Chesapeake Energy Corp. (CHK) is the second largest natural gas producer and one of the largest leaseholders in the United States but its various financial deals have damaged the net asset value (NAV) of its portfolio, according to ITG Investment Research.
An array of joint ventures (JV) agreements, 10 volumetric production payments (VPP) and several off-balance sheet transactions reduced CHK’s after-taxes NAV to about $14.92/share based on $4.00/MMBtu on the New York Mercantile Exchange and $90/bbl at West Texas Intermediate crude oil, ITG analysts estimated. At $5 Nymex, the NAV increases to $27.86/share. Running a 12% discount rate, the NAV drops to $10.58.
“That was the most shocking thing we discovered,” ITG Managing Director Manuj Nikhanj told NGI’s Shale Daily. “When you start to peel back the onion, we thought there would be much greater value than there is.” The “raw asset value is dragged down by these arrangements. We were most surprised with the value we came up with as a whole, because we thought there would be more.”
Nikhanj, who is head of energy research, said the firm launched its indepth review in part because it was “getting lots of questions” about CHK last spring. CHK has been under intense scrutiny for several months following several questionable financial disclosures concerning CEO Aubrey McClendon, who was stripped of the chairman title; a shareholder revolt also toppled half of the board of directors (see Shale Daily, June 22).
ITG since 2002 has focused most of its research on the value of oil and gas plays, not the companies per se. However, because CHK is one of the top natural gas producers and onshore leaseholders in the United States, its name has come up often over the past decade. “When we are looking at the Utica Shale, we look at Chesapeake. When we look at the Marcellus, we look at Chesapeake,” said Nikhanj.
With a base of knowledge already in house, ITG created the NAV model for CHK over a two-and-a-half-month period using data on “several thousand wells” compiled from regulatory agencies, such as the Railroad Commission of Texas, and through filings to the Securities and Exchange Commission (SEC) and investor presentations. What analysts found were “too many shades of gray,” said Nikhanj.
Among other things they have discovered reserves numbers variances in the Barnett and Haynesville shales, which together would knock about 20% from the company’s proved developed and producing (PDP) reserves figures at the end of 2011.
When CHK’s reserves were analyzed by play, a variance was found when comparing well-by-well data in the public filings, with the third-party engineering reports generated by Netherland, Sewell & Associates Inc. (NSAI), which uses data provided by CHK. CHK reported 18.8 Tcfe of total proved reserves at year-end 2011, of which 54% (10.1 Tcfe) were PDP, using $4.11/Mcf Nymex prices and $96/bbl WTI.
However, by ITG’s calculations, PDPs at the end of 2011 were closer 8 Tcfe, which “largely reflects our lower estimates for the company’s Barnett and Haynesville properties,” said Nikhanj.
The drop in reserves numbers have drawn the most media attention, but he said they weren’t intended to be the central focus of the report. “The gas assets are not of that much value these days anyway…We wanted to focus on the aggregate value total.” For example, CHK’s Permian Basin portfolio wasn’t included in the numbers because it is to be sold. “The only real delta is the Barnett and the Haynesville.”
ITG’s team was “surprised by CHK’s low price realizations from its gas assets, particularly the Barnett [Shale], which averaged 40% of Nymex during 1Q2011 to 3Q2011,” said Nikhanj. As of 3Q2011, “CHK no longer breaks out realizations by play.”
In comparing CHK’s disclosed reserves at the corporate level in its Southern Division, which would includes the Barnett and Haynesville, ITG calculated the total proved value at 48 cents/Mcf, which “likely reflects costs associated with the VPPs. With reduced drilling activity this year and absent any significant increase in gas prices, there are a material amount of PUDs [proved undeveloped reserves] (3 Tcf) that have no positive value, heralding a potential writedown, in our opinion.”
ITG’s “calculated PDP blowdown gas reserves for these two assets [Barnett and Haynesville] are estimated at 2.8 Tcf, or 70% of NSAI’s numbers before VPPs. This is likely due to differing types of curve assumptions.”
Chesapeake defended its independent engineering reports.
“Our independent engineers at Netherland, Sewell & Associates Inc. have been determining reserves for over 50 years and evaluating Chesapeake reserve assets for over 10 years using the most comprehensive data set available,” Chesapeake spokesman Michael Kehs told NGI’s Shale Daily. “We are confident in the accuracy of their reports and our public filings based on them.”
Given its huge debt, cash flow “outspending” and financing arrangements, questions surround the asset base’s “existing quality and future prospectivity,” said Nikhanj. Beyond the “obvious benefits” from drilling carries, “many assets are burdened by the terms of the company’s operating agreements and financial engineering” such as higher royalties from gross overriding royalties and subsidiaries such as Chesapeake Granite Wash Trust (CHKR); increased operating costs as a result of VPPs; and low-working interests reflecting the impact from JVs, the Founder Well Participation Program, CHKR and VPPs (albeit over a fixed number of years).”
In addition, “take-or-pay midstream and service contracts, lease obligations and minimum drilling commitments under JV agreements for some plays compound CHK’s drilling and financial obligations, negatively affecting its underlying value.”
Chesapeake doesn’t provide information on when its leaseholds expire; rather, it uses an expiry schedule, which further clouds its balance sheet, noted the ITG chief. “If you add it up, about five million net acres expire before 2014, which would take an estimated 8,000 net wells to hold the land. That’s a lot of land to be expiring.” For example, about 500,000 acres are expiring in CHK’s Marcellus Shale leasehold “next year or in the next couple of years.”
The expiry issues are one reason CHK runs a “circular” operation, he said. It has to drill to hold land, to hold rig contracts and midstream contracts. And it has to drill to pay for debt covenants that it has to meet.
“It’s obvious that [CHK] has to sell assets for the cash flow. Why not slow down drilling? Well, it’s not that easy in order to keep the machinery moving. Chesapeake has a base decline rate of 40%. That’s a fast treadmill. It affects cash flow, the debt covenants…”
Selling the Permian Basin portfolio would “help to bridge the gap a little bit” if it’s sold for $4-5 billion. “But based on Chesapeake’s capital spending plans, I see the same thing happening within a couple of years. It’s unfortunate.”
The Mississippian Lime formation assets also are on the sales list. The Permian sale especially is going to take an “absolutely massive commitment…a ton of money” by a company with deep pockets, said Nikhanj. “Those types of buyers aren’t easy to find these days.”
Separately, the chairman of Southeastern Asset Management, CHK’s largest shareholder, said in a quarterly letter to his shareholders the reconstituted CHK board of directors is behind McClendon.
“All of the leadership controversy is now moot,” wrote Southeastern CEO Mason Hawkins in a letter dated July 12. “We go forward at Chesapeake with one of the best and most vested independent boards that we have seen.” Because of the board’s “multiple industry, client, professional and personal contacts, we gained insight about McClendon and arrived at a different conclusion than the image currently portrayed by Chesapeake short sellers and much of the media.”
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