prices half of what they were back then and we’re starting to see filings for IPOs,” Perry said.
While other areas have stuttered in their attempts to raise funds, Permian companies’ success in the equity markets has been impressive.

“Virtually all the transactions now are being funded by equity and, in fact, a lot of those transactions are being overfunded with equity,” Perry said.

Most recently, Pioneer Natural Resources Co. offered 5.25 million shares for proceeds of $827 million to pay for an acquisition in the Midland Basin. WPX Energy Inc. priced 49.5 million shares for $485 million after a purchase in the Delaware Basin.

Because of the high demand for assets in the Permian, however, Perry said mergers have been more difficult to come by than acquisitions.

“If the strip right now is $50, they’re trading significantly above strip. If you went and did an NAV of that company where Wall Street had that value, most companies many of them would be valued at $65 to $70 strip,” he said. “And that’s generally where the investment community is valuing these companies.”

Investors and producers alike believe technology improvements and multiple benches will support higher multiples and greater upside, Perry said.

“That whole issue of companies trading so much higher than the strip really makes it hard for corporate acquisitions to find NAV agreed deals,” he said. “That’s why we’re just seeing the corporate M&A activity slow and, frankly in our discussions, we expect it will continue to be moderate and not real high growth. We don’t see as fast a recovery as we’re seeing in A&D.”

Marko said a change in price dynamics and the multiples that Permian E&Ps command in the stock market give private companies an appetizing alternative to a divestiture.

“People are thinking about, ‘Do I IPO or do I sell?’” he said.

Not every management company wants to IPO and stick with one company. Some are true wildcatters who want to take the money and prove up another position.

“That’s part of the calculus as well. What’s the math tell me? The math right now is investors are bullish on really strong core oil stories. That would tend to carry the day,” Marko said.

Marko added that other hot plays, such as the Oklahoma Stack, will see companies go public as prices begin to creep toward $60, where most observers see oil plays as more economical.

“I think as we got into the $50s, and it’s been fairly stable, they’ll be thinking about it and certainly in the $60s,” Marko said.

Devon’s Secondhand ‘Noncore’ Midland Wares Go For $860 Million

With noncore assets like this, Devon Energy Corp. must have some pretty nice core holdings when it comes to the Delaware Basin and Stack play.

Devon said June 15 that it would sell assets it had been shopping in the Midland Basin in two deals valued at $858 million. The transactions include its upstream assets in the southern Midland Basin as well as undeveloped leasehold in Martin County, Texas.

So far in 2016, the company has closed or inked deals to sell $2.1 billion, eclipsing the low end of its divestiture goal of $2 billion to $3 billion.

“We anticipate our total noncore asset sales to be at or above the top end of our $2 billion to $3 billion guidance, with the sale of our 50% interest in the Access Pipeline” in Canada, said Devon president and CEO Dave Hager. The pipeline interest may sell for up to $1 billion.

Pioneer Natural Resources Co. was the buyer of Devon’s northern Midland positions. The company will purchase working interests in Martin County, Texas, along with acreage in Midland, Upton, Reagan, Glasscock, Andrews, Dawson, Gaines and Howard counties.

Pioneer will pay $435 million, subject to normal closing adjustments, for about 28,000 net acres.

The deals come just nine days after Devon said June 6 it had signed three deals to divest noncore upstream assets in East Texas, the Anadarko Basin and the overriding royalty interest on the northern Midland Basin acreage it sold June 15. All told, the company said the deals were worth roughly $1 billion.

The acreage bought by Pioneer is nearly all HBP and in the core of the Midland. Significant portions of the acreage offset existing Pioneer acreage, according to a press release.

About 15,000 net acres of the acquired land is in the Sale Ranch area in Martin County and northern Midland County, where Pioneer has drilled its most productive Wolfcamp B wells, the release said.

The acquisition, combined with Pioneer’s existing footprint in the area, will add about 70 Wolfcamp B locations to Pioneer’s Sale Ranch area drilling inventory. The locations have an average lateral length of about 9,000 feet.

As a result of the deal, Pioneer plans to add five horizontal rigs during the second half of 2016, increasing its rig count to 17. The first rig is expected to be added in September, with two rigs added in both October and November. The company plans to focus on the Sale Ranch area once the well locations are permitted.

Consequently, Pioneer’s 2016 capital budget is also expected to increase by about $100 million to between $2 billion and $2.1 billion. The company said it will fund its capital spending with forecasted operating cash flow of $1.5 billion, cash on hand and the remaining $500 million of proceeds from its Eagle Ford Shale midstream business sale.

Devon, too, upped its 2016 upstream capex by $200 million to between $1.1 billion and $1.3 billion. Capital investment will be directed toward the Delaware Basin and the company’s more recently acquired Oklahoma Stack play by third-quarter 2016.

Devon said it plans to add three operated rigs to its drilling plan and will consider increased activity in the fourth quarter.

Confident in the proceeds it will be able to use , Devon additionally increased its production guidance by 7,000 boe/d. For 2016, production guidance from core assets will be 550 Mboe/d at the midpoint.

Devon said it will provide additional information during its second-quarter 2016 earnings disclosures.

Pioneer’s acquisition is expected to close during the third quarter of 2016, subject to customary closing conditions.

Jefferies LLC was the lead financial adviser to Devon on the transactions. RBC Richardson Barr was also a financial adviser to Devon. Vinson & Elkins LLP was legal advisor to Devon. – Darren Barbee and Emily Moser, Hart Energy

QEP Deal Puts Permian Prices Through The Roof

If Midland Basin prices seemed on the high side before, QEP Resources Inc. has upped the ante considerably in a deal that doubled the average amount paid per acre, said Chris Stevens, an analyst at KeyBanc Capital Markets Inc.

QEP said June 21 that it had entered into an agreement with several parties to acquire about 9,400 net acres in the northern Midland Basin in Martin County, Texas, for $600 million. The acreage produces 1,400 barrels of oil equivalent per day (boe/d) from 96 vertical wells.

The acreage offers more than 430 horizontal drilling locations over four horizons—the Wolfcamp A, Wolfcamp B, Middle Spraberry and Spraberry shales, QEP said.

Assuming $40,000 per Mboe/d for the production value, QEP is paying $58,000 per acre, the highest amount so far in a Permian deal, Stevens said, adding that the acreage deserved a premium price.

The acreage is contiguous and de-risked for four quality zones. “But the valuation is surprisingly high,” Stevens said, noting that it “provides support for $/acre valuations implied by the Permian public operator that are in the $30,000 to $70,000/acre range” or an average $46,000/acre.

From a location inventory perspective, QEP is paying $1.3 million per location, which is below the historical $1.5 million per location average in the Midland Basin.

However, at an estimated average lateral length of 7,500 feet, KeyBanc estimates that QEP is using an average of 11 wells per zone per section to calculate the 430 locations on the acreage, “which we believe to be on the aggressive side, as it does not leave much room for upside,” Stevens said.

Most operators have assumed they can drill eight wells per zone per section.

Energen Corp. estimates 28 wells per section for its inventory count in the Spraberry and Wolfcamp package in Martin County. Diamondback Energy Inc. estimates about 30 wells/section, and other E&Ps have drawn similar conclusions.

“The acquisition adds significant drilling inventory in the core of the northern Midland Basin and broadens our footprint in a world-class crude oil basin,” said Chuck Stanley, chairman, president and CEO of QEP. “We believe this acquisition, combined with our existing crude oil assets, will enhance our crude oil production growth and improve our operating efficiency.”

QEP has launched a public offering of 20 million shares of its common stock to help pay for the transaction. The company expects to receive total gross proceeds of about $367 million.

The transaction is expected to close in September, subject to customary closing conditions, with an effective date of April 1. Latham & Watkins LLP represented QEP in the transaction.

Marathon Oil Builds Stack Position Higher With PayRock Deal

Marathon Oil Corp. has expanded its position in the Stack Play to roughly 200,000 net surface acres following a deal to acquire acreage from PayRock Energy Holdings LLC, an EnCap portfolio company.

Marathon Oil said June 20 it signed a definitive agreement to acquire PayRock, which holds about 61,000 net Stack acres, for $888 million. The purchase comes just months after Marathon jettisoned nearly $1 billion worth of noncore assets.

Marathon’s Stack acquisition has an implied acreage value of $11,800 per acre adjusting for proved developed producing reserves, the company said.

PayRock’s acreage, located in the oil window of the Anadarko Basin Stack play in Oklahoma, has current production of 9,000 net boe/d. The properties have 700 MMboe total resource potential from increased well density in the Meramec and Woodford, as well as Osage development.

PayRock most recently said it was targeting Stack wells in Canadian and Kingfisher counties, Okla., according to its website. Payrock is headed by president and CEO Rick Kirby, formerly vice president of operations for SandRidge Energy Inc. Several members of the company also have ties to SandRidge.

EnCap has sponsored the company since 2012, when it began working to acquire and develop resources in Oklahoma and Kansas.

Marathon said completed well costs in the Meramec are between $4 million and $4.5 million and offer 60% to 80% internal rates of return at $50 WTI before taxes.

Marathon gave no indication it would raise capex and expects its 2016 capital program on the acquired acreage to be “covered” within the company’s current $1.4 billion budget, said Lee Tillman, president and CEO.

Pro forma for the acquisition, Marathon Oil will hold about 200,000 net surface acres in the Stack play with more than 1 Bboe 2P resource.

The company anticipates a minimum four-rig drilling program within its pro forma Stack position in 2017. Four rigs will achieve leasehold drilling requirements while accelerating delineation work, Tillman said.

The transaction is expected to close in third-quarter 2016, funded with cash on hand, subject to customary closing conditions.“The recent moves we’ve taken to strengthen the company’s balance sheet, including the successful execution above the top end of our noncore asset divestiture target, have positioned us to be opportunistic to acquire what is an excellent strategic fit,” Tillman said in a statement.

In April, Marathon Oil announced sale agreements of certain noncore assets for $950 million, bringing the total to about $1.3 billion since 2015.

In the largest transaction, Merit Energy Co. agreed to purchase Marathon’s Wyoming upstream and midstream assets for $870 million, excluding closing adjustments. The sale has an effective date of Jan. 1, and was expected to close by the middle of this year.

“As we move forward, while we’re not providing a new target or timeline, our noncore asset sales program will continue to be an integral part of our business model. We will keep testing each and every asset for its fit and competitiveness within our portfolio,” Tillman said during a June 20 conference call.

Jefferies LLC was sole financial adviser to PayRock Energy. – Emily Moser

Rex Energy Agrees To Exit Illinois Basin


Rex Energy Corp.’s departure from the oily Illinois Basin will put the company on track to become a pure-play Appalachia producer, though some analysts say it sold out on the cheap.

Rex has struggled to keep the Illinois Basin economic, with oil revenues falling by 41% year-over-year in the first quarter of 2016. Along with its need to pay debt, that may have been a factor in its sale of the 76,000 net acres in Illinois, Indiana and Kentucky.

Rex said June 14 it has an agreement to sell its acreage for $40 million with up to $10 million more in proceeds depending on the value of commodity prices. Buyer Campbell Development Group LLC could not be reached for comment.

So far in 2016, Rex’s drilling has been focused in the Appalachia, where it put eight net wells into service in first-quarter 2016. In the Illinois Basin, Rex did not drill or complete any wells.

Rex said the Illinois assets produce about 1,700 net barrels per day (bbl/d) of oil. In the first quarter, Illinois Basin production was 158.3 Mbbl compared to 179.8 Mbbl/d for the same period in 2015.

“The decrease in production in Illinois is primarily related to the natural decline of our conventional oil producing properties in conjunction with shutting in certain wells that are marginally economic,” the company said in securities filings.

Brian Velie, senior analyst at Capital One Securities, said the assets’ modeled value was $100 million, including an estimated $20 million of annual EBITDA.

“On a more positive note, Rex’s share price did not previously reflect much value for the Illinois assets and shedding the only piece of the portfolio outside of the Appalachian Basin focuses the company’s efforts on its core,” he said.

Most of Rex’s revenue comes from its core Appalachia holdings.

Other analysts said the sale price was in line with expectations of about $46 million in net asset value.

Cash from the sale also improves the company’s liquidity and, after closing the deal, the company expects to maintain a $190-million borrowing base.

“The deal provides much-needed liquidity over the near term,” said Gordon Douthat, senior analyst at Wells Fargo Securities. The sale “should alleviate some of the burden of high production costs out of the Illinois Basin.”

In the Appalachian Basin, the company has 109,100 net acres and 1,110 net liquids-rich drilling locations. After first-quarter production of 200 million cubic feet equivalent per day (MMcfe/d), the company estimated an increase to about 205 MMcfe/d at the midpoint.

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