Leslie’s Notebook

The Bakken is a barn-burner, and if one includes the Lower Lodgepole formation as well, then this area of North Dakota could contain up to 8 billion barrels of oil, some operators think. It remains to be seen what the well spacing will end up being as the play moves west, although operators will be testing 320-acres eventually, says Harold Hamm, chairman and CEO of Continental Resources Inc.

For now, frac math is the pastime this summer. The more fracs the better, one would think. But of course, it’s more technical than that. There is an optimum number to be done, and a limit to the dollars spent, versus the amount of incremental barrels and Mcfs recovered. Key operators in the Bakken are pushing the limits, with Brigham Exploration Co. having done as many as 36 frac stages.

“I think the upper limit has yet to be tested,” said Hamm during a Q&A session after his prepared remarks, at our Denver conference held in May, Developing Unconventional Oil (DUO).

“We have an ongoing internal study that we keep updating as we get new data.”

Whiting Petroleum Corp. CEO Jim Volker said his company also is experimenting. “It’s something we are wrestling with at Whiting today. We see a a range of options. A 22-stage sand frac can go to a 30-stage frac when using a lot more ceramic proppant in it.

“Going from 22 stages to 25 is an incremental cost of about $700,000. If we go all the way up to 30 stages, that would be an additional $2- to $2.2 million. So we have to recover a lot of additional barrels of oil to get to pay out. We are all testing this thesis that the more fracs, the better. We’ll let you know in about nine months!”

For more on the Bakken and other unconventional oil plays, and to purchase videos of individual speakers and panels, see our ad on the home page of www.OilandGasInvestor.com, or get Bakken reports and wall maps at www.hartenergystore.com.

–Leslie Haines

Is U.S. natural gas production really going up, or is it flat or down, compared to 2008 and 2009 data? That’s been the key question this year for producers, traders, speculators and end-users. With the lag in drilling last year, the sharp decline curves in the shale plays, and the overhang of uncompleted shale wells in second-half 2009, many people find it difficult to say.

Many analysts thought that production would start to decrease this year, thereby enabling prices to rise later in 2010.

The supply picture is cloudy due to many factors—but that may be about to change for the better.

Pending revisions to supply data, as compiled by the Department of Energy’s monthly EIA-914 production report, “cast uncertainty on a primary source” for gas supply data that affects gas markets, says Barclays analyst James Crandell in a recent report.

The EIA’s data has increasingly come into question, especially now that fast-paced drilling in shale plays is adding significantly to U.S. supply. But on April 29, EIA is expected to announce a revised methodology. The agency also says it will release revised monthly production data for all of 2009.

“We examine other sources of production data for comparison, including government sources and commercial vendors,” Crandell says in his weekly natural gas report. “Typically, they rely either on state-administered surveys in which data are reported with a lag, or on pipeline informational postings. Data tend to converge between methods with enough time lag, but incomplete reporting afflicts recent months and makes comparisons between methods another ‘estimation’ process.”

Crandell says EIA-914 data tend to be best for states where survey coverage is high. “We expect data revisions to be focused in a few states, namely Texas and Louisiana, where the industry composition has changed drastically since the survey was instituted.”

Meanwhile, the horizontal gas rig count is now higher than it was during the last peak in 2008.

–Leslie Haines

In this blog a few days ago, I wrote about Jim Bob Moffett, major domo of McMoRan Exploration Co., who spoke in Houston on the big Davy Jones find on the shallow-water shelf.

In the blog, I quoted Mr. Moffett as saying, “Porosities are 13% to 22%. You get different readings from different logs. But downdip, the porosities go to hell, so we have a lot to learn. The challenge starts now. This looks a lot like the fields we drilled when we were young.”

Seems I tripped up a bit here and so, I’d like to apologize and make it right. According to MMR spokesman Bill Collier: “The first two sentences are specific to the initial results McMoRan has obtained on Davy Jones thus far [big porosities and yet, different readings from different logs employed].”

“But, the third sentence [downdip] was a general comment about porosity based on our experience working shallower fields.  Because we have only drilled one well, we do not know what the porosities are downdip at Davy Jones at this time.”

Indeed, McMoRan intends to spud a second well later this year, and to flow-test the disocvery as well.

Collier goes on to say: “Our experience from analyzing shallower fields suggests that porosities are preserved updip in hydrocarbon columns where water cannot compromise the rock porosity.  Downdip, when water occurs in the pore space, ‘diagenesis’ (a change in mineralogy caused by fluids migrating through the pore spaces with precipitation of minerals in the pores) can come into play, which can cause a reduction of porosity.

“As we stated in our January 11, 2010, press release, the zones encountered at Davy Jones are full to base, meaning we have not encountered a water level in the various zones encountered to date.

“We plan to commence drilling an offset delineation well at Davy Jones in the coming weeks. The important information to be gained from the flow test on the discovery well, results from the offset well, and future drilling will be vital as we continue to define the ultimate size and productive capabilities of this exciting discovery.”

And there you have it. Everyone in the industry looks forward to the announcement of results from the flow test oif the first well later this tear, and from second, delineation well later on.

Leslie Haines

We’ve been busy lately, but it’s been a good kind of busy. We have listened to E&P folks at NAPE and then a few days later, we attended a Houston Energy Finance Group event with the CFO of Brigham speaking on the Bakken–32 frac stages in one well!

Finally, the piece de resistance: a SIPES luncheon where Jim Bob Moffett, co-chair of McMoRan Exploration Co.,  spoke on the huge Davy Jones find on the Gulf of Mexico shelf. How’s that for a great run?

At NAPE it was clear that the industry’s mood is lighter again, and were it not for the uncertainty about natural gas prices, people might have been jubilant. The reason? The shales just keep coming, and some big finds elsewhere are about to jump-start the next leasing frenzy.

First, the shales. Many exhibitors at NAPE showed Eagle Ford and Marcellus deals. But we noticed oily-shales such as the Niobrara starting to command more attention. (A landman friend called to say that the courthouse in Converse County, Wyoming, is overrun with landmen and every restaurant in town the same…and they are chasing the Niobrara or Mowry shales in southern Wyoming.)

Now the rumor is that Rosetta Resources has a big shale well like the Bakken out in Glacier County, Montana, some 400 miles west of the main Bakken fairway. If that pans out and more wells are drilled, then boy howdy–a little side trip to Glacier National Park is in order.

The Bakken play, meanwhile, continues to allow operators to showcase what horizontal drilling and frac stages can do. Brigham has reported several wells flowing more than 1,500 barrels per day and has reported fracing one well 32 times as the lateral legs keep expanding further from the wellhead, said CFO Gene Shepherd Jr., speaking to the Houston Energy Finance Group.

The company’s #1H State 36-1 flowed 3,807 barrels of oil equivalent per day from Middle Bakken, in the eastern portion of its Rough Rider project area. “Our four most recent wells IP’d at 3,300 barrels a day,” he said. The comoany has 700 potential horizontal locations in its core area.

Out to the Shelf. McMoRan’s Davy Jones find on South Marsh Island Block320 looks like a big one. The next hurdle is getting a flow test done.

Co-chairman Jim Bob Moffett was in fine form as he told an overflow crowd at a Houston SIPES luncheon that the only question is, should the test equipment be good for 20,000 pounds of pressure, or 25,000? If the latter, the equipment needs to be ordered and the MMS has to OK it, so the test won’t happen until well into the second half of 2010.

“440 degrees is the highest temperature we’ve seen but that doesn’t bother me. We’ve see that elsewehere, like at Mobile Bay, but when you combine it with these high pressures, this is a challenge,” he said. “It takes moxie, but winners never quit and quitters never win. These things are all too damn close to call. But these are the cleanest sands I’ve ever seen–no  bitumen, no feldspar, no H2S.

“Porosities are 13% to 22%. You get different readings from different logs. But downdip, the porosities go to hell, so we have a lot to learn. The challenge starts now. This looks a lot like the fields we drilled when we were young.”

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

lhaines@hartenergy.com

U.S. Reps. Gene Thompson and Tim Murphy, and State Sen. Gene Yaw welcome the industry.

The burgeoning Marcellus shale play in Pennsylvania is a welcome boon to the state’s depressed economy and three legislators stand ready to help the Keystone State take advantage of what they call a once-in-a lifetime opportunity. And all three oppose attempts to institute federal regulation of hydraulic frac fluids.

“The Marcellus is an incredible opportunity. This is the next chapter for our state, and it’s home-grown energy,” says Rep. Glenn Thompson, R-PA. For more of his remarks, see the archived webinar at  UGcenter.com Surface Challenges In The Marcellus: Access, Water, Taxes now available on demand. Thompson represents the Fifth Congressional District, which includes 17 western Pennsylvania counties.

“I see this as another great well, but one that is much longer lasting. A recent Penn State study showed that the Marcellus created 29,000 jobs just in one year, 2008.”

Rep. Tim Murphy, R-PA, who represents the 18th District, says, “Lo and behold, it’s as if we hit the lottery. This is contributing to jobs, wages…But with this great opportunity comes great responsibility. We’ve got to manage this right.”

Murphy, whose district includes southwestern Pennsylvania counties, is founder and co-chairman of the recently formed the House’s Natural Gas Caucus, which now has 45 members from both parties. Thompson is also a member. The caucus is promoting more natural gas use for power generation and fleet vehicles.

The legislators oppose attempts in Congress to regulate frac fluids, saying the states already do so. State Sen. Gene Yaw, R-Loyalsock, representing Pennsylvania’s 23rd State Senate District, including Susquehanna County, says, “This is a piece of legislation that is just not needed. Fracing has changed dramatically in the last two years. One problem people have is how do we treat the frac water? But one of the natural gas companies has made it so that virtually no water comes back out of the ground (when drilling).”

Murphy says it is very important that the energy industry speak up on this topic. Thompson calls it “a bad bill.”

Yaw notes how cooperative Marcellus operators have been, and that they are concerned with safety and community relations. Yaw recently led the filming and production of the first-ever, large-scale safety-drill video for the state’s first responders. The video, which was underwritten by Range Resources Corp. (NYSE: RRC), was filmed in his district, in Lycoming County at one of Range’s locations.

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

By now, you’ve seen a  lot of comment on this deal, ExxonMobil’s first corporate acquisition in a  decade, and the first grab of a super-independent since ConocoPhillips acquired Burlington Resources–that also was a predominantly natural gas play.

I now count at least $53 billion for assets acquisitions, corporate mergers or joint ventures in shales, including ExxonMobil’s deal, which will total $41 billion when accounting for the XTO debt assumed. Recall that in the past 18 months, XTO spent at least $11 billion snapping up primarily shale and tight-gas assets to build a strong platform for long-term growth. (See Oil and Gas Investor A&D editor Steve Toon’s detailed treatment of this in the August 2008 issue, in a piece titled “Transforming XTO.”)

It seems the largest shale players have become the farm teams for the majors and national oil companies.

The interest in shales continues: We hear from our sources that the China National Petroleum Co. (CNPC) is asking around, through the DOE, to have an independent host a tour of a shale operation. This fits in with the U.S.-China energy technology exchange program inked between the Obama administration and Beijing recently.

The XTO deal sends sevral signals to themarketplace. The value of the shales as a long-term gas source has been validated by the savviest company out there: ExxonMobil is known for being conservative and taking its time, and making no big, bold move without first studying it to death. It implies faith in the long-term gas price outlook, and demand outlook.

If any particular shale is not economic now, it will be some day. If EURs are in question, as they have been by some critics, that argument has been tamped down. The shale story will continue, and ExxonMobil will now have a hand in telling it.

ExxonMobil has a lot on its plate around the world, from LNG in Qatar to spending a rumored $1 billion to fund a new purpose-built drill ship for the Arctic, to R&D on algae as a fuel source. That it decided to add natural gas shales to the portfolio says a lot.

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

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