Energy Matters

Investors are opening their wallets to energy-company equity and debt offerings again. In a 24-hour period in early June, Pennsylvania-based onshore- and unconventional-focused producer Penn Virginia Corp. and Gulf of Mexico-focused Mariner Energy Inc., which has Permian Basin interests too, were each able to increase their $250-million, senior-notes-offering expectations to $300 million when the gates opened. Mariner was also able to increase its 10-million-share offering to 11.5 million.

Meanwhile, Gulf-focused Stone Energy Corp., which also has some interests in the Marcellus shale, was able to sell 7 million shares, up from an initial expectation of placing 6 million.

At press time, onshore-focused EV Energy Partners LP sold 4 million units, up from the initially set 3.5 million, and at a higher price per unit than expected upon the offering’s launch.

Just four weeks earlier, a few producers hit the wrong side of the up-one-week-and-down-another market for energy stocks. Haynesville-focused GMX Resources Inc.’s 5-million-share offering priced at $12 each, raising $60 million. When brought to the table only days earlier, the share price had been $17. It fell to $15 while brokers were opening the phone lines and to $12 at closing, leaving $25 million un-won.

Delta Petroleum Corp. was caught in this dust devil as well. It had already withdrawn a stock offering earlier this year that was to raise some $170 million to right its debt profile, expecting to price some 58 million shares at $3 each, but the stock was already trading at under $2 and fell to under $1 shortly thereafter. Delta withdrew the offering, and its lenders extended a reprieve.

In early May, the stock price was some $2.50, and Delta gave the offering another go. Before pricing, though, shares fell to $1.50. It proceeded, nonetheless, issuing 150 million shares, instead of 70 million, and raising $225 million, with major shareholder Tracinda Corp. buying $90-million worth.

Delta’s is among some stock prices that has swung wildly all year—from being up 24% one week to down 47% another week, and several others. The company appears among the top 5 U.S. E&P stocks for percentage up or down in one week for 11 weeks so far this year—five times for being among most improved; six times for being among most disappointing—according to Oil and Gas Investor This Week’s summary prepared by Tristone Capital.

The up-and-down trend among energy stocks became so transparent that it became easy to predict when stock prices would be up again (next week) and down again (the next). For example, for the week ending May 15, only three U.S. E&P stocks’ prices had improved; all others lost market value, including as much as 33% for onshore -focused Brigham Exploration Co., which has a large Bakken holding.

One week later, most E&P stock prices had improved—as much as 22% for ATP Oil & Gas Corp.

How reticent had capital-raising become since this past summer? The regular “New Financings” feature in Oil and Gas Investor is usually a full page of the largest deals, with these and all others posted in the OilandGasInvestor.com database. In 11 years of preparing the monthly summary, having more than enough deals to fill the page was certain.

By mid-December, when preparing the January issue’s “New Financings,” there were a total of five deals, barely filling a half-page. “We need more deals!” came the call from the graphic-design department. “There are no more deals,” came the answer, which was received by stutters of disbelief and exclamations of shock.

The extreme of that season appears to be past the industry now. Stock prices for most producers found bottom roughly on March 1, and the trend has been steadily upward since. Chesapeake Energy Corp. bottomed at about $11 in December and was $22 at press time. Devon Energy Corp. fell to about $38 in March and was $62. Range Resources Corp. hit its one-year low at about $26 in October and was $46.

Natural gas prices remained below $5 on Nymex, but futures were higher, and several producers were locking in better than $6 in 2010 hedges on some production. Crude oil on Nymex pushed past $70, although some of the price improvement is due to a newly declining U.S. dollar.

Get the capital raises in now.

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

For details on all capital-raises, plus buybacks and redemptions, see the “Recent Financings” database at OilandGasInvestor.com.

Increased use of natural gas as transportation fuel could resolve some take-away-capacity issues. More natural gas would be consumed where it is produced. Some gas flow may even be redirected.

            In current forecasts for new natural gas supply, the prolific U.S. shale plays, particularly in the ArkLaTex region, have the potential to lock out a large amount of Gulf Coast and Gulf of Mexico gas production.

            In this month’s cover story, “Building Gas Demand,” Porter Bennett, founder and president of Evergreen, Colorado-based energy-analysis firm Bentek Energy LLC, says it is plausible, based on current supply forecasts, that the Nymex price for natural gas may one day no longer be based on delivery at Henry Hub in South Louisiana.

            If not there, then where? “We debate that about once a month at the office,” he says.

            In developing this month’s cover story, an abundance of facts about natural gas and other energy sources were surfaced. In it, the metaphor of “an elephant in the room” is used to describe tremendous gas production and reserves, and gas in storage.

            There is another elephant in the U.S. energy-policy debate: the undeniable benefits of greater reliance on natural gas as a leading source of fuel, and no matter what each American would like to see Washington achieve via energy policy.

            – Natural gas has greater energy content, in an Mcf of gas versus a gallon of gasoline comparison. An average-car fill-up—approximately 16 gallons of fuel—would cost about $8.40 at today’s natural gas price.

            – Its carbon footprint is lower than that of coal and crude oil. It produces 90% fewer particulates and half as much greenhouse gas.

            – It is necessary as a backup power-generation fuel source if the U.S. is to power more homes and businesses with solar and wind. Natural gas-fueled power plants can sit ready, idle when solar and wind don’t carry their load.

            – It is available in great quantity domestically, suggesting reduced dependence on foreign oil, thus fewer U.S. dollars sent abroad and less interest in keeping up relations with hostile exporters and their enemies.

            Generally, there isn’t a lower-carbon-footprint fuel that is available domestically—or abroad—in sufficient quantity and as inexpensively.

            The elephant in this month’s cover story generated some grins and commentary while the story was under way. “I think the elephant represents (this),” says one contributor. “I think the elephant represents (that),” says another.

            The idea evolved into theories for a hypothetical elephant-based multimedia message campaign. The elephant could be blue and carry wind and solar on its back. It could appear in a television commercial in which it is sitting quietly, but unnoticed, outside a breakfast window in a modest neighborhood in which homeowners are wondering how to solve energy prices but reduce pollution.

            There is an obvious problem with an elephant as an icon for promoting natural gas, though: it has a huge footprint, and that’s not true about natural gas.

            Natural gas does need branding, though, says Aubrey McClendon, chairman and chief executive of Chesapeake Energy Corp., the nation’s No. 2 gas producer and the most active driller. The milk industry has made milk cool, with its “Got Milk?” campaign. Florida has done it with orange juice. Pork purveyors did it with “The other white meat.”

            Chesapeake and 24 other producers, which represent 40% of current U.S. gas production, have formed the American Natural Gas Alliance in the past year and pledged $100 million a year to consumer, legislator and policy-maker education.

Producers have been focused in the past on surfacing supply, cracking the code in the U.S. shale-gas plays and trying to keep up with demand, McClendon says.“We didn’t really know how to produce more, so there was really no reason to increase the market for it.”

Now, there is all this supply. “We have to change the culture of how our industry approaches the promotion of its product,” he says.

At press time, natural gas on Nymex for June delivery was about $4.20—a price at which few U.S. gas plays are economic at current E&P costs.

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

The “Building Gas Demand” Online Information Center Online resources used in developing “Building Gas Demand,” the Oil and Gas Investor, June 2009, cover story and additional resources that have been developed since the article was published are now available at The “Building Gas Demand” Online Information Center at OilandGasInvestor.com. Click for the story and resource-center link, including two webinars, four feature films, transcripts and 10 supplemental articles: ­What To Do With All This Natural Gas?

The Haynesville shale may be the biggest natural gas play in the U.S. today. “Some think it may be one of the biggest gas fields in the world,” says Questar Corp. chairman, president and chief executive Keith Rattie in the webinar “’Inconvenient’ Realities Of Energy, And The Role Of Natural Gas”  hosted by OilandGasInvestor.com and now available on demand for review.

“And the irony here is that, until mid-March of 2008, very few people in the industry and certainly nobody in Washington had ever heard of the Haynesville shale.”

The Salt Lake City-based integrated gas company is among gas producers operating in the northwestern Louisiana/northeastern Texas play, holding a position in what is proving to be the “sweet spot” of the producing trend.

“The Haynesville shale is perhaps one of the best illustrations of that stunning breakthrough in our ability to exploit the resource base in this country,” Rattie says in describing whether the U.S. has sufficient natural gas supply to support conversion of more U.S. energy demand off oil and coal to natural gas.

“What we’ve seen in recent years is that technology that was first adapted to exploit gas in the Barnett shale in the Fort Worth Basin in Texas has now been applied to a series of major new shale plays that just a few years ago most observers thought would never be commercially viable.

“We have the Fayetteville shale, the Haynesville shale, the Marcellus shale and, in Canada, there are the Horn River shales. You’re going to see horizontal drilling technology and, in particular, multi-fracture-stimulation technology applied to rock that we thought was unproducible just a few years ago.”

            At the current rate of U.S. natural gas consumption, many gas-market observers suggest North America hosts a 100-year supply of proven, producible reserves.

Rattie says, “Over time, that number will prove to be conservative. Many policy-makers are hung up on the fact that natural gas supplies are finite, and that of course is true, but human ingenuity is not (finite) and over time, the smart people in our industry, using advances in technology, are able to extend our natural gas resource base.”

Since 1980, the U.S. has consumed more than 600 trillion cubic feet of gas and the known resource base today is at least three times what it was believed to be then, he says. “If we are having a conversation like this 20 years from now, we will find that, during the next 20 years, we will probably, in this country, use another 500 to 600 Tcf of natural gas and our resource base will be even greater than when we started out.”

Currently in Washington, the coal lobby is winning in “a game of trying to buy enough votes. And the game is getting rigged; the coal industry is better at playing that game than the natural gas industry. And my concern right now is that we’re going to see legislation that has the unintended consequence of allowing the continued use, and perhaps greater use, of coal to the disadvantage of natural gas.

“If you left the playing field level…natural gas will win. But politicians will have a way of gaming the rules so market-based outcomes are not always the ones that are realized.”

            The natural gas industry can win on the product’s favorable environmental profile.

“Many (environmental) groups despise drilling for natural gas more than they fear the impact of climate change. It’s a sad reality. What we as a natural gas industry have to do is reach out to responsible environmental groups. We have, as an industry, every right to claim the moral high ground on this issue.

“We find, produce and deliver a clean, safe and environmentally friendly fuel to 65 million American homes and businesses in this country. And by choosing not to develop our most environmentally benign fuel—and I stress that word “fuel”—the unintended consequence is that we are going to burn more coal, import more oil and run our aging nuclear plants harder than ever.”

Aggressive climate-change policy will be difficult to effect if the Obama administration wins in its quest to eliminate oil and gas producers’ tax credits for intangible drilling costs (IDCs).

“We need to have policies that allow the industry to consistently invest in development of new supplies…IDC expensing has been part of the U.S. tax code since, I think, 1913. (Eliminating it) will have the effect of reducing U.S. producers’ cash flow by somewhere from 20% to 30% in the first year. Most U.S. producers operate under a simple rule: Cash flow equals capital spending.

“If you eliminate the expensing of IDCs—and I believe that is a wrong-headed policy—you will have the unintended consequence of reducing investment in natural gas supply.”

He urges producers to at least “do just one thing when policy-makers talk about sweeping changes in the way we use energy in this country and that is to do the math. Do the math.”

He concludes that the best policy is to let various energy sources compete. “The reality is there is no perfect form of energy. Only markets can weigh the pros and cons of various types of energy, and let the markets do the job.”

–Nissa Darbonne

(The 60-minute webinar is now available for review. Click to register for the webinar, which includes a copy of Hart Energy Publishing editors’ Vision: Global Energy Outlook, 2009 special report.)

What’s the expert economist’s forecast for U.S. oil and natural gas demand and future prices? Dr. Nariman Behravesh, chief economist for IHS Global Insight, discusses this and more in an interview with Oil and Gas Investor executive editor Nissa Darbonne.

Behravesh says oil and gas prices will remain very soft through 2009 and will begin to shift upward in 2010. Proposed U.S. energy policy will give a boost to natural gas demand, he adds.

            Is the current U.S. economic crisis Fed Chairman Ben Bernanke’s fault? Behravesh says it isn’t and that former chairman Alan Greenspan was too great an economic cheerleader, leading it into excess. Examples are the tech boom/bust and the housing boom/bust. Greenspan held interest rates too low for too long, he says, and was too lax in regulating the banking industry.

            Yet, the U.S. experienced 20 years of economic expansion under Greenspan. Should America bring back the cheerleader? No, says Behravesh, that won’t correct the situation.

Click through for the tape of his comments.

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

Gulf of Mexico shelf gas producers are at the greatest risk of not staying afloat of current natural gas prices. “If you aren’t getting $5 an Mcf, you should not be drilling any Gulf of Mexico (shelf) projects,” says Rehan Rashid, managing director and head of energy and natural resources research for FBR Capital Markets, a unit of Friedman, Billings, Ramsey & Co. Inc.

“Stick with the purest shale players and avoid producers in conventional plays, such as the Gulf shelf,” he says.

Rashid and Rocco Canonica, director of energy analysis at Bentek Energy LLC, present their analysis of current gas-price economics in the webinar “Where Are The $5 Gas Plays? Who’s Profitable In This Market?” The webinar archive, including the speakers’ slides, is available at http://www.oilandgasinvestor.com/webinar/200904_gasplays.

Rashid expects demand for gas in 2012 to, at best, be flat with demand of 2008.

With the highly capitalized drilling of the past few years has come production overcapacity. Just as in the retail and residential sectors this past decade, there has been gas-production overbuild, and the economy is creating a strong headwind against improving gas prices.

“Bankruptcies must happen; people must close shop, unfortunately,” he says.

If service costs and operating costs improve, positive margins will return in some plays and improve in others. “You need to find as much of a pure-play shale (producer) as possible (if investing in a gas producer).”

Among producers he covers and others, shale-weighted players include Range Resources Corp. (primarily in the Marcellus, Barnett), Petrohawk Energy Corp. (Haynesville), Chesapeake Energy Corp. (Barnett, Haynesville, Fayetteville, Marcellus), Southwestern Energy Co. (Fayetteville) and Newfield Exploration Co. (Woodford).

What about forecasts for LNG dumping into U.S. terminals and storage facilities this summer? Canonica says the economics are not favorable for LNG coming into the U.S. right now. “The end is full here.” The incentive for LNG dumping is not present, especially on the U.S. Gulf Coast, compared with terminals on the Atlantic Coast. “If there is dumping, it would be on the East Coast,” he says.

Rashid agrees, and adds that there may be dumping, nevertheless. For an owner of a tanker of LNG, “I’ve got to dump it somewhere.”

Which shales plays have stronger odds if service costs decline? At the current cost of oilfield services and at $4.50 gas prices, the Haynesville, Marcellus, Fayetteville, Barnett and Woodford shale plays have single-well internal rates of return ranging from 25% to 75%, according to Rashid.

If service costs decline 40%, the single-well IRR at $4.50 gas improves to 400% in the Haynesville; more than 300% in the Marcellus; more than 250% in the Fayetteville; more than 150% in the Barnett; and 100% in the Woodford.

Canonica says the gold-rush mentality in the U.S. gas industry these past few years led to 8% growth in gas production in 2008. “This happened to coincide with the worst financial crisis in decades. The result: Futures have dropped to less than $4 per million Btu from nearly $14.”

The current breakeven price is $2.88 in the Haynesville; $3.16, Pinedale; $3.60, Fayetteville; $4.00, Marcellus; $4.02, Piceance; $4.04, Barnett; and $4.55, Woodford.

“Current spot prices are not supporting drilling in most unconventional plays. But forward prices have not dropped below breakeven costs in some of the star plays,” Canonica says.

Spot prices in the Rockies have fallen from $7.64 a year ago to $3.05; Midcontinent, from $8.23 to $3.10; East Texas, from $8.25 to $3.75; Gulf Coast, from $8.57 to $4.59; and Ohio, from $8.93 to $4.88.

Canonica offers a comparison of Haynesville and Piceance production forecasts through 2018 in the current economic environment. “While production in the Piceance is projected to decline slightly and then flatten out, Haynesville drilling economics and producer drilling plans indicate rapid growth.”

That new Haynesville production—as much as 4 billion cubic feet a day by next year—will create hurdles for producers in the Gulf Coast region to get their gas into sales.

“Southeast/Gulf outbound pipe flows reached capacity briefly this winter and is projected to be solidly against the capacity line late this year as the Haynesville continues growing. Gas-on-gas competition will become more intense.”

            What’s economic at $2 gas prices? Rashid says costs have to come down some 70% to 80% to make $2 gas plays. The industry was profitable just a few years ago at $2 gas, and it can be again, but only if service and operating costs decline significantly, he says.

The “Where Are The $5 Gas Plays? Who’s Profitable In This Market?” webinar archive, including the speakers’ slides, is available at http://www.oilandgasinvestor.com/webinar/200904_gasplays.

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

Some financially careful producers and some types of plays are incredibly economic at natural gas prices below $5. What are these plays? Who are these producers? Short- and long-term investment opportunities are here. Experts describe the nature of plays and producers in a sub-$5 commodity price in the webinar “Where Are The $5 Gas Plays? Who’s Profitable In This Market?” Thursday, April 2, 10 a.m. CDT. Register here: http://www.oilandgasinvestor.com/webinar/200904_gasplays/

What you will learn:

– Break-even drilling cost by basin, including a discussion of why costs are different per basin, which companies are in certain basins and whether the cash and forward markets support drilling in those basins.

– How to differentiate E&P companies’ cash-flow potential based on the geologic and geographic nature of their gas production.

– The outlook for future gas supply and demand, based on producers’ ability to continue to produce at $5 gas prices.

– Natural gas investment ideas.

Featured Speakers:

Rehan Rashid, managing director, FBR Capital Markets

Rehan Rashid is managing director and head of energy and natural resources research at FBR Capital Markets. He joined FBR in September 1998 as a vice president, covering the oil and gas E&P sector and most recently initiated coverage of the liquefied natural gas (LNG) sector.  Prior to joining FBR, he was an associate analyst at PaineWebber, covering E&P and spent two years at Jefferies Inc. He received his B.S. in accounting and an MBA in finance and accounting from the University of Houston.

Rocco Canonica, director of energy analysis, Bentek Energy

Rocco Canonica, director of energy analysis at Bentek Energy, has 15 years of experience in the energy industry. He has been with Bentek Energy since April 2007 and previously was managing editor at Intelligence Press Inc. and was an editor at the Oil Daily Company.

Moderator:

Nissa Darbonne, executive editor, Oil and Gas Investor

Nissa Darbonne is executive editor of Hart Energy Publishing’s Oil and Gas Investor group, which consists of Oil and Gas Investor magazine, the online market-intelligence centers OilandGasInvestor.com, A-Dcenter.com and UGcenter.com, the newsletters A&D Watch, Oil and Gas Investor This Week and OilandGasInvestor.com Today, and the conferences Developing Unconventional Gas (DUG), Energy Capital Week and A&D Strategies and Opportunities. She joined Hart in 1998 after nine years in news reporting for The Daily Advertiser (Lafayette, La.), the last two years as business editor. She holds a BA in Journalism and English from the University of Louisiana-Lafayette.

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

Chinese proppant might not be all that bad. Dave Pursell, head of macro-research for Tudor, Pickering, Holt & Co. Securities Inc., says, “Our sense is that, what’s coming out of China right now, the quality is fine.”

But, these small manufacturers may try to ramp up too fast, and quality may be diminished, he adds in the webinar “Seeking Proppant? The Outlook for Supply, Demand And Quality” at OilandGasInvestor.com. To hear the one-hour program, go to http://www.oilandgasinvestor.com/webinar/200903_seekingproppant.

            Earl Freeman, executive vice president of proppant-testing firm PropTesters Inc., says what he has seen of Chinese proppant has been relatively fine. “Worldwide, there are about 20 suppliers of ceramic proppant…In some cases, Chinese ceramic has performed better than local supplies,” he says.

            Yet, again, the quality of proppant used in a well depends on what is delivered to a wellsite, versus what is tested in a lab or at the manufacturer’s shipping bay, before contamination and other corruption at transfer points and in handling, he adds.

What about general proppant availability? “Near term, I don’t think we’re going to have a problem with proppant availability,” Pursell says. But that won’t last.

            Rigs are being laid down across the U.S., however, the number of horizontal rigs at work has grown as a percentage of total rigs in the field. Horizontal rigs are often used in drilling shale and other unconventional plays, which need proppant. He expects demand to continue to be strong.

Proppant demand was 70% for sand, 10% for resin-coated sand and 20% for ceramic in 2006, according to Pursell and based on figures from Carbo Ceramics Inc., which has some 60% or more of ceramic-market share. Pursell says the global proppant market grew some 10% a year in 2007 and 2008, thus demand last year was an estimated 16 billion pounds—“and that’s a lot.”

            The Marcellus and Haynesville plays are the two strongest engines for growth in demand for proppant, he adds. If estimating that 500 Haynesville wells are drilled each year and each use 3 million pounds of proppant—“Maybe higher. It seems to grow higher in time, as wells get better”—this demand totals 1.5 billion pounds of proppant a year.

“That’s a 10% increase, roughly, in global proppant demand.” If a third of this is ceramic, that’s a roughly 17% increase in ceramic-proppant demand; if the balance is sand, that’s roughly an 8% increase.

“So these shale plays are big users of proppant and, the deeper you go…, the more likely it is to need to retain conductivity and you’ll have to go to a higher-strength proppant—and that means ceramic, on many occasions.”

In the Marcellus, sand and resin-coated sand can be used more often than in the Haynesville play (which is deeper and, thus, has a higher closure stress, so the proppant must be stronger). If 500 Marcellus wells are drilled each year and 2 million pounds are used per well, this results in additional demand of 1 billion pounds of proppant per year. “You’re talking about a significant increase in total demand.”

            And, there are other shale plays that will put pressure on supply, such as the Montney and Muskwa plays in western Canada, and the Eagle Ford and Pearsall in South Texas.

“It’s going to be tough-sledding in the current environment,” Pursell says. “…The tension there is to continue to grow demand for proppant…We are already, effectively, out of capacity.”

            Domestically produced ceramic-proppant supply can grow some by Carbo Ceramics’ restart of its New Iberia, La., plant and expansion of a Georgia plant, but “you’ll have to rely on external supply, probably from China…

“Buy proppant with eyes wide open and make sure of the quality,” he says.

            Proppant quality can be corrupted at many supply-chain points, which begin with the source and end at the wellsite, Freeman says. “It can affect crush properties, particle distribution and so forth.” Sometimes the proppant isn’t up to specs due to abuse; it can even be damaged during movement in the field bin, he says.

            Meanwhile, a new proppant is coming to town. Nanostructured ceramic proppant is an innovation in proppant supply that is under way at Oxane Materials Inc., a 16-person, start-up spinout of Rice University and that holds patents for OxFrac and OxSense. Investors include Energy Ventures Ltd., Carrizo Oil & Gas and Advanced Energy Consortium.

            The nanoproppant has increased particle strength, expanded processing possibilities and enhanced particle reactivity/surface energy. Chris Coker, Oxane president, describes the difference as pebbles versus boulders. OxFrac can be placed at a reduced pumping rate, facilitating creation of more optimal fracture geometry. OxFrac is to be available in fourth-quarter 2009; OxSense in 2010 or early 2011.

            Where does it fit in the marketplace? “We compete with non-consumption—areas you can’t prop today,” Coker says. He adds, however, that Oxane facilities could consider making traditional high-strength ceramic proppant as well as the nanoproduct.

            There are currently three types of proppant in the marketplace: quartz sand (Ottowa, Jordan, England, Brady); resin-coated sand (curable, which has sand flowback problems, and pre-cured, which has enhanced strength); and ceramics (sintered bauxite, which is the strongest; intermediate-strength, or ISP; and light-weight, or LWP).

            The propping agent is the only thing in the well job that has lasting value, says Dr. Steve Holditch, department head and Samuel Roberts Noble Foundation endowed chair in petroleum, Texas A&M University.

“Placing the right propping agent at the right place in the fracture is a key to financial success and to high flow rates,” he says. “Usually, more conductivity is better, even in tighter rocks. Fracture-fluid cleanup is a key issue that is being researched and worked on by a lot of people in the oil and gas industry right now…to help us minimize the problem.

“In the meantime, the solution really is better and more fracture conductivity.” Click to hear the webinar presentations, questions and answers, and for the presenters’ slideshows: http://www.oilandgasinvestor.com/webinar/200903_seekingproppant.

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

The two most imminent issues affecting the continued prosperity of the U.S. are easily solved by each other.

Former President Bill Clinton noted in an address at the Rodman & Renshaw investment conference in New York in November that individuals have wagered against the success of America since the American Revolution. “People have always predicted the demise of America…Everyone who has invested against America has lost…We keep stumbling in the right direction.”

Fortunately, again, the solution is simple and obvious. Work out this economic downcycle while achieving energy independence, which would help assure the U.S. has the strongest economy in the world 10, 20, 30 and 50 years from now, when nations that depend on crude oil but lack any or sufficient domestic supply vie amongst other have-nots for the fuel from what have been historically hostile and virulent countries.

The answer to the economy can be energy itself.

Clinton’s idea is a type of make-work program that is a preface to T. Boone Pickens’ plan for natural gas. Simply put, Clinton suggests engaging the American workforce in converting existing energy demand to greater efficiency, some innovations being as simple as installing motion-sensor light switches in public buildings.

The other part of the deal is to legislate greater efficiency in use of energy supply— that is, to promote the highest- and most indigenous- Btu supply to its best use. U.S. use of natural gas has been historically wasteful. Having a higher Btu content than crude oil or its byproducts, natural gas is increasingly used for generation of electricity, which evaporates when not used.

Suggestions on the dais most often involve conversion to electricity-powered cars, but this requires conversion of high-Btu gas into electricity, and what is not used is wasted. Instead, conversion of the greatest portion of the U.S. transportation system to compressed natural gas (CNG) puts the high- Btu-content fuel directly into automobiles, and closes the tap until the next fill-up.

Meanwhile, efforts toward installing gas taps, retrofitting existing vehicles and making ready-for-CNG ones going forward represent legislated “make work” but, like American infrastructure improvements of the 1930s, will produce great economic advantage— and actually have street value as CNG parts and vehicles become fungible.

Enter a side story: the upside-down U.S. automotive industry. Obviously, conversion to CNG would provide American autoworkers— and not just those employed by indigenous companies, but all U.S. autoworkers— with new tasks, and result in patent and best-practice leadership globally.

And enter another side story: the globalwarming scare. Natural gas has a carbon footprint, in that it does contain some carbon, yet it is significantly less than that of crude oil and normal uses of coal, and especially when factoring how little is needed to achieve the same fuel-supply goal.

Melanie Kenderdine, associate director, MIT Energy Initiative and a former vice president of the Gas Technology Institute, notes that natural gas is both a CO2-mitigation option and a target for mitigation.

In the past, natural gas as a transportation fuel has been rejected by Washington due to its belief that there was too little indigenous supply, which would merely result in U.S. conversion from relying on a caustic oil cartel that can stronghold supply and prices to relying on a relatively unknown gas cartel that could do the same.

Yet, U.S. natural gas explorationists have proven abundant resources in the Lower 48, where infrastructure is at the ready to take it to markets; in Alaska from which only a pipeline is needed; and from a normally good neighbor, Canada. There are 2,000 trillion cubic feet of known unconventional gas resources in North America, and the number is likely to soon be revised upward, according to Kenderdine.

Current demand is 22 trillion per year, thus some 100 years of indigenous gas supply is available at the current rate of use.

In summation, the U.S. has abundant natural gas supply. The economy has been crushed in part by US$147 crude oil and US$4-plus pump prices. Relations with foreign oil producers can be toxic. The U.S. auto industry has become a world laggard. And, some Americans are convinced that people can reverse Earth’s warming trend.

The solution? Put the economy to work at converting energy demand to natural gas.

–Nissa Darbonne, Executive Editor, Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com, A-Dcenter.com; ndarbonne@hartenergy.com

Proppant demand continues to run full-out, and supply continues to run tight or out—and when exploiting U.S. shale and tight natural gas is at the top of more and more E&P companies’ capital-spending plans. What is the nature of the supply and demand balance currently of the various types of proppant? What types of proppant are required by play for the best initial and long-term results? What have been the trends in the quality of domestically produced proppant, and particularly as material from outside North America may increasingly land in U.S. wells? And, what is on the horizon for a “smart” proppant? Experts will answer these questions in the webinar “Seeking Proppant: The Outlook for Supply Capacity, Demand and Quality,” March 11, 10 a.m. CDT. Register here: https://video.webcasts.com/events/pmny001/viewer/index.jsp?eventid=29788

What You Will Learn:

– The fundamentals of proppants, such as when it is best to use sand or ceramic, depending on the nature of the formation.
– Current U.S. supply and demand, and any supply/demand issues outside North America that may affect the availability of more product in the U.S.
– The current quality of U.S. proppant supply, and how to assure the material is reliably to specs.
– The nature of nano-structured proppant, the new “smart ceramic” that is being developed now.

Featured Speakers:

Dr. Stephen (Steve) A. Holditch, department head & Samuel Roberts Noble Foundation Endowed Chair in Petroleum, Texas A&M University. Prior to Texas A&M, Dr. Holditch worked for Shell Oil Co. and was president from 1977-2000 of S.A. Holditch & Associates, now a division of Schlumberger and provides petroleum-engineering technology involving the analysis of low-permeability gas reservoirs and the design of hydraulic-fracture treatments for industrial and government clients, spanning reservoir simulation, well testing, reservoir engineering, natural gas engineering, coalbed-methane development, and the use of horizontal wells to develop gas reservoirs. He joined the Texas A&M petroleum-engineering faculty in 1976 and was named to the R.L. Adams Endowed Professorship in 1995. He has BS, MS and PhD degrees in petroleum engineering from Texas A&M.

Earl R. Freeman, executive vice president, PropTester Inc. Earl R. Freeman is executive vice president of independent proppant-testing firm PropTester Inc. Previously, he was sales and marketing manager, oilfield technology group, for Borden Chemical Inc. He began his career in the late 1970s with the Western Company of North America, where he assembled a proppant-testing laboratory that contributed to the eventual development of API-recommended practices (e.g. API RP 56), and later spent 15 years with BJ Services. He has a B.S. in Biology from the University of Texas-Arlington, is an author of several SPE papers on fracturing and cementing, and holds two U.S. patents on well-stimulation methods.

Chris Coker, president, Oxane Materials Inc. Chris Coker has served as Oxane Materials Inc.’s president since its founding in late 2002. Chris has raised more than $15MM in capital from

About the Moderator:

Nissa Darbonne, executive editor, Oil and Gas Investor. Nissa Darbonne is executive editor of Hart Energy Publishing’s Oil and Gas Investor group, which consists of Oil and Gas Investor magazine, the online market-intelligence centers OilandGasInvestor.com and A-Dcenter.com, the newsletters A&D Watch and Oil and Gas Investor This Week, and the conferences Developing Unconventional Gas (DUG), Energy Capital Week and A&D Strategies and Opportunities. She joined Hart in 1998 after nine years in news reporting for The Daily Advertiser (Lafayette, Louisiana), the last two years as business editor. She holds a BA in Journalism and English from the University of Louisiana-Lafayette.

Sell the asset—and problem? Not in this A&D marketplace.

Owners of nonoperated working interests in Gulf of Mexico assets may be without any coverage for the upcoming hurricane season, which begins June 1, says John Ludwig, chief executive officer, Fort Worth-based EnRisk energy insurance risk-mitigation and management firm.

Meanwhile, acquiring the coverage can take 60 to 90 days if starting now, wind coverage is selling out, and merely dumping the Gulf assets before the next hurricane would require overcoming an anemic A&D marketplace—and with a hot-potato offering! (Listen to the interview.)

“What we’re finding today is a disturbing trend,” Ludwig says. “Most larger operators in the Gulf of Mexico who have been obligated by joint operating agreements (JOAs) in the past number of years (to hold coverage) have recently, as a result of the hurricanes of the last three seasons, now dropping any coverage that they might (normally) be extending out to the nonoperated-working-interest-owners.

“Even though the JOA is requiring (the operator to) provide coverage, they are walking away from those JOAs, as a result of the increasing cost associated with it, and the fact that there is less and less capacity for wind cover in the Gulf of Mexico.”

He suggests a nonoperated-working-interest-owner find out what’s in the JOA, what coverage exists, what properties are exposed, and enlist a risk-mitigation firm, such as EnRisk, to walk through the exposure. Sorting it out and sealing the leaks may take at least 60 and up to 90 days. The market today is requiring a tremendous amount of information and proof.

“It’s going to be no less than 60 days by the amount of information that is now being required of the market,” Ludwig says. Meanwhile, hurricane season begins June 1. And, the market may be out of wind cover before June 1, so Ludwig recommends taking care of the matter sooner than later.

The option of simply selling the nonoperated working interest is not a strong one right now. “Because the credit markets are so tight, I don’t see that anybody is looking to increase their amount of exposure in the Gulf of Mexico…Plus, the fact is, with (oil and gas) prices where they are today, no one wants to sell those interests under this current (price) multiple situation.”

For more information, contact Ludwig at 817-877-1884. More information on the firm is at www.enriskservices.com.

–Nissa Darbonne, Executive Editor, Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com, A-Dcenter.com; ndarbonne@hartenergy.com