Energy Matters

“The Wolfcamp shale play is proving to be oily, consistent and large—very large.”

The oily, horizontal Wolfcamp play may be expanding north of drillers’ current focus in Crockett, Irion, Reagan and Uptown counties, Texas, in the Permian Basin, says Irene Haas, E&P analyst for Wunderlich Securities.

Haas analyzed results of some 30 Wolfcamp wells to date with initial-production rates of 1,000 to 1,500 barrels of oil equivalent (BOE) a day and are up to 60 miles apart.

Sample wells include one by EOG Resources Inc. that tested 1,576 BOE per day in Irion County and one by Pioneer Natural Resources Co., which may drill 80 Wolfcamp horizontals in 2012, that tested 1,200 BOE per day, unrestricted, in Upton County.

Also, El Paso Corp.’s #1H University 43-17 in Reagan County flowed 1,369 BOE per day, mostly oil, from Wolfcamp at 6,700 feet through a 7,500-foot lateral that underwent 25 stages.

“Assuming a 25-mile wide fairway, the trend could cover a 1,500-square-mile area or almost 1 million acres,” Haas says. “…We visited and spoke with a number of Wolfcamp-shale first movers this week and we now believe that the play could expand northward and might not be confined to the four counties.”

Wolfcamp carbonate is a “Lower Permian” play in the neighborhood of Abo, Leonard and Bone Spring carbonates and Spraberry sandstone. Haas believes a Wolfcamp play expansion bodes well for Permian-focused, Fort Worth-based Approach Resources Inc., which tested the deeper C bench of the Wolfcamp with its University 42B #1001H.

In the El Paso well, Wolfcamp is at 6,367 feet; Wolfcamp A, 6,546 feet; and Wolfcamp B, 6,704.

“While Approach did not get to complete all the stages planned, the company is happy with the micro-seismic results and will continue to refine its completion techniques,” Haas says. “We look forward to more wells being drilled in the C Bench, and expect Approach to climb the learning curve quickly.”

EOG, which is drilling Wolfcamp, Leonard and Bone Springs, expects its 240,000 net acres over these will be productive from one or more interval. It also cites Wolfcamp as the biggest of the three and wells there cost as little as $5.4 million each.

“More drilling will need to happen before we know the true extent of this play,” Haas says. “The Wolfcamp shale play is proving to be oily, consistent and large—very large.”

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

WSJ interview has the oil industry abuzz about Obama’s hopes for green and alternative energy.

It’s called the Bakken and it has oil superpowers on their heels.

The Wall Street Journal’s Stephen Moore, a member of the Journal’s editorial board, has taken notice too. Moore interviews Continental Resources Inc. founder Harold Hamm in “The Weekend Interview” edition, “How North Dakota Became Saudi Arabia,” Oct. 1. One sign that Moore knows the value of domestic energy supply? Acknowledgement that President Obama’s talk of oil and gas industry “subsidies” is really just the same tax adjustments all U.S. manufacturers receive.

Hamm, whose Continental holds 900,000 net acres prospective for Bakken oil production in North Dakota and Montana, tells Moore the U.S. could be energy independent by the end of this decade, with the right national energy policies.

Hamm, who in 2004 completed the first successful horizontal and multi-stage-fracture-stimulated Bakken well, estimates the oil field may produce 20 billion barrels of oil and 4 billion barrels equivalent of natural gas. Continental alone holds a nearly half-billion of proved reserves—that is, proven to produce—in the oil play. The figure is based on drilling to date, so more could come.

What struck the oil and gas community the most in the week following the Journal report is what Hamm tells Moore of a visit with Obama recently. In this, Obama told Hamm that oil and gas will only be important to the U.S. for a few more years; green energy and battery-powered cars will replace these in importance.

Hamm tells Moore, “Even if you believed that, why would you want to stop oil and gas development? It was pretty disappointing.”

Tom Petrie, vice chairman of Bank of America Merrill Lynch, told Oil Council conference attendees in New York that week, “The unconventional-resource revolution holds great promise for enhancing energy supply flexibility over the next several decades; a U.S. gain of 3 million-plus barrels (of daily production) over the coming decade is possible.”

U.S. oil production grew 3.2% in 2010 from 2009 to 7.513 million barrels a day, according to BP Plc’s annual “BP Statistical Review of World Energy” released in June. The 2009 rate, which was 7.271 million barrels a day, was up from 6.734 million in 2008. In the 2009 review, published in June 2010, BP reported, “U.S. (daily) production increased by 460,000 barrels or 7%, the largest increase in the world last year and largest U.S. percentage increase in our (50-year) data set.”

Peter Tertzakian, chief energy economist and managing director for Calgary-based, energy private-equity firm ARC Financial Corp., said at the Oil Council meeting in New York, “Who would have said two years ago that North Dakota would be an energy superpower?”

The 15,000-square-mile Bakken oil play, which is dubbed a shale-oil play but the oil is actually produced from rock that sits between two shales, is making 400,000 barrels a day already, he notes.

Producers expect—and pipeline and rail operators are gearing up for—making up to 1 million barrels a day from the Bakken in the coming few years.

In the Journal report, Hamm tells Moore, “President Obama is riding the wrong horse on energy.”

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Leasehold in the core Utica play may be worth between $12,000 and $16,000 an acre.

With little drilling—but early play-making results—yet from Ohio’s Utica shale-oil play, Global Hunter Securities LLC’s research team has gathered what is available—even putting Google Earth to work—for an initial “Utipedia” report.

“Uticulous,” says Michael Bodino, GHS managing director and head of energy research, of the first four horizontal completions in the Utica oil window: Each had initial production of more than 1,000 barrels of oil equivalent per day. Chesapeake Energy Corp., in a joint venture with EV Energy Partners LP, indicated in August that the tests confirmed the company has been prescient in accumulating 1.25 million net acres over the shale rock, with possibly some 40% of it in the heart of the play; in late September, it released the test results.

“If the play wasn’t on your radar screen before this announcement, it definitely should be now,” Bodino says.

In compiling the brief “Utipedia,” Bodino and the team compiled 17 slides from 11 producers’ recent presentations that include reference to Utica, which Bodino calls a “potentially massive liquids-rich shale play.”

He estimates leasehold in the core Utica play may be worth between $12,000 and $16,000 an acre in a non-operated, joint-venture structure, which Chesapeake aims to have done by year-end. At $14,000 an acre, here is what these 11 publicly held E&Ps’ leasehold may be worth, he says.

–Rex Energy Corp., 57,900 acres, $811 million or 127% of REXX’s enterprise value.

–EV Energy Partners LP, 159,000 (working interest), 240,000 (royalty interest), $2.23 billion or 77% of EVEP’s EV.

–Gulfport Energy Corp., 57,500 acres, $805 million or 60% of GPOR’s EV.

–Chesapeake Energy Corp., 1.25 million acres, $17.5 billion or 57% of CHK’s EV.

–PDC Energy Co., 30,000 acres, $420 million or 54% of PETD’s EV.

–Range Resources Corp., 357,000 acres, $4.99 billion or 43% of RRC’s EV.

–Magnum Hunter Resources Corp., 16,000 acres, $224 million or 29% of MHR’s EV.

–Hess Corp., 185,000 acres, $2.59 billion or 11% of HES’ EV.

–Consol Energy Inc., 100,000 acres, $1.4 billion or 12% of CNX’s EV.

–Devon Energy Corp., 110,000 acres, $1.54 billion or 6% of DVN’s EV.

–Carrizo Oil & Gas Inc., 1,500 acres, $21 million or 1% of CRZO’s EV.

Bodino adds that Anadarko Petroleum Corp. has an acreage position over Utica but the total leasehold amount is unconfirmed. The Ohio Department of Natural Resources reports Anadarko has received permits for three wells to Utica.

For his full report, click here.

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Chevron Corp. has capex opportunities in the Marcellus, Utica, Monterey

“This is as good as it gets in the deepwater Gulf of Mexico,” says Paul Sankey, Deutsche Bank integrated-oil equity analyst. Sankey and the investment-banking group’s research team visited with Chevron Corp. management Wednesday about the outlook for future meaningful news from the super-major.

“The most dramatic statement from our lunch with Chevron’s consistently impressive board member, senior vice president and head of upstream George Kirkland in Boston…was that current activity levels in the deepwater Gulf of Mexico represent ‘the new normal,’” Sankey says.

President Obama placed a moratorium on drilling under existing permits in the Gulf after the April 2010 Macondo well blowout. The moratorium was lifted later; however, the new regulators of Gulf drilling—the BSEE and BOEM, formerly known as the BOERME that was created and replaced the MMS during the moratorium—has not green-lighted much new drilling under existing permits and new-permit sales were suspended.

“For smaller players—even $9-billion (-market-cap) Murphy Oil Corp. is talking about an exit—this could be the end of the road on red tape,” Sankey says.

If robust drilling is not revived and the only wildcatters left in the billion-barrel Gulf region are mega-cap E&Ps, it is “another nail in non-OPEC (production’s) coffin if this is really peak activity in the GOM, with Chevron and other mega-caps as the only players. Those companies will see fewer competitors, more GOM access opportunities, lower service costs and overall oil prices higher on weak non-OPEC supply,” Sankey says.

He adds, “Good for them; that is, we believe, until the government—of the time, probably mid-next administration—wakes up to low activity, higher unemployment and less U.S. oil supply.”

He adds that Chevron management “stresses that the current regulations are far more onerous—hardly surprising post-Macondo.”

The beneficiary of stranded capex that super-majors planned for the deepwater Gulf includes onshore Lower 48 unconventional-resource plays. Spending on this type of oil and gas development that is still within the U.S. “might mitigate any policy response in Washington.”

Murphy Oil, which he says is considering a Gulf exit, has already stated that it plans to increase spending in the Eagle Ford shale-liquids and -gas play in South Texas.

Chevron plans to increase its capex spending on its Marcellus shale-gas and -liquids assets, which it bought from Atlas Energy Inc. earlier this year. It also holds more than 600,000 acres that are prospective for Utica oil-shale pay in Ohio and it owns a large leasehold in southern California that is prospective for Monterey shale-oil pay.

As for Chevron acquisitions, Sankey says that, in the Wednesday meeting, “denials were not as strong as bulls might hope. Don’t count out more (unconventional-) resource deals here.”

Sankey says cash-rich Chevron is underweight U.S. natural gas and U.S. unconventional resources.

“Questions will persist over its appetite for M&A to boost near-term growth and develop a portfolio with shorter-term, more-flexible spending that the unconventional (play category) offers (compared with long-range Gulf and other mega-projects).”

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

“…Additional dry-gas acreage would be met with investor scorn,” says Barclays Capital’s Michael Zenker.

Maybe the ire of investors has publicly held producers shy about buying dry-gas-producing properties. Barclays Capital research analysts asked several public E&Ps’ executives if they would buy dry-gas acreage from distressed sellers today if the price is right.

“Most answered ‘no,’ while only two answered ‘yes,’” says Michael Zenker, Barclays Capital managing director, commodities research. “This suggests that some companies believe adding additional dry-gas acreage would be met with investor scorn. A watershed event would be a company applauded for selling or spinning its gas acreage to focus on oil. Some companies have positioned themselves this way, but have not completely eschewed gas.”

The small-sample survey was taken at Barclays’ recent energy and power conference where more than 170 companies—from E&P and oilfield services to midstream, coal and power generation and transmission—presented to institutional investors in five tracks during three days in New York.

“One company executive indicated that an increasing number of offers to sell gas acreage were being presented to them. In some cases, prices are as low as $1 to $1.50 per Mcf for dry-gas reserves—close to the cost of developing reserves. This suggests the business model of acquiring dry-gas acreage—drilling several wells to prove the resource, and then flipping the asset—is meeting a bearish market. Liquids-rich acreage still commands interest and a premium.”

E&Ps’ push to emphasize to investors and grow their oil and gas-liquids production began in early 2010, while emphasis leading up to late 2008 was on dry-gas-production growth from the Barnett, Fayetteville and Haynesville plays were headliners before gas prices fell into single digits and finally landed at $4.

At the recent Barclays conference, “management teams took great pains to draw attention away from the gas side of their businesses. Many companies led their presentations with catchy phrases about their new-found oil prowess: ‘back to being an oil company,’ ‘oil story with a gas option,’ ‘a pro-liquids environment,’ ‘liquids factories,’ ‘low-cost-liquids acreage advantage’ and ‘the most misunderstood asset.’ Companies that have already shifted a majority of their production or revenue to liquids trumpeted that fact.”

None of the presenting E&P executives forecasted higher gas prices soon, he adds, in contrast to suggestions in investor presentations a year ago. “In fact, this year marked the first time no company was brave enough to suggest that gas prices were ‘temporarily low.’”

Zenker concludes, “The leveraged gas-growth story has lost much of its appeal. Indeed, many producers said they would not acquire dry gas acreage even at low prices. While producers have delivered the gas production story they promised last year, investors want something else.”

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Panelists include Joe Foster and Forrest Hoglund, Bobby Tudor and Jack Randall. Topics include international JVs, turning purchases into profit, what the money wants, what the deals will cost.

Want to be on top? Forrest Hoglund, Joe Foster, Charles Stephenson and Ted Collins will be in the house Aug. 30 at the 10th annual A&D Strategies & Opportunities conference in Dallas, presented by Oil and Gas Investor and A&D Watch.

In a special roundtable panel, these heavyweight-ranks, legendary deal-makers will tell tales from both sides of major purchases and divestments, how they got it right, how they made them right and how they knew which ones were wrong in “The Masters—Their Favorite Deals, The Ones That Got Away, And The Ones They’re Glad Got Away.”

Also on tap for this anniversary edition of the No. 1 E&P M&A gathering of the year are these powerful deal-makers and hot topics. Click for the full conference agenda. Click to register.

–Sheridan Production’s Lisa Stewart, QR Energy’s Alan Smith and Concho Resources’ Jack Harper will present on and discuss how their acquisition targets have fit their business strategy and how they’re generating a greater return on investment in “Field Reports—How These Producers Are Turning Purchases Into Profit.”

–International M&A advisor Bobby Tudor will provide the 411 on global energy capital access and demands and oil and gas markets.

–Fresh from inking a $15-billion sale to BHP Billiton Ltd., Petrohawk Energy Corp.’s Steve Herod will lead the roundtable discussion “The Metrics & Drivers–What Assets Cost,” including presentations by Albrecht & Associates’ Harrison Williams on “Cost & Competition For High-PDP (80%) vs. Low-PDP (20%) Plays;” Jefferies & Co.’s Bill Marko, who co-led two Chesapeake-CNOOC JVs on “JV Rewards: The Latest Deal Terms, Play By Play;” Tudor, Pickering, Holt’s Ward Polzin, who represented CNOOC in these deals, on “Conventional v. Unconventional: Cost Of Entry, Lease Renewal, Lease Expansion;” and RBC Richardson Barr’s Scott Richardson on “Cash Or Stock: The Latest Dynamics In Financing The Deal.”

–Energy M&A innovators Jack Randall and Ken Dewey, who founded Randall & Dewey in the supermajor divestment windfall of 1989, will share their prescience about A&D then and today in a spotlight Q&A as well as receive Oil and Gas Investor and A&D Watch’s “Lifetime A&D Achievement Award.”

–Global Hunter Securities’ Michael Bodino, who gave industry its first breakdown on the Tuscaloosa Marine Shale play in May at Hart’s DUO conference, will reveal U.S. conventional formations that are ripe targets for unconventional technology in “The New, ‘Old’ U.S. Oil Plays—Where Are They?”

–BNP Paribas’ David Marcell will present his ground-breaking formula for when to sell in “Defining the Exit Window.”

–Three-decade-long PE investor EnCap Investments’ Murphy Markham will lead the roundtable discussion “The Money—What Capital Sources Will Fund Today” with presentations by SandRidge drilling-trust leader Howard House of Raymond James on “The U.S. Drilling Trust and the New Canadian Royalty Trust;” longtime PE-to-E&P matchmaker Weidner Advisors’ Bill Weidner on “Private Equity For Big and Small;” Banc of America Merrill Lynch’s Randy King on “The JVs: What’s Next?;” and commercial-lending scorecard-keeper Macquarie Tristone’s Jon Goddard on “Energy Lenders’ Price Decks.”

–Netherland, Sewell & Associates’ Lance Binder will lead a discussion of “The Gas Glut & The Liquids-Rich Rush” with presentations by The Oil & Gas Asset Clearinghouse’s Ken Olive on “Oil v. Gas: The Bid/Ask Spread;” Madison Williams’ Sylvia Barnes on “Buy Gas Now;” and DrillingInfo’s Ramona Hovey on “Need a JV to HBP? Lease Expirations on the Horizon, Play by Play.”

Click for the full conference agenda. Click to register.

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

The source rock for nearly a century of Upper Smackover production is a new target as a horizontal oil play.

A hot new horizontal “dirty shale” carbonate/shale play may surface from the Lower Smackover’s Brown Dense. Here are some facts about the formation. For a new report, see “At Closing” in the September issue of Oil and Gas Investor online Sept. 1. Available online now from March 2011: Let’s Talk Some Smack(Over).

–The Brown Dense play is also known as the Lower Smackover Brown Dense or LSBD. It is a Jurassic-age, kerogen-rich, carbonate/shale source rock. It is a “dirty shale” in that it is mixed with carbonate. It is also described as an organically laminated, carbonate mudstone. And, it is at times called a limestone.

–The formation is found from East Texas to Florida. In northern Louisiana, it and its Upper and Middle Smackover members are just below the Haynesville shale play. In the area, Lower Smackover is at 8,000 to 11,000 feet and is between 300 and 530 feet thick.

–Southwestern Energy Co.’s new 460,000-net-acre leasehold is in southern Arkansas and northern Louisiana. It is at an 82% average net revenue interest. The average primary lease term is four years with four-year extensions. It was leased at an average of $326 per acre.

–Two horizontal wells are under way now—one by Southwestern in southern Arkansas and one by Devon Energy Corp., which has some 40,000 net acres over Brown Dense. The Southwestern horizontal, in Columbia County, Arkansas, will have a vertical depth of some 8,900 feet and lateral length of 3,500 feet.

–Rehan Rashid, E&P analyst for FBR Capital Markets, says total organic content (TOC) is high and carbonate content appears to be 40% to 60%.

–The oil is light at 40 to 50 API gravity. There may be high sulfur content (H2S). Upper Smackover production, since the 1920s and which is sourced from Lower Smackover, is sour. Sour hydrocarbons will need processing.

–Porosity and permeability appear to be similar to that of the Eagle Ford shale play, which is also a carbonate/shale mix or “dirty shale.” Southwestern says a piece of a core sample it tested from Brown Dense was brittle.

–In southern Arkansas, laterals of some 4,500 feet are all that is allowed. In Louisiana, between 6,000 and 8,000 feet is allowed.

–Core Lab calls Lower Smackover Brown Dense “one of the most prolific source rocks in the Gulf Coast Basin area.”

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Tudor, Pickering, Holt & Co. Securities Inc. analysts say Niobrara wells cost less but make less after-tax return on investment.

How does the horizontal Niobrara oil play in the Denver-Julesburg Basin of northeastern Colorado and southeastern Wyoming compare with the oily Bakken and Eagle Ford?

Tudor, Pickering, Holt & Co. Inc. analysts say there may be more original oil in place (OOIP) in the Niobrara (30 million barrels of oil equivalent per square mile, including chalk and marl/shale intervals) than in the Bakken (10- to 15 million) but less than in the Eagle Ford (30- to 50 million).

In the Niobrara, when considering OOIP in the “B” chalk bench only, which is thicker and has better porosity than two other chalk benches (A and C), the TPH analysts estimate 5- to 10 million BOE—or less OOIP per square mile than in the Bakken or Eagle Ford.

Also, reservoir pressure is lower in the Niobrara, so productivity and recovery are lower and less consistent on average. And, development is being slowed by that many leases are held by production from other formations. Thus, there is no rush to drill to hold the acreage for future development and operators are more willing to let other producers do the spending to crack the Niobrara well-design and fracture-stimulation code. In the Bakken, for example, most leases are new and expire within three to five years if not drilled, so there is more activity.

“Also, most operators are acquiring 3-D seismic to better understand the (Niobrara) reservoir prior to drilling,” says Jessica Chipman, a TPH analyst and lead author of a new Niobrara study.

As for well spacing in the Niobrara, this may be similar to or tighter than in the Bakken and Eagle Ford when there is little natural fracturing in the well target. The Niobrara formation has low “fracability,” Chipman says.

Niobrara wells may cost less, however, because the formation is at a shallower depth than Bakken and Eagle Ford and there are oilfield services in the area, while there are fewer services that are indigenous to the Bakken in western North Dakota and eastern Montana. A Niobrara well in the D-J Basin area may cost $3.5- to $5.5 million, drilled and completed, compared with $6- to $9 million in Eagle Ford and $7 to $12 million in Bakken.

Chipman adds that a Niobrara well in the more remote Powder River Basin may cost $7- to $9 million.

The D-J Basin also hosts other productive formations: three Niobrara chalk reservoirs, the Codell sandstone and the Fort Hays/Greenhorn limestones. “We expect these intervals will be tested for potential as stand-alone plays over the next few years.”

Yet, Niobrara wells in the D-J Basin may average a lower after-tax rate of return due to less recovery of hydrocarbons than being surfaced in Bakken and Eagle Ford. Using $60 to $100 oil and $4 to $6 gas, an average Niobrara well in the gassier Wattenberg Field area may return 10% to 45%-plus on the dollars invested, 15% to 60%-plus in oilier sweet spots outside Wattenberg and 0% to 15% in marginal areas outside Wattenberg.

 “These returns compare to 15% to 80%-plus in the Eagle Ford oil window and 15% to 200%-plus in the Bakken.” If the operator is able to tap a large, natural fracture system, the Niobrara return may improve significantly to between 100% and 200%-plus, she adds.

She and co-authors David Heikkinen and Brian Lively report, “It’s early days. We think the Niobrara now is where the Bakken was in 2005 as far as knowing which drilling and completion techniques work best and where the sweet spots and edges of the play are. A play in its infancy means more risk but potentially greater reward.”

They add that investors shouldn’t be turned off by that many Niobrara operators aren’t revealing much about their work in the play. “Many operators have kept public commentary close to the vest, so investors have formed a certain skepticism—a ‘no news means bad news’ view of the play. This lack of open discussion and resulting skepticism mean operators are lumped together with those we think are ‘doing the right things’ in the ‘better’ parts of the play undifferentiated from the rest.”

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

From folding card tables and lawn chairs for office furniture, Foster and team grew Newfield to 2 Tcfe proved.

“There’s ‘Joe time’ and there’s ordinary time,” former Newfield Exploration Co. board member Dale Zand tells Art Smith of Newfield founder and retired chairman Joe Foster in Smith’s new book, Something from Nothing: Joe B. Foster and the People Who Built Newfield Exploration Company.

“…Joe can see and understand a problem a hundred times faster than anyone else.”

Published this year, Smith explores how Foster led two dozen other former Tenneco Oil Co. professionals in the formation of Newfield in 1989 with a total of $9 million in employee and outside investments, growing the company to 2 trillion cubic feet equivalent of proved reserves upon his retirement in 2005.

Foster’s philosophy references Rudyard Kipling in “If:” “…If you can meet with Triumph and Disaster and treat those two impostors just the same…Yours is the Earth and everything that’s in it….”

Smith writes, “One of Foster’s strongest and most persistent characteristics as an oilman is his stoic acceptance of failures and setbacks. Success often follows failure and Foster has long viewed drilling dryholes as Babe Ruth did strikeouts. Like the Babe, Foster has no fear of setting ‘whiff’ records in the pursuit of home-run success. This anonymous quote is a favorite of Foster’s: ‘Failure is never fatal and success is never final.’”

Smith peppers the book with anecdotes and succinct descriptions, such as of Newfield’s early and ascetic days. For example, office furniture consisted of what employees, who were all owners, could put together, thus meetings were held at folding card tables complemented with an assortment of lawn chairs.

Spartan use of money was evident in a Wall Street Journal article in the early 1990s in which a Newfield platform in the Gulf was noted for its “kaleidoscope of colors.” The platform was made from components from other platforms and pieces were blue, red, yellow or gray.

Six-foot Foster and all Newfield employees flew coach class—even to Australia, a 26-hour flight. Investor-relations chief Steve Campbell, six foot four, joined Foster in coach on a flight to New York just two days after joining Newfield from Anadarko Petroleum Corp., which had a corporate jet. Upon landing at LaGuardia at almost midnight (Campbell tells Smith, “Joe likes to fly after business hours because it allowed you to get in a full day of work in the office.”), Foster told Campbell, “You know what I like about flying coach? It’s so damn uncomfortable you can get a lot of work done!”

And employees found cabs, not limos. During the company’s 1993 IPO road show, which involved meetings in Boston, New York, Chicago and on the West Coast (Foster says, “There sure is a lot more road than there is show in a road show.”), the Newfield team took cabs the first week. Bobby Tudor, a Goldman Sachs managing director at the time and now co-founder of Tudor, Pickering, Holt & Co. Securities Inc., was a co-manager of the IPO.

Smith writes, “The second week, (Tudor) said, ‘Look, Joe. We’re going to get limos and Goldman Sachs will pay for them…It’s not coming out of Newfield’s pocket.’ Tudor’s rationale was that arranging the logistics for all of them was just hell on the secretaries.”

And, about that IPO, Foster says he thought it might be too soon for Newfield, which had some 100 billion cubic feet equivalent of proved reserves at the time. Howard Newman, a managing director at the time of Warburg Pincus that was a second-round investor in Newfield and currently co-founder of Pine Brook Road Partners, emphasized that the IPO window was open at that time and it was unknown when it would be open again. Smith writes, “(Newman) passed on this gem of advice: ‘Joe, you take the cookies when the tray is passed—not just when you’re hungry.’”

In Foster’s hand-written notes (Foster carried a yellow legal pad to any meeting and made copious notes; longtime assistant and a founding Newfield employee Betty Smith says, “…We never ran out of them. That was one of my key jobs…to keep a good supply of yellow tablets.”) in early 1989 while forming Newfield, he lists what he will tell the troops two weeks into the effort. Among them: start-up pains are normal; Newfield will be data-driven; networking and exposure are essential but to take care that it isn’t taking more time than it is giving back; and “we must be prepared to live with failure.”

He concludes his list with this: “Finally, when we achieve success, we must not let it go to our heads.” Find Art Smith’s book here: Something from Nothing.

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Dear Ian,

In reading your June 25 online report “Insiders Sound an Alarm Amid a Natural Gas Rush,” it is apparent that the story, with the application of sincerity and more thoughtfulness, would have been titled “Shale-Gas Well Decline-Rate Criticism Unfounded.” You were on the cusp of the real story and missed it; it appears that great effort went into missing it.

Instead of simply pushing readers’ Enron and dotcom buttons via highlighting these words from critics’ e-mails, your report would have explained that the critics’ comparison of these with the shale-gas investment phenomenon is unfounded: Shale gas is a real asset; the Enron, or gas-marketing, bubble and the dotcom bubble were burst upon a lack of fundamental business principle — that is, to operate profitably.

As free and transparent markets work, investors themselves — those trading in and those trading out — define the ultimate boundary of an asset’s value on a daily basis. That boundary is tested 24/7; at times, such as in the case of the dotcom phenomenon, the correction can be gross, yet the dotcom business did not end — it simply was righted, just as the automaker industry found its way in the past century from dozens to the few best and how the home-ownership industry pushed to an ultimate test in this past decade, and tens of thousands more U.S. citizens are now enfranchised with property rights.

And, then, in your report, there are the anonymous critics themselves: They are provided to substantiate a scientific premise, yet the individuals themselves are unsubstantiated and not real assets in your story modeling. In reviewing the pages of e-mails with identifiers — although the remnants of their protocols are easily recognizable by industry — marked out, their commentary is merely that of friendly banter, envy or wonder, when read by one who understands the science behind forecasting decline rates, evaluating demonstrated decline rates from surfaced resources and, then, modeling in rate-of-return economics upon which an investment decision is made.

Your report lacks what would be easily demonstrable, as decline rates are no secret — they are on the surface, literally — and, while sophisticated, consist of simple math. Had the anonymous critics been asked to demonstrate this to you, your report would have been titled “Shale-Gas Well Decline-Rate Criticism Unfounded.” The business of evaluating decline rates is not mysterious and it is not taken lightly by oil and gas producers and by the investment community. Knowledge of it is easily obtained.

And, why provide safe harbor of anonymity for these critics anyway? There is regular debate and diligent effort within the oil and gas industry — as it is a science- and, thus, math-based business — on best practices, from well placement to completion method to reinvesting returns. This debate is conducted internally within oil and gas companies on a daily basis and also in open sessions at professional-organization symposiums and even in oil and gas producers’ regular investor conference calls.

Why, then, does criticism of this have to be secreted with anonymity? Are the critics anonymous because identifying them would show your readers that they lack credentials in contrast with that of members of an industry of hundreds of thousands who drill wells and are accountable for their profitability?

The energy analyst John Olson signed his name to his early 2001 report that said something was amuck at Enron. Alan Greenspan publicly stated he believed there was irrational exuberance in public markets in 1996 and devotes a chapter to his reason for this in his autobiography. Yet, your sources cannot do the same — sign their name to their statements? And, yet, your report’s intent is to affect the value of hundreds of billions of dollars of public and private investment in U.S. shale-gas resources?

These are incongruous.

The market for shale-gas stories is regularly corrected as wells work out and wells don’t work out, and simultaneously by user-market appetite for the natural gas itself. In mid-2008, for example, natural gas prices began to fall, thus the value of both shale-gas and all other gas wells — and not due to any change in the wells’ performance, but upon the application of simple business math, that is X$=X$ and X$-50%=0.50/X$.

In fact, shale-gas stories are out of favor in the short-term-investment marketplace today — not for poor well performance but because of the low price of the product the shales are making so well and, thus, is a contrarian investment opportunity for longer-term investors, who understand decline rates and that there will be gas — and years from now.

Alas, those who seek unsubstantiated journalism get unsubstantiated journalism. Your report suggests “sell your gas holdings now,” while the smart money is buying in.

It’s unfortunate you have burned your very own readers too.

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.