While nearly 1,400 E&P, oilfield-service and financial leaders were hearing executives’ Marcellus reports at Oil and Gas Investor and E&P’s Developing Unconventional Gas—East conference in Pittsburgh recently, many attendees followed presenters to post-presentation Q&A sessions to drill for more intelligence on the surface and subsurface details of the play. Here are some of their remarks.

Question: While gas prices are so low right now, why does everyone continue to drill as hard as they can, particularly in the Marcellus?

Jeff Ventura, president and chief operating officer, Range Resources Corp.: All companies are going to high-grade and direct cash flow into the strongest projects they have. We’ve compared the Marcellus against the Haynesville, Fayetteville, Barnett. The Marcellus’ economics are the most robust.

Q: What about spacing and the potential to double the number of wells?

Ventura: If you look at other gas fields, with time spacing tends to get tighter and recoveries tend to go up, and I think you have the potential for that in the Marcellus.

Q: What gas price do you need in the Marcellus?

Murry Gerber, chairman and chief executive officer, EQT Corp.: Our wells are in the $3-million range, and the reserves are in the 3.5-Bcf (billion-cubic-foot) per-well range. We break even at $2.50 natural gas, Nymex. We make another 10% after-tax return. So, somewhere between $3.50 and $4.

Q: What is the Appalachian market for propane and ethane?

Gerber: The Appalachian region is a net importer of propane. I was surprised by that, but it is a net importer. So, that’s relatively easy to dispose of. If you’ve got a good use for ethane, we’d like to find that out. We need to think of ethane as a benefit, not as a problem. This is the most amazing thing that’s happened to us here. I’m not sure we know it.

Q: You tested verticals at first.

Mike Walen, senior vice president and COO, Cabot Oil & Gas Corp.: We drilled our first vertical well in the Marcellus in 2006, the Teal #1. The original completion on the vertical well was 7 million cubic feet a day.

Q: On a vertical well?

Walen: On a vertical well, yes. That was our test, and that was a 24-hour test. It caught our attention; we kept it quiet. We went in and drilled an offset. It tested very, very similarly. We picked up more leases. The geochemistry of these rocks was vastly superior to what we were expecting.

Q: How does the lack of forced pooling in Pennsylvania affect drilling?

Rich Weber, president and COO, Atlas Energy Resources LLC: Pooling will negate the need to drill vertical wells along irregular lease lines and will be very good for development—for the producers and the land-holders. If we don’t have some sort of unitization law in Pennsylvania, producers are going to have to drill vertical wells along irregular lease lines if they want to fully develop their acreage.

Q: What is your biggest challenge?

Weber: We produce about $300 million a year in free cash flow. We will be dedicating all of that to the Marcellus, but our position is so large it would take us over 35 years to develop it at that pace.

            Q: What are the technology gaps in the Marcellus?

Aubrey McClendon, chairman and CEO, Chesapeake Energy Corp.: Remember, from northeastern to southwestern Pennsylvania, it’s basically the difference between the Haynesville and the Barnett. That’s an enormous piece of real estate, so there will be a lot of differences.

Q: How much potential does the Marcellus hold?

McClendon: We’re only getting 25% to 30% of the gas out of these (and other shale) rocks. We’re going to find ways to extract that additional 5%, 10%, 15%, 20%. It’s one of the reasons I wanted to own so much acreage in shale plays. I really think they are “forever” assets—you will be looking back 20, 30, 40, 50 years from now and see that the winners were people who recognized the value of these assets and how they would get better and better over time.

For full transcripts of each of these Q&A sessions, see the Marcellus Week series of webcasts of DUG—East presentations.

–Nissa Darbonne (ndarbonne@hartenergy.com), E-Editor, Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com Today, OilandGasInvestor.com, A-Dcenter.com, UGcenter.com.

Three of the largest M&A deals of the past couple of months have been for oil-weighted producers, and all three buyers are funds—one private equity and two special-purpose acquisition companies (SPACs). Publicly held SPAC United Refining Energy Corp. has bid $580 million for privately held Chaparral Energy Inc., whose 146 million barrels of oil equivalent (BOE) are 62% oil. Edge Petroleum Corp. planned to buy Chaparral last year but the deal fell through over post-commodity-price-collapse financing, and Edge is now in Chapter 11 proceedings.

            Tom Hicks’ publicly held SPAC Hicks Acquisition Co. I has purchased Nick Sutton’s privately held Resolute Energy Corp., which owns 49.3 million proved BOE of which 91% is oil. And, private-equity firm Apollo Global Management LLC will buy oil-weighted Parallel Petroleum Corp. for $483 million, after having failed to win its bid for oily producer Legacy Reserves LP earlier this year as oil prices grew and Apollo’s bid did not.

Another oil-weighted producer, Ram Resources Inc. president Larry Lee noted when the company’s borrowing base was affirmed last month “the cash-flow yield from our production mix, 59% of which is driven by the price of oil.”

Private investment-fund manager Jim Wicklund of Carlson Capital LLC told Energy Capital Week attendees this June, “What hedge funds love right now is oily and shaley. If you are a conventional gas producer, you need to get a white suit and dance like John Travolta. You are so passé, it is almost scary.”

Shaley Oil No. 1 is the Williston Basin’s Bakken and Three Forks-Sanish formations.“We are in the first inning of what is already and will be one of the largest oil discoveries in North America,” says Jefferies & Co. senior E&P analyst Subash Chandra in a recent OilandGasInvestor.com-hosted webinar. “We’re probably talking about billions of barrels of recoverable oil that can come out of this play.”

Chandra couldn’t cite a single Bakken disqualifier. The play, centered around Montrail County, North Dakota, is producing better and better wells, its economics work at lower oil prices, incidences of success are spreading in the play, and the number of potentially successful well locations is underestimated by Wall Street, he says.

“There are legitimately 1,000s of locations that Wall Street has yet to get its hands around.” Results so far suggest Middle Bakken wells produce independent of the Three Forks-Sanish formation. “We are not draining the Three Forks with a Bakken well…so we can pretty much double these locations over time.”

Several Bakken-weighted producers’ stock prices in 2009 have grown between 50% and 700%, including Whiting Petroleum Corp., Brigham Exploration Co., Kodiak Oil & Gas Corp., GeoResources Inc., Northern Oil & Gas Inc. and Continental Resources Inc. Their 2009 returns have also outperformed the Amex Oil Index.

While Bakken producers’ stock prices include great expectations for the play, expectations can be greater, Chandra says. “There isn’t a single Bakken company that can’t earn its premium over time and…earn an even higher one.”

He estimates the average Bakken well is economic at $50 Nymex oil, assuming a $7.50 basis differential. Nymex oil was approximately $76 at press time.

Also at press time, C.K. Cooper & Co. analyst Sven Del Pozzo launched coverage of “oil rich” Whiting “whose operating leverage and recently declining debt load put it on the cusp of delivering much-stronger operating cash flows under $70 perpetual Nymex oil.”

In contrast, U.S. shale-gas producers’ stock prices have grown between 10% and 80%, including Chesapeake Energy Corp. (all major U.S. shale-gas plays), Southwestern Energy Co. (mostly the Fayetteville), Devon Energy Corp. (Barnett and Haynesville) and Range Resources Corp. (Barnett and Marcellus).

The contrarian buy is gas. Tudor, Pickering, Holt & Co. analyst Dan Pickering stands by his “$7.50 in 2010” forecast. He and fellow analysts reported at press time: “Remember: Gas supply is falling like a rock.” On Chesapeake, nearly 100% weighted to U.S. natural gas, “you’ll make lots of money buying…Keep doing it.”

–Nissa Darbonne (ndarbonne@hartenergy.com), E-Editor, Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com Today, OilandGasInvestor.com, A-Dcenter.com, UGcenter.com.

“There are excellent opportunities for savvy U.S. independents….”

The world awaits U.S. unconventional gas producers’ expertise in unlocking reserves across the world—with Europe possibly the most anxious, according to panelists in the webinar Translating The Profit Overseas: International Unconventional Gas Opportunities, And The Macro Global Gas-Price Forecast now available on demand.

“There are excellent opportunities for savvy U.S. independents who have the technologies and management experience, and the opportunities are best in those countries where there are established unconventional resources and high-priority energy needs,” says Dr. Pete Stark, vice president, industry relations, for IHS Inc.

Stark describes coalbed-methane, tight-gas and shale-gas reservoirs across the globe. In a spotlight on European unconventional resources, he says, “The shale gas area is the hot new area of interest. I was intrigued to learn only recently the distribution of the recent shale licenses in southern France, also just west of Switzerland and farther to the north in easternmost France. Those projects are of great interest but there is not a lot of detail on them yet.”

More shale-gas exploration is under way in Germany (by ExxonMobil Corp.) and in Poland. OMV has identified shale gas in Austria. Producers exploring the continent’s shale, besides ExxonMobil and OMV, include ConocoPhillips, Toreador Resources Corp., BNK Petroleum Inc., Composite Energy Ltd., EUR Energy, Layne Energy, San Leon Energy Plc, Schuepbach Energy LLC and Total SA.

“Europe is a target because it has unconventional resources; it has low entry costs, very attractive fiscal regimes, and a stable regulatory environment; and it already has pipeline infrastructure. Also, there is strong demand and gas prices, and there is an energy security need as well.”

Charles De Jager, partner with law firm Mayer Brown and based in Brussels, advising foreign interests on gaining access to European Union markets, says gas supply is a top issue again since the European gas crisis of January 2009—not the first time Russia has cut off gas supply to many European countries as a result of a dispute with Ukraine.

“This really served to refocus people’s attention on the issue of security of gas supply,” De Jager says. “As a result, the EU has embarked on a fairly rapid process, by EU standards, for the review of the legislation that governs security of gas supply.”

A growing amount of European gas is from sources other than Russia. “Gazprom, in recent years, has lost approximately one third of its European market, primarily to Norway, Trinidad and Qatar. So, Gazprom’s shenanigans up to now have certainly cost it a certain part of its European market.”

Except for two net gas producers among the EU’s 27 member countries, all are net importers. Among these, nearly all import 80% or more of their gas supply, at times 100%. “Four of the big five European economies are almost entirely reliant on gas imports,” De Jager says. EU dependence on imported gas is some 60% overall.

U.S. producers’ domestic efforts are going without market-price recognition, notes Laurent Key, associate in the U.S. commodities research group for Societe Generale’s corporate and investment-banking unit. “We should experience more recovery of industrial demand, even in the bearish scenario, but we will remain below the 2008 level and well below 2007 levels,” he says. “Many people in the market talk about the peak U.S. industrial gas demand in the U.S. as being long ago, in 2004 and 2005.”

How U.S. prices fare going forward depends on many variables. “When we talk to producers…just a small survey told us that more than 80% of U.S. production is hedged for 2010, 2011 and 2012, so this is why we have such an increasing trend in U.S. production.”

When will unconventional-gas exploitation find full speed in Europe? “We’re not going to see a four- to five-year ramp-up period in European shales,” Stark says. Unless an exploration company hits a quick home-run find, “we’re going to see a four- to five-year demonstration period (and if promising, then) some M&A activity and partnering to bring more capital and know-how to speed the process.”

The presenters’ full remarks, and their slides, including maps, tables and graphics, are available for viewing and download on demand at Translating The Profit Overseas: International Unconventional Gas Opportunities, And The Macro Global Gas-Price Forecast.

–Nissa Darbonne (ndarbonne@hartenergy.com), E-Editor, Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com Today, OilandGasInvestor.com, A-Dcenter.com, UGcenter.com.

It’s a sign o’ the popular Marcellus shale-gas times!

More than 800 individuals pre-registered for Hart Energy Publishing’s inaugural Developing Unconventional Gas (DUG) East conference—and hotel capacity was, well, approx. 800.

The event—this Oct. 19 in Pittsburgh—sold out in just a few weeks of open registration. And, it’s been moved now to the David L. Lawrence Convention Center, adjacent to the original event site, the downtown Westin.

With expanded capacity roughly 200 stand-by registrants who were wait-listed now have a seat, and more registrations are under way, plus openings of exhibition space.

“DUG East is bucking the trend of nearly every B2B conference in the U.S.,” says Rich Eichler, Hart president and chief executive. “I cannot think of a stronger endorsement of Hart’s position as the leader in unconventional resource and specifically Marcellus shale content, than to have to relocate this event, due to popular demand, in the current economic environment.”

Speakers will include:

– Aubrey McClendon, chairman and CEO, Chesapeake Energy Corp.,

– Jeff Ventura, president and COO, Range Resources Corp.,

– Murry Gerber, chairman and CEO, EQT Corp.,

– Mike Walen, senior vice president and COO, Cabot Oil & Gas Corp.,

– Ben Hulbert, CEO, Rex Energy Corp.,

– Randall Albert, senior vice president, emerging business unit, CNX Gas Corp. and

– Frank Semple, CEO, MarkWest Energy.

Topics include improving well results, reducing drilling costs, taking gas to market, geology, resource potential and technology. For more details, click to DUG East.

–Nissa Darbonne (ndarbonne@hartenergy.com), E-Editor, Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com Today, OilandGasInvestor.com, A-Dcenter.com, UGcenter.com.

Can the Bakken unconventional oil play in North Dakota get any better? Yes, it can.

“We are in the first inning of what is already and will be one of the largest oil discoveries in North America,” says Subash Chandra managing director and senior equity research analyst, U.S. E&P, for Jefferies & Co. in the webinar The Renewed Bakken/Three Forks-Sanish: Economics, Well Results, Technological Advancements now available on demand.

“We’re probably talking about billions of barrels of recoverable oil that can come out of this play.” The play, centered around Montrail County, North Dakota, is producing better and better wells, its economics work at lower oil prices, incidences of success is spreading in the play, and the number of potentially successful well locations is underestimated by Wall Street, he says.

“There are legitimately 1000s of locations that Wall Street has yet to get its hands around.”

Results so far suggest Middle Bakken wells produce independent of the Three Forks-Sanish formation. “We are not draining the Three Forks with a Bakken well…so we can pretty much double these locations over time.”

Bakken producers’ stock prices include great expectations for the play, but expectations can be greater, Chandra says. “There isn’t a single Bakken company that can’t earn its premium over time and…earn an even higher one.”

He estimates the average Bakken well is economic at $50 Nymex oil, assuming a $7.50 basis differential, which isn’t the best or the worst differential but is a “pretty decent one.” Nymex oil was approximately $67 this morning (Sept. 24, 2009). “It is exceptionally economic at these levels.”

Initial production (IP) is also showing a direct correlation to 30-day average production (AP), suggesting estimated ultimate recovery (EUR) of many Bakken wells of 500,000 to 600,000 barrels or more. An AP of 500 to 600 barrels a day is required to be considered a good well. And, “we are seeing a lot more of these 1,000 to 1,200-barrel-per-day wells,” he adds.

Brigham Exploration Co. (Nasdaq: BEXP) has had APs of 1,1,41 and 919, for example; XTO Energy Inc. (NYSE: XTO), 860; and Whiting Petroleum Corp. (NYSE: WLL), 1,543, 1,086, 1,309, 901, 1,034 and 983.

Is play technology overcoming nature? “We are finding, with every passing well, that it can…There are no bad wells in the Bakken (generally); there are underestimated wells in the Bakken.”

Finding and development (F&D) costs are declining, while wells are proving more reserves. “Most can be done for approximately $12-a-barrel F&D…To do that in the oil world is absolutely exceptional.”

Chandra just returned from a Bakken field trip for investors and analysts with Brigham. “Investor interest was very high,” he reports. One trip attendee who advises investors and has worked in oil fields across the world. “He said he hasn’t seen any opportunity like the Bakken.”

Chandra is joined in the program by Lynn Peterson, president and chief executive officer of Kodiak Oil & Gas Corp., describing Kodiak’s results and economics in the Bakken. “We do believe there are two reservoirs (the Bakken and Three Forks),” Peterson says. “…The Three Forks could be nearly what the Bakken is.”

He estimates that, at an average EUR per well of 650,000, $70 Nymex oil and a $9 basis differential, “we’re looking at a rate of return of some 80% or better.” Kodiak’s acreage was tied up in permitting and other hurdles until recently. “That primarily explains why this area was under-leased and under-explored…A lot of these issues are behind us now.”

John Harju, associate director for research for the Energy & Environmental Research Center (EERC) at the University of North Dakota, says the Bakken has been extremely receptive to technology. “The Bakken is a place where we have an astounding rate of technological innovation.” Harju describes current fracture-stimulation practices, lateral lengths, the efficacy of gel and slickwater, and other drilling and completion practices in the play.

The archive of the program is now available on demand, including presenters’ slides: The Renewed Bakken/Three Forks-Sanish: Economics, Well Results, Technological Advancements.

–Nissa Darbonne (ndarbonne@hartenergy.com), E-Editor, Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com Today, OilandGasInvestor.com, A-Dcenter.com, UGcenter.com.

“We’ve seen a lot of bills wax and wane—no pun intended—a number of times over the years.” Waxman-Markey may go the way of the rest.

Traders aren’t factoring in futures prices any expectation of Washington legislating greater natural gas use. “If you were looking at only the natural gas market, no, you wouldn’t find it,” says Keith Barnett, director of strategic analysis for Merrill Lynch Global Commodities, in the webinar The Carbon Challenge: Impact On The Natural Gas Sector presented by Hart Energy Publishing LP.

            If looking at futures for off-peak power in regions that have a lot of coal as part of it, traders are factoring in some belief that the Waxman-Markey bill will create some price fluctuation, he says.

Frankly, though, Barnett says of gas and other energy traders, “We’ve seen a lot of bills wax and wane—no pun intended—a number of times over the years.” Waxman-Markey may go the way of the rest.

As it stands now, Waxman-Markey should go the way of the rest—defeated—says Rod Lowman, president and CEO of America’s Natural Gas Alliance, which consists of 28 U.S. natural gas producers of more than 40% of daily supply. “We could not support Waxman-Markey as it stands now.” Within the 1,428-page document, little mention is made of natural gas.

Lowman says Congress is coming to understand that the U.S. has plentiful natural gas supply, both already surfaced and readily producible. “Shale and shale-gas plays have changed everything…This is going to be a global phenomenon—that we are going to have a lot of natural gas.”

What to do with all that gas? Some reports are that North American LNG receiving terminals may reverse flow to export LNG. Barnett says, “Yes, two Gulf Coast terminals (at Sabine Pass and Freeport) have DOE approval to export what was imported.” Two terminals in British Columbia may commence exporting LNG as well.

Jim Slutz, managing director of Global Energy Strategies LLC, notes that the U.S. already exports domestic gas production from Alaska (to Japan by DOE permission) and some southern U.S. production is exported, on a net basis, to Mexico.

Otherwise, North American gas supply is stranded, in a way.

Barnett says, “I have long thought that the ability to export LNG should not be inhibited by LDCs (local distribution companies). Exporting (U.S. gas) allows the market to balance itself and sends appropriate price signals, and we would be exporting to two of our strongest allies—the U.K. and Japan.”

The Merrill Lynch analysis team believes the Nymex gas price will struggle to exceed $4 for the balance of 2009, due to rapidly diminishing odds of many or any powerful Gulf of Mexico hurricanes this season, storage nearly full in the U.S. and Canada, and new LNG supply expected in the fourth quarter. “We’re obviously going to be in an oversupply situation in the back half of 2009,” Barnett says.

For 2010, the outlook is mixed. “The bulls are afraid of (a continued sluggish) economy and of more LNG imports and the bears are afraid of production declines.” Most economists expect slow U.S. growth in 2010, and a second wave of LNG imports is expected in the summer and fall, he adds.

Most forecasts among gas analysts across many firms expect prices to range from $2.50 to $8—generally between the cash cost and marginal plays’ life-cycle investment costs—during the next two to four years. Some forecasts are for $8 or nearly $8 in the latter half of 2010. “I’m less sanguine,” Barnett says. New LNG supply will keep Henry Hub gas prices well below $8.

For more of the presenters’ remarks, and for their slides, click for the webinar The Carbon Challenge: Impact On The Natural Gas Sector now available on demand. For information on The Carbon Challenge 11-part series of webinars, click to HartCarbon.com.

–Nissa Darbonne (ndarbonne@hartenergy.com), E-Editor, Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com Today, OilandGasInvestor.com, A-Dcenter.com, UGcenter.com.

J. Robert Ransone, president and chief operating officer for Plano, Texas-based Barnes Oil & Gas LLC, has received the inaugural A&D Achievement Award from Oil and Gas Investor magazine and A&D Watch newsletter for his contributions to forums for intelligence-gathering and improvements in oil and gas property acquisition and divestiture best practices.

Ransone was recognized at the eighth annual A&D Strategies and Opportunities conference in Dallas on Sept. 2, 2009. The conference, co-founded and co-presented by Oil and Gas Investor and A&D Watch in 2002, is among Ransone’s achievements in promoting further professional development in oil and gas A&D.

Ransone had already co-founded the Dallas-based ADAM Energy Forum in 1994 as a networking and information-sharing organization for Dallas- and Fort Worth-area A&D professionals, when taking on the goal of an A&D conference.

“Robert called Bob Jarvis, our publisher at the time (who is now vice president of membership, business development and capital markets for IPAA), one day in late 2001 or early 2002 and said, ‘Bob, we need an A&D conference in Dallas,’” says Nissa Darbonne, editor of A&D Watch at the time and now e-editor for its publisher, Hart Energy Publishing LP.

“Soon, Bob and I were visiting with Robert and developing an agenda. The first conference was hosted in September 2002 in North Dallas. It moved to The Fairmont downtown in 2003 and has been held here since.”

Attendees the first year numbered some 130, including speakers; the event has grown to host more than 550 leading E&P-company asset buyers and sellers, financiers, property marketers, business analysts, advisors and investors.

Keynote speakers have included Ray Hunt, chairman, president and CEO of Hunt Oil Co.; Aubrey K. McClendon, chairman, president and CEO of Chesapeake Energy Corp.; Peter Barker-Homek, CEO of TAQA-Abu Dhabi National Energy Co.; T. Boone Pickens, chairman of BP Capital; Keith Rattie, chairman, president and CEO of Questar Corp.; Keith Hutton, CEO of XTO Energy Inc.; the late Frank Pitts, founder of Pitts Oil Co.; Tom Petrie, vice chairman of Merrill Lynch; Al Walker, COO of Anadarko Petroleum Corp.; Don Wolf, chairman of Quantum Resources Management; John Walker, chairman, president and CEO, EV Energy Partners and EnerVest Management Co.; Clayton Williams, founder and chairman of Clayton Williams Energy Inc.; Dan Pickering, co-president and head of research for Tudor, Pickering, Holt & Co. LLC; and Art Smith, former chairman, IHS Herold.

The one-day conference has grown to include live-streaming of proceedings via the Internet in each of the past two years, and a half-day workshop, including a “Let’s Make A Deal” lab.

Meanwhile, ADAM Energy Forum has grown to more than 275 members from energy companies in five states.

Ransone says of co-founding ADAM Energy Forum of which he was president from 1997-2003 and remains an officer and trustee, “This was in 1994 and David Rice, at The Wiser Oil Co. then, suggested we put a group together. We began having luncheons, and then invited speakers and started formal memberships and dues.”

The first A&D Strategies and Opportunities conference in September 2002 was booked for a Westin hotel in North Dallas, but hotel management pushed the event to a closed Sheraton next door when a larger event requested the Westin date. “We called it the ‘ghost hotel,’” Ransone says of the unexpected venue, “but we had it to ourselves and we had a great start to this conference.”

From 2005 to 2007, Ransone was a partner with responsibility for A&D with Duer Wagner III. From 2004-05, he was vice president of business development and CFO for Five States Energy LLC, which owned more than $300 million of oil and gas producing properties. At Five States, in addition to his duties as CFO, he oversaw A&D. From 1995 to 2004, he was founding partner, president and CEO of asset marketer Wellspring Partners LLC, which enabled more than $850 million in oil and gas acquisitions and divestitures. In 2004, he sold Wellspring to PLS, another asset marketer.

In addition, Ransone advises Stanford University with respect to investments in the petroleum sector. He currently serves on the Dallas Wildcat Committee of the Dallas Petroleum Club and he has served on numerous other committees of the club, is a past regional director and member of the board of directors of the Independent Petroleum Association of America (IPAA), and a past president and current board member of the Texas Energy Council (TEC) and past vice president and board member of the Texas Alliance of Energy Producers.

“Hope is not a ‘strategy.’ Your banker does not want to hear that everything is going to be fine once natural gas prices improve,” says Carl Stutzman, senior vice president and manager of Union Bank’s petroleum commercial-lending group, in the recent webinar Forecasts For The Fallout From Fall Bank Redeterminations.

“Have a realistic game plan with actions that are within (your) control,” he says of working with lenders year-round and during this fall’s bi-annual borrowing-base redetermination season.

            “Hope is probably also not a ‘confirmable plan’” in bankruptcy court, adds Trey Wood, a Houston-based partner with law firm Bracewell & Guiliani LLP and specializing in business reorganizations and Chapter 7, 11 and 13 bankruptcy cases. “At the end of the day, what the plan has to be is ‘fair and equitable.’” If unwilling to negotiate, “you will get into a very expensive fight…to declare what is fair and equitable.”

            Banks themselves have undergone tremendous transition this past year, and many continue to work to find their footing. “The nice person who used to be your commercial banker is now a sort of neurotic mess,” Stutzman says.

            There are challenges even within E&P companies’ lender groups, he adds. “We have probably spent as much time dealing with dysfunctional bank groups (this past year) where we are lead agent (on a facility) than with the client…(And, within the lender group) sometimes we are forced to solve to the lowest common denominator as the agent bank is unable to take out an uncooperative lender.”

            His forecast for the upcoming redetermination season? “We expect this to be a more challenging period…We’re all worried about gas prices…We’ve all pretty much given up at this point as to when that (gas-price improvement) is going to happen.”

Wood says prospective oil and gas asset buyers see distressed E&Ps file bankruptcy in various federal court districts. “The reason often is they’re looking for a friendly judge.”

Potential “debtor in possession” financing can come from DIP lenders, second/junior lien-holders, existing equity, new investors (e.g. loan to own), existing first-lien lenders (a defensive DIP strategy) and vendor financing.

“Vendors aren’t in the business of lending money, but they will do it often to protect (the debt already owed)…but they will want a primary lien on existing program wells,” Wood says. Vendor financing is also expensive: It’s at 100% cost, plus a risk premium of as much as 25%, plus interest and cost.

Distressed E&Ps, and their lenders, also face a lower-priced asset market than a year ago, Stutzman notes. “It’s a soft A&D market out there.”

Chris Simon, managing director, investment banking, and head of asset A&D for Raymond James & Associates Inc., says, “We are well below the prior year’s (market prices)…in almost all cases.”

Prices for gas-weighted assets have plummeted most. Here’s the current environment, Simon says: Buyers are using strip prices, PDP net present value discount rates have risen to above 10% and as high as 15%, many gas PUDs are uneconomic at today’s prices but look better in next year’s budget, valuation metrics are showing signs of improvement, oil-weighted assets are realizing attractive metrics in line with 2004-07 metrics, and sellers are considering selling their oil-weighted assets.

“(Buyers are) having to stretch a bit beyond the PDP for the nonproducing reserves,” he adds.

Most buying and selling this year has been of oily Permian Basin properties. “By far the largest volume of deals has been in the Permian…As for shale, the greatest activity has been (the joint venture)—foreign buyers interested in learning the technology and taking it back to their country and acreage programs.”

            Will seemingly healthy E&Ps form a line at bankruptcy courts this fall? Stutzman says, “I have been pleasantly surprised by how proactive E&P companies have been, including in accessing the (public) debt and equity markets (when open). For the most part, our public E&P companies look healthy.” Bankruptcy filings may more likely come from private E&Ps that may have already been struggling, he says.

            Simon says, “Some gas assets will be forced onto the market due to distressed situations.”

            Wood concludes, “Most of the lenders are going to work through this process…You are going to see more out-of-court restructurings than bankruptcy filings.”

            Stutzman says of the upcoming borrowing-base redetermination season, “Be completely open and honest, even if it’s bad news.” Also:

            – The restructuring plan must address both asset value and cash-flow coverage.

            – Take bold steps quickly. Plan on lengthy meetings and information requests from lenders. Expect a thorough review of the loan/collateral documentation. Anticipate the banks’ desire to reduce “hold” levels. And, be prepared to have the deal repriced and to pay fees for amendments.

            “Banks really do want to work with their borrowers to solve problems,” Stutzman says. “…Bankruptcies and foreclosures really destroy value.”

            For the presenters’ remarks, and to download their slides, click to Forecasts For The Fallout From Fall Bank Redeterminations now available on demand.

–Nissa Darbonne (ndarbonne@hartenergy.com), E-Editor, Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com Today, OilandGasInvestor.com, A-Dcenter.com, UGcenter.com.

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–Nissa Darbonne (ndarbonne@hartenergy.com), E-Editor, Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com Today, OilandGasInvestor.com, A-Dcenter.com, UGcenter.com.

“It would be a viable option if someone were to take up the battle to pursue exporting more gas out of the U.S.”

Will U.S. gas-storage centers and pipelines be overfull in coming months? Will pipelines have to turn producers away?

This isn’t an exaggeration, says Justin Carlson, senior energy analyst for Denver-based energy-research firm Bentek Energy LLC, in the Aug. 20 webinar “The Haynesville Bottom Line: Leasing, Take-Away, Well Results” now available for viewing on demand.

“Right now, we estimate that, on a daily basis, (the U.S. is) more than 2 Bcf/day long on gas. We are building storage at 2 Bcf a day. From a pure inventory standpoint, we don’t have the capacity to take that much gas. We don’t have anywhere to put it. Nor do we have a demand market to absorb that gas….”

Will an improved U.S. economy deplete the excess? “At 2 Bcf long a day, I don’t think even an economic turnaround is enough demand to help absorb the excess gas we have.

“(For the) Haynesville producers or Fayetteville producers or any of the big shale producers—or if you want to go all the way to the Granite Wash and down to the Eagle Ford—drill times and efficiencies have gotten so good that it is simply a manufacturing process.

“It’s (a) gas on demand (supply market) and we can produce it fairly quick to meet any incremental demand from the market.”

Could this excess natural gas be exported? “Certainly that’s an option, but there are some barriers to that. There is a lot of red tape to get through. We have Kitimat (LNG import) facility in (British Columbia) Canada that will start doing it. The Louisiana facility at Sabine Pass and the facility at Freeport, Texas, will start re-exporting gas that is brought in or they have authorization to export a limited amount.

“We’ve got a lot of gas here. I don’t know the total U.S. reserves, but we certainly have a lot of gas and it would be a viable option if someone were take up the battle to pursue exporting more gas out of the U.S., but then you’re competing with a lot of other countries (to sell this gas to other) demand markets.

“I don’t know the exact amount of LNG (export) capacity expected to come online in the next several years, but it’s a lot, so the U.S. would be competing with a market that’s flooded with a lot of LNG out there.”

The Aug. 20 webinar including Carlson’s remarks, along with remarks by DrillingInfo’s Ramona Hovey on Haynesville leasing and by Object Reservoir’s Dr. Joel Walls on Haynesville drilling results, is now available on demand at OilandGasInvestor.com: “The Haynesville Bottom Line: Leasing, Take-Away, Well Results.”

–Nissa Darbonne

–Nissa Darbonne (ndarbonne@hartenergy.com), E-Editor, Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com Today, OilandGasInvestor.com, A-Dcenter.com, UGcenter.com.