[C8]

At this rate- shale may be competitive and profitable at prices much lower than previously thought

Shale Drillers Squeeze Costs as Era of Exploration Ends

The pioneers of America’s shale gas and oil revolution have done their work. Now it’s time for the factory crews to take over.

After spending $53 billion on a land binge to find hydrocarbons, the petroleum industry is counting on technological innovations -- better imaging data, speedier and longer horizontal drilling, among them -- to ramp up the flow of oil and gas from U.S. shale fields where they’re drilling more than 10,000 wells a year.

The techniques are embraced by the biggest producers from shale such as Chesapeake Energy Corp. (CHK) and Newfield Exploration Co. (NFX) to boost shareholder returns by shifting money from exploration, which is winding down, into what’s known in industry parlance as manufacturing. The moves will help producers increase profit at a time shareholders are ousting executives and revamping boards because of poor performance.

“Now that all of the established shale plays are known, companies can start focusing on the economics of these plays,” said Eric Gordon, who helps manage $35 billion at Brown Advisory Inc. in Baltimore. “They are under pressure to reduce drilling time and operating costs.”

In Oklahoma, Chesapeake is blasting cracks into rocks surrounding each well at 10 times the rate of a few years ago. Newfield is using finely tuned mixtures of chemicals and minerals to stabilize wells that slice sideways through crude-soaked rock 10 times farther at half the cost per foot of a decade ago.

Land Rush

Producers that engaged in a land rush yielding vast shale discoveries from Pennsylvania to Wyoming and Texas are now being pressed by shareholders to turn promises into profit, said Brian Gibbons, a debt analyst at CreditSights Inc. in New York. By employing new technology, domestic explorers aspire to catch up with international energy titans such as Exxon Mobil Corp. (XOM) that generate six times as much profit from each barrel of oil.

Measures to cut per-unit production costs also are key to coping with oil and gas prices that are one-third and two-thirds lower, respectively, than their 2008 peaks. Soaring output from wells in North Dakota, Oklahoma and Texas has driven a 3.2 percent increase in U.S. crude production this year, adding to the 19 percent rise in 2012 that was the biggest annual jump in at least three decades, according to Energy Department figures.

Independent U.S. oil and gas companies -- those that focus on production and don’t refine crude into fuels and chemicals -- ended 2012 with an average cash-flow deficit of $1.5 billion, compared with an average surplus of $386 million for the world’s biggest energy producers.

Shifting Gears

Independent U.S. explorers spent more than $53 billion during the past decade snapping up drilling leases as breakthroughs in horizontal drilling and hydraulic fracturing allowed explorers to access previously impenetrable formations.

Of the 17 companies in the Standard & Poor’s 500 Oil & Gas Exploration & Production Index, Chesapeake was the biggest spender on prospective U.S. oil and gas leases with $19.9 billion from 2003 through 2012, according to data compiled by Bloomberg. The company, whose shares lost 36 percent from 2010-2012, on May 20 said it hired former Anadarko Petroleum Corp. (APC) Senior Vice President Robert Douglas Lawler as its new chief executive.

Chesapeake, the world’s largest driller of horizontal shale wells, said as early as March 2012 that all of the major untapped petroleum deposits in the continental U.S. had been discovered.

Expanding Sights

EOG Resources Inc. (EOG) Chairman and Chief Executive Officer Mark Papa told analysts on May 7 that the company’s exploration unit is now looking for overlapping, oil-bearing geological formations that can be simultaneously tapped to extract “substantially larger” quantities of crude. Houston-based EOG is the largest owner of drilling rights in Texas’s Eagle Ford shale.

The payoff for the deeper-farther-faster approach remains to be seen for Chesapeake and explorers such as Devon Energy Corp. (DVN), QEP Resources Inc. (QEP) and Southwestern Energy Co. (SWN), which have the poorest records of turning untapped reserves into barrels of crude for sale.

Producers use a calculation called the recycle ratio as a measure of profitability, dividing profit per barrel of production by the cost of discovery and extraction. So a $40 profit divided by $20 in costs yields a recycle ratio of 2:1, or 2. A higher number represents more profitability.

Recycle Ratio

Denver-based QEP’s recycle ratio was 0.69 in 2012 and Chesapeake posted a 0.97, data compiled by Bloomberg show. In contrast, Exxon scored a 4.5 and Total SA (FP) had a ratio of 3.3. The ratios include three-year averages for reserves used in calculating costs for the companies.

The best performers in the exploration and production index were Denbury Resources Inc. (DNR), which uses carbon dioxide to coax more oil from wells, and Range Resources Corp. (RRC), the second-largest holder of drilling rights in the Marcellus Shale. Both logged recycle ratios that surpassed Chevron Corp. (CVX)’s 2.5 and BP Plc (BP/)’s 2.8.

Devon and QEP said several factors lowered their recycle ratio numbers in the past couple of years, including falling gas prices that cut revenue as they shifted more drilling to oil projects, which are costlier than gas.

During the shift, the company is recording higher costs without yet getting the full benefit of bigger profits, said Vince White, Devon’s senior vice president of communications.

Improving Results

QEP incurred costs from an acquisition before production materialized from the assets, said Greg Bensen, director of investor relations at the company. QEP looks at the ratio using a multi-year view, he said.

Though Southwestern has some of the lowest costs in the industry, gas prices that collapsed to a decade low in 2012 reduced cash flow and forced the company to erase some proved reserves from its books, elevating per-unit costs for finding and development, or F&D, CEO Steve Mueller said in an e-mail.

“As the gas price increases, the F&D will drop dramatically as reserves are returned to the books and the yearly recycle ratio will be one of the best in the sector,” Mueller said.

Jim Gipson, a Chesapeake spokesman, declined to comment.

Analysts expect rising profits and stock prices will come to producers who embrace a manufacturing model, according to data compiled by Bloomberg.

Rising Earnings

Chesapeake, which reported on May 1 a first-quarter profit of 30 cents a share excluding one-time items, is expected to see adjusted income of 43 cents a share in the comparable period next year and 49 cents a share in the fourth quarter of 2014. At Range, analysts estimate per-share adjusted earnings may almost double to 63 cents in the fourth quarter of next year, compared with 33 cents in the first three months of 2013.

Newfield’s average 12-month target price from analysts’ estimates compiled by Bloomberg is $33.75, 48 percent more than the closing price yesterday. Denbury’s target price is $23.71, a 30 percent increase from yesterday’s closing price.

Energy producers and the oilfield-services companies they hire to help drill wells have continued to refine their techniques and equipment to increase the amount of oil and gas that can be squeezed from shale and other unconventional formations. Drilling sideways through the length of a field puts the well in contact with a larger section of oil-soaked rocks than a traditional vertical well.

Longer, Cheaper

Newfield is now drilling lateral wells as much as two miles long, 10 times the length of the horizontal bores used at the dawn of the shale revolution during the last decade, Clay Gaspar, a vice president at The Woodlands, Texas-based company, said in a telephone interview. In the last 18 months, the company cut the cost of drilling sideways by more than half to about $1,000 a foot, he said.

In Oklahoma’s Cana Woodford region, new techniques and improved materials are giving Newfield’s crews better access to the well bore, allowing them to isolate smaller zones to target fracturing more precisely. Newfield crews are shattering the rock two or three times more frequently in wells with twice the lateral length of the 5,000-foot wells they were drilling just 18 months ago, Gaspar said. That equates to clusters of fractures approximately every 300 feet compared to more than 400 feet before.

“The world we live in today is all about manufacturing and it’s trying to get to the point where that experiment that we do becomes repeatable,” Gaspar said. “We’re using a lot of the same efficiency techniques that other manufacturing organizations have used over the years.”

Saving Time

Chesapeake has reduced the time it takes to drill wells in the Eagle Ford shale to 18 days from 25 days a year ago, according to a presentation published on the company’s website on May 13. Chesapeake is aiming to eventually lower that to 13 days. The Eagle Ford will account for 35 percent of Chesapeake’s capital spending this year, more than any other single region, the presentation showed.

In Ohio’s Utica Shale, Chesapeake has lowered its cost to drill wells to $5.9 million each from $8.5 million, a 30 percent decline, according to the presentation. The company has 14 rigs drilling in the Utica region.

Noble Energy Inc. (NBL) is drilling wells in Colorado’s Denver-Julesburg Basin with 9,000-foot horizontal bores that the company’s engineers estimate will ultimately produce the equivalent of 1 million barrels each, Chief Operating Officer David Stover said during an April 25 conference call with analysts. That’s compared to the 40,000 barrels per well that the company was targeting three years ago with traditional vertical wells.

Prime Targets

Producers are searching for ways to boost efficiency and curb costs before drill bits even begin chewing into rocks to start a new well, said Gregory Powers, vice president of technology at Halliburton Co. (HAL), the world’s largest provider of hydraulic fracturing.

Three-dimensional modeling of subterranean formations help oil producers predict the nature, location and permeability of crude-rich reservoirs, Powers said during a meeting with reporters at Halliburton’s Technology Center in Houston on May 9. Prospectors also are taking advantage of better technology in steering drill bits to precise locations deep underground.

“How much better is it?” Powers said. “It’s immensely better than just 10 years ago.”

To contact the reporters on this story: Joe Carroll in Chicago at [email protected]; Edward Klump in Houston at [email protected]

[ROCKMAN]

C8 – Time will tell. It’s difficult to make generalities (positive or negative) given the variations between plays, the companies and the specific acreage positions those companies control.

Talking to the folks who are actually drilling and frac’ng all those Eagle Ford wells there seems to be two well established facts. 1: they have definitely got the cost per foot drilled down a good bit. 2: it isn’t going to get much cheaper. They say they have optimized all the aspects pretty much as far as they think they can. That’s still the good news. The not so good news the cost per frac job hasn’t come down significantly and probably won’t as long as activity stays where it is now. The price of frac’ng is presently very demand driven. For the most part the same equipment and materials that were used initially are still being utilized. And while the cost per foot drilled has decreased those extra lengths are requiring more frac stages…20+ in many cases. Many of the longer laterals are costing more to frac than it does to drilling hole. IOW a $5 million lateral might use $6 million in fracs. So when a company claims the are “drilling” their laterals for $1,000 per foot the question is whether that’s the total cost including the fracs or just the cost to drill the hole. Often not enough detail provided to know.

So drilling longer laterals with more frac stages may make for greater efficiency it doesn’t mean a better profit margin. In some cases yes…others no. Every geologist and engineer I know that’s playing the EFS has serious concerns about lower oil prices hurting their drilling programs. Others are free to express an opinion that the plays can handle lower prices. But I’m talking to the folks that are running economic analysis on a day to day basis and have to convince management to drill their wells. But, as I’ve said before, as long as oil prices stay about where they are and companies have undeveloped acreage they’ll keep drilling the shales as fast as possible because they have no choice IMHO: stop drilling and their reserve base declines and Wall Street will kick them to the curb.

As pointed out about some of the shale players:”…the company is recording higher costs without yet getting the full benefit of bigger profits, said Vince White, Devon’s senior vice president of communications.” IOW drilling longer laterals with more frac stages isn't lowering the cost per bbl for some companies.

“Newfield is now drilling lateral wells as much as two miles long, 10 times the length of the horizontal bores used at the dawn of the shale revolution during the last decade. Newfield crews are shattering the rock two or three times more frequently in wells with twice the lateral length of the 5,000-foot wells they were drilling just 18 months ago”. And just a footnote to explain why this statement is utter BS: The Austin Chalk, essentially a carbonate shale, was the hottest oil play in the country about 20 years ago. And they were drilling two 1-mile long laterals in opposite directions out of single vertical well. Even more dramatic than what’s being done today: they were PWD wells (producing while drilling). Heavily fractured reservoirs are very difficult to drill: the drilling mud would tend to flow very easy into the reservoir via those fractures. So they would intentional lower the mud weight below what was needed to keep the well from flowing oil/NG while drilling. I was on a few such locations where 100’s of bbls of oil and a million cuft of NG were coming out of a well bore while we were drilling. Basically it was a controlled blowout. The oil went into tanks and the NG flared. Very exciting and scary all at the same time. The drilling in the shales these days is rather tame and fairly standard compared to those wild days.

And not that Wall street is always right but compare what they are saying to how they are actually responding to these plays. EOG is probably the most successful shale player. While they have had a nice gain in value of around 7% per year since the shales began they are just back to the pre’08 oil price bust. And Chesapeake and Devon, two other big shale players, have remained flat in value to dropping a tad throughout this great and profitable “boom” they’ve been participating in.

Wall Street appears to be more willing to talk the shale plays up then to actually back up those words with their checkbook. Maybe some of them would like folks to buy their stocks before an oil price slide and their values drop even more than some have in the last year.

[C8]

But Rockman, how can being more efficient not lead to greater profits? Isn't the definition of efficiency getting more done with the same effort?

[C8]

great- I wait for my 100th post to get out of being 'coal' and find that I am 'tar sands'- life isn't fair.

[ROCKMAN]

C8 – Certainly can work that way…all things being equally. And that the frustrating thing about reservoirs like the fractured shales. Even for a company with access to every bit of their detailed engineering and geologic data and some very smart folks it can be difficult to tell (at least in the short term) if you’re really doing better…better being more profitable. It’s obviously easy to know what you’re spending to drill per foot of hole. Two wells drilled side by side in an identical fashion could yield very different outcomes. Or two wells drilled very differently in very different areas could have the same outcome. Two wells drilled on the same location using identical tech but drilled by two different companies could have very different outcomes because all companies aren’t as good as getting it done as others.

Now take all those variables, throw in a big can, shake and dump out on the ground. Now cover with a sheet. That’s because none of us, even in the oil patch, will ever have all those individual details from all the other companies. Now start cross plotting all the results and tell me how everyone is doing.

Seriously: I’ve worked projects where internally there were raging debates about the answers to such questions. It really is a very difficult analysis for the pros with all the data. Now switch to us armchair reservoir engineers with few of the details. LOL.

[Pops]

One thing rarely talked about is how cheap money has been the last few years and how the lack of a good return has pushed more and more capital out of "safer" investments trying to find a return in riskier areas. I'd put oil exploration in that riskier category.

What happens to the profit margins when the fed gets out of the QE and mortgage lending game and rates rise? And even more, what happens when credit availability dries up because mutual fund managers can find a return in a "safer" arena?

Here is a good article on the current situation, it's from a series called Dumb Money and this installment talks about recent comments from the advisory council to the Fed about just this...

[Oily Stuff]

Outstanding, Pops. What happens? Well, the party is over, I think that is what happens. I don't thing these shale dudes can keep their stock all puffed up if they can't draw on enormous lines of credit to stay on the treadmill. If they can't borrow money, can't raise money at Merrill Lynch, and income is declining at the rate of 75% every 2. 54 years, or whatever the decline rate is, hold on to your knickers.

"What a tangled web we weave when it is we try to deceive."

A very important part of this tight oil equation, borrowed money. Thank you.

[Graeme]

Just How Expensive Is Shale Oil?

While new technologies such as fracking and horizontal drilling are largely responsible for the boom in U.S. oil and gas production, the costs associated with these so-called "technological barrels" are on the rise.

So exactly how costly is shale oil production? Staggeringly expensive, according to a new report from a leading energy research firm. Let's take a closer look.

Costs still rising
According to recent estimates by Sanford C. Bernstein, a research and consulting firm, non-OPEC marginal cost of production rose last year to a whopping $104.50 a barrel, representing more than a 13% increase from $92.30 a barrel in the previous year.

What's more is that marginal production costs for U.S. drillers rose by even more, in both relative and absolute terms, from around $89 per barrel in 2011 to a remarkable $114 a barrel last year. While many have argued that rising marginal costs of production for unconventional oil projects will help buoy oil prices by driving a floor underneath prices, they're also limiting the industry's profitability.

Bernstein's findings are worrying, because they imply that new technological improvements aren't enough to bring down the industry's overall marginal costs. "What we call technological barrels are day after day more expensive," Christophe de Margerie, chief executive of French oil giant Total (NYSE: TOT ) , recently told the Financial Times.

Implications for big oil
That's bad news for the world's largest integrated oil companies, which are seeing reduced profitability due to the double whammy of rising costs and a cap on oil prices as a result of increased supply due to the shale boom. Not surprisingly, profit margins among the world's 50-largest listed oil companies are currently the lowest they've been in a decade, according to Bernstein.

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[Pops]

Thanks Graeme, beat me to it.

Someone correct me if I'm wrong again, OilCo ABC had to spend $114/bbl to bring on an additional x number of barrels last year. But this year they will pay some lower figure to continue pumping oil from those wells. The article says "cash costs" are $44, that is the ongoing lifting cost for all wells, right?

Bernstein further finds that, over the past decade, marginal production costs have risen by about 250%, from just under $30 a barrel in 2002 to a record of $104.5 a barrel last year, while cash costs have increased from $9.70 a barrel to $44.20 a barrel over the same time period.

Here is the killer quote though:

...the upstream industry spent $2.4 trillion to produce 12.3 million barrels per day of additional oil output in the period 1995-2005.

Yet in the period from 2005 to 2010, the same level of spending actually yielded a decline of 0.2 million barrels per day.

I'm pretty sure Berstien has said production will go somewhere over 10mmb/d in a few years but that instead of a crash the price will start to rise again around '15

.

[rockdoc123]

Pops...unfortunately this is one of those terminology issues. The proper terminology for such analysis is "finding and development costs" of F&D which is all of the costs including land, people costs, drilling etc. to bring hydrocarbons on stream. Lifting costs are similar to operating costs....just the costs to produce the hydrocarbons once you have the wells and facilities in place. Break even costs are generally everything combined Capex and Opex (capital and operating expenses) to arrive at a $/bbl or $/Mcf number that corresponds to zero net present value.

The article is mixing up terminology somewhat when they say production costs are $30/bbl when I think what he means to say is breakeven costs are $30/bbl. As I remember normal F&D for most of the liquid rich shales is around $15 - $20 /bbl. Opex for the shale wells is not much different than for conventional and as I remember it is usually somewhere between $6 - $10/bbl. My numbers are likely out of date somewhat however.

In any event it is F&D costs that get you to the point you are producing and Opex that handles the cost to produce. There are of course cases where additional capital needs to be spent after a field has been producing for sometime (i.e. additional flow lines, compression, pumps etc) and generally that is not considered as Opex which makes the breakeven analysis more relevant.

Hope that wasn't too obtuse.

[SamInNebraska]

Let the shale drillers fall off the treadmill. After the surplus of drilled but not completed or producing yet for pipeline wells have been put on line, and their high rates of IP begin to decline (call it a year or two, if everyone stopped drilling tomorrow) the obvious consequence is gradually higher natural gas prices. Depending on acreage positions, partners, co. by co. drilling costs rig availability, results in each given acreage position, someone or a couple someones will start to drill again. More gas will be produced, if it isn't a boom then perhaps they won't drill enough to crash prices like last time, and the game becomes natural gas manufacturing similar to the way the Bakken is being developed for oil.

[Graeme]

Well, it appears that E&P (or is it F&D) costs are not the only ones that are rising. Apparently, reserve replacement costs are too.

According to Ernst & Young's annual U.S. Oil and Gas Reserves study, reserve replacement costs are some of the highest we've seen in several years. The average cost to replace a barrel of oil equivalent in 2012 was $32.72, almost double what it was in 2011. The closest comparable figure was in 2008, when reserve replacement costs were $39.34 per boe.

Reserve replacement costs can rise for two reasons. The most obvious one is that it becomes more difficult to find new resources, so the cost to find a new barrel of oil goes up. Most of the time, the cost of oil moves in tandem with reserve replacement costs. As prices for oil increase, companies are more willing to explore higher-cost, higher-risk regions, and they may not always find oil. One example is Royal Dutch Shell's (NYSE: RDS-A ) attempt to find oil offshore from Alaska. The company has spent $4.5 billion in the region but has yet to produce a barrel of oil from the region. The company can take such a chance on this region is because the price of oil gives it some flexibility.

The other reason reserve replacement costs might increase can make numbers go haywire. A company's reserves are based on the amount of oil the company can economically extract based on current prices. If the price of oil goes down, though, a company needs to write down some of its reserves, because they can't be feasibly produced at the lower price. So the replacement cost of what it has today goes up, since the company needs to replace both the oil and gas it's currently producing, as well as the amount lost to these asset writedowns. According to Ernst & Young, the high reserve replacement costs in 2008 were largely related to writedowns, because oil prices dropped by almost $100 a barrel. Whenever oil prices take a big nosedive, as they did in 2008, you have to take reserve replacement costs with a small grain of salt.


In 2013, capital expenditures for E&P are expected to be higher than they were in 2012, but because we can't exactly predict the movements of oil prices, it will be difficult to determine what 2013 reserve replacement costs will look like. One indicator that reserve replacement costs may remain high is that integrated majors such as BP and Shell are some of the biggest spenders when it comes to exploration and production. These two have reserve replacement costs well above the industry average, which will skew replacement costs higher for everyone.

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