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Shale Gas Production Currently NOT Profitable

This is an excellent piece on shale gas production, price, and (lack of) profit. It really exposes the inappropriately low price of shale gas for what it is. This discussion could go a lot further, but this is probably enough for one day:

by Dave Cohen

Shale gas drilling and production in the United States is ramping up like there’s no tomorrow. Natural gas is going for $3.01 per MCF ($MMBTU, Henry Hub future). The average well-head price in 2010 was $4.48/MCF. Through the first 10 months of 2011, it was $4.04. It is impossible make a profit producing shale gas at that price. Let me spell that out for you.


Consider the situation. The natural gas market is out of balance. There is a glut (over-supply) of natural gas, which is driving down the price, although demand is rising somewhat due to low prices. Now, you would think that producers would pull back on production to bring the market back into balance. But no! The shale gas operators keep drilling, which drives down the price, which makes it even more unprofitable to sell shale gas. This alone ought to tell you there’s something fishy going on.

Natural gas production in the northeast, reflecting the production boom in the Marcellus shale.The EIA’s October 2011 monthly data show gross (total U.S.) production of 2,483 billion cubic feet, the highest month on record. Graph source: EIA.

It’s been awhile since I looked at shale gas economics. Look at my mid-2011 posts How Does The Shale Gas Scam Work? and The Shale Gas Scam Goes Public. The first post summarizes my previous work on shale gas. The second comments on the exposé questioning shale gas economics published in the New York Times last June. Energy analyst Chris Nelder has also weighed in on problem in The questionable economics of shale gas. I’ll quote Nelder’s article at length, making some comments of my own.

Houston-based petroleum geologist and energy sector consultant Arthur Berman, along with petroleum engineer Lynn Pittinger, has independently studied the economics of thousands of wells in the three shale gas formations with the longest production histories — the Barnett Shale in Texas, the Fayetteville Shale in Arkansas, and the Haynesville Shale in Louisiana — and found numerous irregularities.

When the true structural costs of shale gas are fully incorporated, he says, including the costs of leasing, restimulating wells where production was flagging, and general operation and administrative overhead, operators need $8 to $9 per thousand cubic feet (mcf) to break even, assuming an 8 percent discount rate.

For new development on existing leases, considering just the costs of drilling, completion and operation, operators need $5 to $6/mcf to break even. But the spot price (for immediate delivery) of gas is only $3.11/mcf today, and except for two brief moments in 2010, it has remained below $5 since February 2010. On an averaged annual basis, shale gas has been unprofitable since 2008.

If shale gas production is unprofitable, then why is there still so much drilling activity, and how are producers able to claim otherwise?

Yes, those are the questions. Nelder offers some theories. We can call the first one Use It Or Lose It.

gee whiz natural gas pricesOne answer to this conundrum is that operators need to keep drilling in order to hold onto their leases. If they don’t actively work the land that they spent the last several years acquiring in a buying frenzy, they lose it. The early operators in these gas formations, or “plays,” aren’t sufficiently well-funded to continue drilling at a loss; they’re simply trying to hold onto their leases long enough to flip them to larger companies at a profit. Hence the recent rash of joint ventures with deeper-pocketed players, which give the original leaseholders a way to pay off the leasing and initial drilling costs, but ultimately reduces their net asset values.

A detailed examination of the financial data bears this out. If shale gas is so profitable, then one might expect operators to pay for leasing and drilling costs out of cash flow, and pay down their debt. But quite the opposite appears to be the case. According to analysis by Bernstein Research, capital expenditures on land acquisition and new drilling exceeds cashflow (by as much as 511 percent in the worst example, Carrizo Oil & Gas) for 18 of the top shale gas producers, and they’re still heavily laden with debt.

This makes sense, and accords with my own conclusions. Nelder also speculates that “producers are willing to take a big gamble on shale gas in order to support their market valuations.” (See his article for the details.) Another sensible theory is that the production of associated liquids makes the economics better—but not “better” enough.

The production of associated natural gas liquids, which generally command about half the price of oil, further complicates the economics. (At the 2011 average of $95 a barrel for oil in the U.S., gas sells at an enormous discount to oil, at $3.29 per million BTU, versus $16.39 for oil.) Natural gas liquids produced along with the “dry” gas have certainly helped generate revenues, but to what degree, we don’t know, since they are not separately reported to regulators. Berman estimates they might add $1/mcf after processing. Operators commingle the revenues from “dry” gas with those from associated natural gas liquids, masking the true profitability of the gas production.

Does it matter if some operators are able to drill profitably due to the natural gas liquids, but not the gas itself? Well yes, it does. If the wells are shut down after their liquids play out, it could leave a lot of gas effectively stranded, and a significant chunk of the anticipated reserves would never be produced.

And last but not least, the best part of shale gas economics involves the use of “creative accounting.”

In order to show profitability, shale gas operators have employed complex creative accounting. Instead of the usual “netback” calculations that clearly state the net profit per barrel of oil equivalent (or per mcf of gas) produced, in the 10-K reports filed with the SEC, one finds an intricate set of statements which would only be comprehensible to an expert accountant, not an average investor.

Hedging strategies employed after 2008 have counterbalanced some of the losses on production, andmajor capital costs have been excluded through off-book accounting. Worse, Berman found that some operators have used variable production payment schemes to recognize borrowed cash up front, then failed to account for it as debt and actually claimed it as an asset.

As Bloomberg reports in Shale Bubble Inflates on Near-Record Prices, the shale gas shenanigans are continuing unabated. I’ll illustrate this through their coverage of investment in the Utica shale, which I recently posted on inThe Next “Oil” Miracle” Will Be In Ohio! That post tells you what you need to know about the Utica natural gas play. It is largely unknown whether the Utica will be a winner. And now here’s Bloomberg

Surging prices for oil and natural- gas shales, in at least one case rising 10-fold in five weeks, are raising concerns of a bubble as valuations of drilling acreage approach the peak set before the collapse of Lehman Brothers Holdings Inc…

Chinese, French and Japanese energy explorers committed more than $8 billion in the past two weeks to shale-rock formations from Pennsylvania to Texas after 2011 set records for international average crude prices and U.S. gas demand. As competition among buyers intensifies, overseas investors are paying top dollar for fields where too few wells have been drilled to assess potential production, said Sven Del Pozzo, a senior equity analyst at IHS, Inc.

In the Utica shale of Ohio and Pennsylvania, deal prices jumped 10-fold in five weeks to almost $15,000 an acre, according to IHS figures.

“I don’t feel confident that the prices being paid now are justified,” Del Pozzo said in a telephone interview from Norwalk, Connecticut. “I’m wary.”

Why is Sven wary? Why doesn’t he feel confident? Because these overseas investors could be paying $15,000 an acre for garbage!

Private-equity firms also are showing increasing interest in US shale assets, Sylvester “Chip” Johnson, chief executive officer of Carrizo Oil & Gas Inc., said in a Jan. 4 presentation at a Pritchard Capital conference in San Francisco.

[My note: there’s Carrizo again. You will recall that Nelder mentioned them.]

Carizzo, based in Houston, has been selling fields in some of its first shale plays, such as the Barnett region, to raise money for drilling higher-profit Utica and Eagle Ford prospects that contain oil, he said.

The higher-profit Utica prospect? As far as I can see, no one has made a single dime (producing gas and associated liquids) in the Utica shale up to now. Can you say “Ponzi Scheme”?

Chesapeake sold $750 million preferred shares last month in a subsidiary created to finance development of its Utica shale holdings. The transaction entitles Magnetar Capital, Blackstone Group’s GSO Capital Partners LP and an investment group that includes EIG Global Energy Partners LP to 7 percent annual distributions and a 3 percent overriding royalty interest in the first 1,500 wells.

Where there is questionable stuff going on in the shale gas biz, you will always find Chesapeake. They’re selling “preferred” stock to finance the next acquisition frency because they don’t actually make money producing shale gas. But here’s my favorite part.

Buyers are studying fields more closely before committing, Nikhanj said. Total, Europe’s third-largest oil producer by market value, was selective about what sections of the Utica shale will be included in the 25 percent stake it acquired on Dec. 30 in 619,000 acres controlled by Chesapeake Energy Corp. and EnerVest Ltd.

Total’s outlay, including drilling costs, will be $2.32 billion, or the equivalent to about $15,000 an acre, based on Bloomberg calculations. That’s more than four times the average per-acre price from seven Utica shale transactions tracked by IHS from March 2011 to September 2011.

“We are seeing prices move up quite dramatically in these exploratory shale plays,” Nikhanj said. “But the Total joint venture also shows us that these companies with deep pockets are doing more science” before signing deals.

Doing more science! They’re paying $15,000 per acre for potential garbage! Recall Nelder’s words: “shale gas operators [like Carrizo and Chesapeake] are simply trying to hold onto their leases long enough to flip them to larger companies at a profit. Flip away!

Can no one make an honest living anymore? It’s not hard to imagine how all this is going to end.

And on that note, I will conclude this overly long analysis. As always, the Latin axiom Caveat Emptor applies—let the buyer beware.

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Written By

Zach is tryin' to help society help itself one word at a time. He spends most of his time here on CleanTechnica as its director, chief editor, and CEO. Zach is recognized globally as an electric vehicle, solar energy, and energy storage expert. He has presented about cleantech at conferences in India, the UAE, Ukraine, Poland, Germany, the Netherlands, the USA, Canada, and Curaçao. Zach has long-term investments in Tesla [TSLA], NIO [NIO], Xpeng [XPEV], Ford [F], ChargePoint [CHPT], Amazon [AMZN], Piedmont Lithium [PLL], Lithium Americas [LAC], Albemarle Corporation [ALB], Nouveau Monde Graphite [NMGRF], Talon Metals [TLOFF], Arclight Clean Transition Corp [ACTC], and Starbucks [SBUX]. But he does not offer (explicitly or implicitly) investment advice of any sort.


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