Chesapeake Energy Corp.’s (CHK) financial and operating deals, impacted by low natural gas realizations, have damaged the calculated net asset value (NAV) of some of the natural gas plays in its massive portfolio, according to an analysis by ITG Investment Research.

With its joint ventures (JV) agreements, 10 volumetric production payments (VPP) and off-balance sheet transactions, CHK’s NAV is around $14.92/share using a 10% discount rate at $4.00/MMBtu on the New York Mercantile Exchange and $90/bbl at West Texas Intermediate crude oil, according to an indepth report by ITG IR. At $5 Nymex, the NAV increases to $27.86/share. Running a 12% discount rate, the NAV drops to $10.58.

“That was one of the biggest surprises,” ITG IR Managing Director Manuj Nikhanj told NGI last week. “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.”

Nikhanj, who is head of energy research, said the Calgary-based firm launched its review in part after “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 NGI, June 25).

The ITG IR team is unlike many providers. The energy team, which is staffed in a similar way to an exploration and production company, has focused its efforts since 1998 on oil and natural gas plays, not the producers per se. Because CHK is one of the top natural gas producers and onshore leaseholders in the United States, its name has come up often. “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, the investment team created the CHK NAV model 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.

For example, public data on CHK’s proved developed reserves (PDP) were analyzed for more than 2,500 Barnett Shale wells and 600 Haynesville Shale wells. Analysts discovered that the PDP variances in those two plays accounted for 7.9 Tcfe of CHK’s 18.8 Tcfe of PDP at year-end 2011.

Before calculating the VPPs attached to the two assets, the PDP blowdown gas reserves amounted to 2.8 Tcf, or 70% of the total estimated by Netherland Sewell & Associates Inc. (NSAI), the independent third-party engineers that CHK uses. The delta between NSAI and ITG IR likely is because of “differing types of curve assumptions,” according to the analysts. Additionally, there’s “no value in the 3 Tcf of proved undeveloped reserves (PUDs) at current pricing for those assets.”

Analysts were “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.” The low price realizations and resulting high break-evens levels plus low drilling activity levels are the key reason for the ITG IR’s thesis on the PUDs: the shortfalls herald “a potential writedown, in our opinion.”

Because his firm’s access to data is “far more limited,” Nikhanj acknowledged that NSAI “could see internal information from CHK that we just don’t have access to.” The reserves differences weren’t intended to be the central focus of the report. “The Barnett and Haynesville are higher cost gas assets and are not of that much value these days anyway. Our focus was to have a comprehensive analysis on all aspects of one of the largest natural gas producers in North America.”

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. “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” of CHK’s asset base, said Nikhanj.

Beyond the “obvious benefits” from drilling carries, Nikhanj said in the report “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.”

CHK doesn’t provide information on when its leaseholds expire in individual plays; rather, it shows an aggregate expiration schedule, which further clouds the ability to evaluate its individual assets, noted Nikhanj.

“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. If a large part of that acreage is in the company’s top plays like the Eagle Ford or Marcellus, that is a major concern.” The expiry issues and other financial and operating commitments are a big reason for why CHK is in a “vicious drilling cycle where it is hard to slow down. There is a need for the company to slow down activities, live within cash flows and pay down debt, but it’s not that easy.”

In addition to its financial and operating commitments, CHK’s gross operating based decline rate is 40%, he noted. “That’s a fast treadmill that you don’t want to fall off of.” Selling the Permian Basin portfolio, the biggest asset on the market by CHK, would “help to bridge the funding gap” and the producer likely would fetch $4-5 billion, according to Nikhanj. The Permian sale is going to take an “absolutely massive commitment…a ton of money” by a company with deep pockets,” said Nikhanj, referring to not only the sale price but the need for the purchaser to drill aggressively to hold a good chunk of the 1.5 million acres for sale. “Those types of buyers aren’t easy to find these days.”

Unless the producer’s proclivity to spend can change, “I see the same thing happening within a couple of years absent any significant increase in commodity prices,” Nikhanj said.

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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