Leslie’s Notebook

They came to Pittsburgh, and the Marcellus shale was the lure. Some 1,400 people attended our “Developing Unconventional Gas-East” (DUG-East), held October 19.

One key take-away is that the Marcellus may be the largest natural gas field in North America (just give it a few more years of steady development drilling), and in fact, it might rank among the top five gas fields in the world. Estimates put the recoverable gas reserves at anywhere from 250- to 489 trillion cubic feet! It’s still early in the game, however, so as time goes on, those numbers will likely rise.

No doubt the play will evolve into several separately named, but adjacent fields, rather than calling an entire swath of the eastern U.S. one big field. By comparison, the Tamar Field just unveiled offshore Israel, which has operator Noble Energy Inc. and plenty of others, excited, has about 6.3 Tcf recoverable. The famed Madden Field in Wyoming has about 4 Tcf.

Another key take-away is that industry appears to be solving any water-related challenges, despite the fears of regulators and environmentalists in the region.  Sourcing enough water for the multi-stage frac jobs being done is not a problem, and handling the produced water may not be either.  Range Resources Corp., a play leader that drilled the first slick-water-fraced Marcellus well in 2004, is close to having zero-discharge wells as it treats and recycles produced and frac-water.

At present, the industry has dodged a bullet–the Pennsylvania legislature did not impose a severance tax on natural gas production as part of the new state budget just signed by Gov. Ed Rendell. Meanwhile, despite fairly low gas prices, activity ploughs ahead. There are 650 horizontal wells permitted in Pennsylvania’s top-five most active counties: Greene, Tioga, Washington, Susquehanna and Bradford.

For much more on the Marcellus shale, and to see videos of key speakers at DUG-East, go to www.UGCenter.com and www.OilandGasInvestor.com.

–Leslie Haines

No matter how you slice it, the U.S. has more than enough natural gas to transition the country away from over-reliance on crude oil and toward the future, for power generation and transportation fuel. T. Boone Pickens isn’t the only person to buy this fact.

Consider this: 2008 was the 10th consecutive year that proved gas reserves in the U.S. increased. You can thank the Piceance Basin, Jonah/Pinedale, and all the shale plays.

The U.S. had already added 46.1 trillion cubic feet of dry gas reserves in 2007, which turned out to be more than double the 19.5 Tcf operators actually produced that same year, says the Energy Information Administration.

Also in 2007, proved reserves of natural gas rose 13% above the prior year to 237.7 Tcf–the highest number in 13 years, according to the EIA, in its annual report published last October.

There’s more good news. This week, BP released its annual BP Statistical Review of World Energy. Its data show that in 2008, natural gas production in the U.S. increased a healthy 7.5%–the largest growth rate in years in fact, and 10 times the 10-year average increase.

The biggest gas production decrease was right next door, in Canada. “How can this be, when it’s an integrated market responding to essentially the same price signals?” asked Mark Findley, general manager of global energy markets for BP America, and manager of the annual review, now in its 58th year.

The answer is, in a nutshell, U.S. shale gas.

More good news about gas came today, as the well-respected Potential Gas Committee released its biennial report on U.S. gas reserve potential. The committee of academics, consultants and industry experts is supported by the Colorado School of Mines.

Estimated natural gas resources rose to 2,074 trillion cubic feet in 2008, from 1,532 trillion cubic feet in 2006, when the last report was issued. This 35% increase, or some 542 Tcf,  is the largest recorded in the committee’s 44-year history of issuing this report.

To put this in perspective, it compares to some 251 Tcf of recoverable resource from the Marcellus shale alone, so, I suspect, the numbers will only rise again two years hence, when we will know still more about the shale plays.

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–Leslie Haines, Editor in chief, Oil and Gas Investor

A Calgary research firm has mapped and plotted 75 wells in East Texas and North Louisiana’s Haynesville shale. More details are thus emerging and the location of the sweet spots is becoming clear. In fact there may be more than one sweet spot.

But, says the May 2009 report from Ross Smith Energy Group Ltd.,  “What seemed like a dream during the leasing frenzy a year ago may turn into a nightmare for some operators. This play is highly variable and some areas will require $10-plus Nymex to break even.”

Based on results from 53 wells studied in Louisiana, a core area is emerging. The Group concludes that Petrohawk Energy Corp.’s Bossier Parish results are still unmatched by any other company, and that the Houston firm’s results in DeSoto and Red River parishes also are superior to other E&Ps drilling in the same general area.

Wells in Harrison County in East Texas are showing shallower decline curves than wells in Louisiana. However, it appears their estimated ultimate recovery (EUR) numbers may be lower as well.

“Press-released IP rates can be very misleading when compared to actual monthly data reported to the state,” the report cautions.

For more on the Haynesville, go to www.UGCenter.com and/or the archives for Oil and Gas Investor.

–Leslie Haines, Oil and Gas Investor

Continued stress in financial and commodity markets has been facilitating a lot of deal action since May 2009. Deals are getting done, and many of them are creative, and oversubscribed. But flexibility is required. (Cue Tom Cruise in Mission Impossible, dangling just above the floor while working on a laptop.)

Thus began Sylvia Barnes’ presentation at the Houston Energy Finance Group this week. Barnes, formerly with Merrill Lynch Petrie Divestment Advisors,  became head of energy investment banking for SMH Capital in Houston in April.

She advised that E&P companies needing to fund drilling, or shore up balance sheets, look at equity raises, asset or hedge monetizations, joint ventures and vendor financings–or all of the above.

“Please don’t hesitate to bite the bullet and issue some equity, whether public, private or hybrid,” she advised, “even if it’s a bit dilutive. In all my years in investment banking, I have never heard anyone say after the fact, ‘Gee, I wish I hadn’t raised any equity.’”

Last July when energy markets peaked, E&Ps raised some $4 billion in upstream equity, but after that, the big drought began. In fourth-quarter 2009, pretty much nothing happened, an unprecedented slowdown in energy finance. But in 2009, some 22 public companies have issued equity.  Sixteen were follow-ons, four were PIPEs and two were registered direct offerings.

Since January 2009, when Whiting Petroleum Corp. became the first “hardy soul” to offer public equity, some $3.57 billion has been raised by E&Ps alone.

The offering discount to the closing stock price–pre-announcement–has varied from 19.5% for Whiting, to 11% for ATP Oil & Gas, to a horrendous 52% haircut for beleaguered Delta Petroleum Corp.

Most of the stocks are up now in the face of a general market rally, rising crude oil prices and investors rotating into energy. But investors also like the comfort of knowing that an E&P has better liquidity or longer-term debt. Since BPZ Energy Inc. issued a PIPE in February, its stock has risen 81.5%.

“Monetizations are a beautiful thing in tough markets. You can reduce leverage, free up capital and get equity-type money, but not at equity-type rates,” Barnes said.

Recent examples include Berry Petroleum selling its East Texas midstream assets, and NGAS selling 50% of its Stone Mountain gas system in Appalachia for $28 million. Then there’s XTO Energy, which gained $800 million in February when it unwound some hedges.

“Think of JVs. In tough times, it’s good to have a partner. This is known as using OPM (Other People’s Money).”

Barnes cited Quicksilver Resources’ recent $280-million deal to bring Eni into its Barnett shale drilling program, Chesapeake Energy’s multibillion-dollar deal with StatoilHydro in the Marcellus shale, and Whiitng’s deal with a private partner in the Bakken shale for $107 million.  These new JVs bring in cash and reduce drilling costs.

In the end, it’s time to shout, as Tom Cruise did: “Show me the money!”

–Leslie Haines, Editor-in-chief, Oil and Gas Investor

Crude oil prices have surpassed $50 a barrel for the first time in months! OPEC held its production quotas firm at its March 15 meeting and compliance with those cuts is fairly decent this time around.  And just yesterday, I saw the first Wall Street report where the analyst actually increased his average oil-price estimate for 2009, to $52 a barrel from $50.

Meanwhile, natural gas prices continue to soften, well below $4 most days. But we see the elements of recovery on the horizon–lower drilling rig counts for gas, falling production in most basins. Now we have to hope that while LNG shipments to the U.S. are increasing over 2008 levels, they won’t increase too much and spoil market dynamics.

Drilling in shales continues to prove your best bet. Even smaller companies that are challenged in many ways, intend to keep drilling in them if they can. GMX Resources Inc., under fire from Centennial Partners, said on March 9 that it has reduced its 2009 capex by $70 million to $150 million–yet it still expects to drill 14 net Haynesville/Bossier horizontal wells. And why not? Even though gas prices are below $5 per Mcf, these wells create a rate of return of 25%, president and CEO Ken Kenworthy says.

What do the bigger companies say? Top executives from EOG Resources, Range Resources, Southwestern Energy and XTO Energy shared their views a week ago at the annual Simmons & Co. International energy conference in Las Vegas.

A Simmons report says the panelists hesitated to forecast gas prices for the near term, but all agreed they will range between $6 and $10 per Mcfe in 2010, as production trails off in response to lower rig counts. In this case, the decline curve is your friend.

The commodity will fluctuate around the marginal cost of production.

XTO chairman Bob Simpson looks for $7 to $10 long term. He said the company now estimates U.S. gas production will fall 10% to 12% year-over-year by December 2009–and this will outstrip demand destruction. XTO thinks the Haynesville and the Woodford shales will yield 25% IRRs at $4 per Mcf, assuming tax deferments.

Range Resources CEO John Pinkerton said the longer term looks like $7 to $8. The company estimates that if the U.S. runs 900 gas-directed rigs throughout 2009, production will be down 8% to 9% by December. He also warned that without IDC tax deductions (intangible drilling costs), less capital will go into the ground, delaying any production ramp-up. In the southeast area of the Marcellus, where Range is the major player, it can achieve a 20% IRR at $3.25 gas, due to the rich BTU content and favorable royalties.

EOG’s Loren Leiker, SVP of exploration, agrees with the range of $7 to $8. But he said EOG needs $5 in its core Barnett shale acreage and $6 in the non-core.

Finally, Harold Korell, CEO of Southwestern, says he will ramp back up in the Fayetteville “when they have the people in place and the returns justify it.” Current returns don’t justify increasing activity–but even so SWN will grow its production 70% this year. It needs $5 gas to meet its own internal hurdle rate of spending $1 to get back $1.30–but wells still show a positive present value at $4 per Mcf. 

–Leslie Haines, Editor in chief, lhaines@hartenergy.com

OPEC meets on 15 March. What can we expect? The analysts at Barclays Capital, led by Paul Horsnell, say, “Global fundamental balances argue for no further change in output policy, but the lack of sustained upwards momentum in prices presents the case for ratcheting up the already considerable supply-side pressure.”

Meanwhile, I think it appears that oil has finally found its floor, trading between $40 and $45 for a few weeks now. Wish natural gas would do the same. The next question is, how long before oil rallies in a sustainable way? That depends on world economies–but I just heard this week that in February, China’s exports fell 26% year-on-year, so don’t look for much of a global oil demand recovery any time soon.

The latest EIA projections have reduced non-OPEC supply growth expectations to almost zero and also cut OPEC NGLs growth expectations. “Our view remains that the key dynamic over the next few years will be a sharp fall in non-OPEC supply, so severe as to shock the more complacent current consensus of a fairly flat profile,” Barclays says.

That last sentence really caught my eye, since oil exploration success is not over yet. There have been some wondrous discoveries unveiled lately–Petrobras’ Tupi find and others offshore Brazil take the prize. Then there is the big Jubilee find offshore Ghana as announced recently by partners Tullow Oil, Anadarko Petroleum and Kosmos Energy.  Also worth mentioning is Anadarko’s Shenandoah find in the Gulf of Mexico. 

On the other hand, the oil rig count in the U.S. should fall by nearly 50% in 2009, according to models from the analysts at Friedman, Billings, Ramsey & Co. The oil rig count would then increase 13% in 2010 and another 5% in 2011 and 2012 when oil prices recover, they say.

–Leslie Haines, Editor-in-chief, Oil and Gas Investor, lhaines@hartenergy.com

You’ve seen it here first! I received a research note in my inbox today saying that for oil and gas prices, and thus for energy equities, the worst may be over. So says Ben Dell, analyst with Bernstein.

This is the first major analyst report I have come across that may be calling the bottom.

“We believe the worst may now be behind us in energy,” says Dell. “Oil and gas prices are now trading at the cash cost and while near term fundamentals may deteriorate further, it appears there is limited additional downside risk to the equities.

• We are upgrading the group and now recommend adding beta as the year progresses to take advantage of any rebound in pricing. Specifically we are upgrading TLM, CHK, RIG, ESV, NE and RDC. At the same time, we are downgrading XOM and OXY due to valuation.
• Our top picks in the E&P/Driller & Service space are now XTO, APC, NFX, EOG, ECA, HAL, NBR, RIG, CHK, TLM, PTEN, DVN and APA (all rated outperform). In the Majors, we continue to recommend an outperform stance on MRO, TOT and ENI.” 

–Leslie Haines, Editor in Chief, Oil and Gas Investor, lhaines@hartenergy.com

During CERAWeek 2009 in Houston last week, Saudi oil minister Ali Al-Naimi was the keynote at a dinner for nearly 1,000 attendees, who of course were  eager to hear from him.  It’s a rare opportunity for all of us who cannot go to Vienna every time OPEC meets.

The man seems charming, a gentleman, articulate. He spoke with self-deprecating humor. But I can see that he, and by extension all of OPEC, is caught in the cross-currents of the day. After the global economy rights itself–whenever that is, in 2010 or beyond–global oil demand will surge once again, and with it, oil prices. But until then, OPEC has, since last September, struggled to get control of the oil markets. It has vowed to cut production by more than 4 million barrels a day.

Yet at the same time, Saudi Aramco has been increasing its capital spending and drilling activity over the past two years. Now in mid-year, its megaproject called Khurais Field will come on stream at the rate of 1.2 million barrels a day. That will bring the Saudi’s spare capacity to 4.5 million a day, well above their stated policy of maintaining 1.5- to 2 million a day in spare capacity at all times. And this is happening during a time of reduced global oil demand, when some 80 million barrels are floating offshore in tankers, as marketers wait for demand or prices to turn back up.

At the same time that Al-Naimi called for oil market stability at CERA, and hopes for a price high enough to create a return, yet low enough to sustain world demand, he also acknowledged the need for nuclear power and renewables. He even vowed that one day, the Kingdom will export the same BTU equivalent in electricty from solar, as it now exports in crude!

“All BTUs are welcome and needed–whether they come from renewable energy, nuclear power or fossil fuels,” he said. “While the push for alternatives is important, a prudent approach demands that we recognize the massive scale of the global energy industry, which makes rapid change costly and impractical.

“We must be mindful that efforts to rapidly promote alternatives could have a ‘chilling effect’ on investment in the oil sector. A nightmare scenario would be created if alternative supplies fail to meet overly optimistic expectations, while traditional energy suppliers scale back investment due to expectations of declining demand for their products.”

He also said global cooperation, more research, and government policies to promote increased energy efficiency and conservation are needed. 

“Over time, the world will likely transition away from the current fossil-fuel-based energy economy,” he said.

For more detail on the world oil situation, see the upcoming March cover story in Oil and Gas Investor magazine, or go to OilandGasInvestor.com.

–Leslie Haines, Editor-in-chief, Oil and Gas Investor

The mood at NAPE on February 5 and 6  was marked by as much comraderie as always, with registrations up ftrom last year, and more exhibitors as well. People said they had to attend because their absence would be noted, and no matter what is happening in the industry, they come to catch up with friends and hear the buzz. Many were not seeking nor selling prospects, but instead, looking for JV partners.

But everyone was asking the same burning questions: Is this the bottom? What do you think? When do you see it turning up again?

There are no major speeches, panelists or workshops at NAPE, so no grand pronouncements from on high were forthcoming to ease anyone’s mind or provide insight. Instead, a collective sigh of resignation and maybe, hopeful optimism, was present: “We’ve been through these downturns before, we know what to do, and we’ll be fine. Just got to wait it out.”

Indeed, we heard all of these phrases at one time or another: The industry is dogpaddling. Treading water. Sitting on its hands. Waiting on the sidelines. Drilling to hold acreage and nothing more.

Said one E&P executive, “Drilling costs have come down some, but not enough compared to commodity prices. I think they will come down even more, so I am waiting until April or May to drill my wells.”

Many are waiting–or need to cut back on their drilling plans for other reasons. The U.S. land rig count has come down to about 1,400, vs. a bit more than 2,000 seen at the peak last fall. (Experts predict more rigs will come down, but that the count may in fact bottom out in April, according to The Land Rig Newsletter.)

–Leslie Haines, editor-in-chief, Oil and Gas Investor… lhaines@hartenergy.com

Here is a big tip of the hat to CEO Harold Korell and his whole team at Southwestern Energy Corp. in Houston.

The E&P company is the only energy-related company to make the list of the 10 best performers in the S&P 500 for 2008. That’s quite an honor in this year of all years.

You can thank a glorious set of shale wells and acreage, and good, steady execution. The company’s third-quarter results showed that its Fayetteville shale production in Arkansas was up 75% over the prior year.

The stock has outperformed just about everybody–actually going up and staying up relative to other E&Ps, many of which have gone on a wild ride this year to new highs and new lows. The 52-week high was $52 and change in July–the low was $19.05 on October 10.

In the interest of full disclosure, I don’t own any of this stock (other than if it is buried in some of my mutual funds)–but I wish I did.

The stock closed at $27.78 on Dec. 15.

–Leslie Haines, Editor in chief,  Oil and Gas Investor.  Contact me at lhaines@hartenergy.com.