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Shale boom: Pa. leading the way in May

Posted on 06 June 2013 by shalenow

Shell7P-1024x400SALEM, Ohio — The number of permits issued for drilling in the Utica shale in Ohio stayed strong during May.

According to the Ohio Department of Natural Resources permit list, Harrison County led with the number of permits issued. A total of 16 permits were issued during May.

Harrison County

A total of 10 permits were issued in Harrison County to Chesapeake Exploration in North Township and one was issued to Chesapeake in German Township. Four permits were issued in Freeport Township to Gulfport Energy Corporation and one was issued in Cadiz Township to Hess Ohio Development LLC. The additions bring the total number of permits issued to date to 98.

Noble County

Behind Harrison County was Noble County where 10 permits for horizontal drilling through the Utica shale were issued in May. All of the permits were issued in Seneca Township with seven permits issued to CNX Gas Co. LLC and three to Antero Reserve Appalachian Corporation.

There are now 42 permits issued in Noble County for Utica shale wells, according to the ODNR.

Carroll County

Seven permits were issued in Carroll County in May. Chesapeake Exploration received permits for four sites in Loudon Township, and one in Perry Township. R.E. Gas Development LLC received permits for two sites in Washington Township.

There are now 266 total permits issued in Carroll County, with 103 wells drilled, 51 wells producing and the remainder are still in the permitting stage.

Columbiana County

The ODNR reported four permits were issued in Columbiana County bringing the total number of well permits issued in the county to 71. The permits were issued in Hanover and Franklin townships to Chesapeake Exploration.

Mahoning, Portage Jefferson

New permits were also issued in Mahoning County to Hilcorp Energy Company for two wells in Poland Township. In Jefferson County, Chesapeake Exploration received a permit for one site in Smithfield Township.

A permit was issued in Portage County Mountaineer Keystone LLC for a site in Nelson Township.
According to the ODNR permit list, a total of 686 horizontal permits have been issued and 335 have been drilled.


Across the state line in Pennsylvania, the Department of Environmental Protection reported issuing 171 permits and 131 wells were drilled during May.

Sites in Greene County, a county south of Pittsburgh, received 33 permits for drilling and eight wells were drilled in that county during May. The permits were issued to Alpha Shale Reserve LLP; EQT Production Company, Chesapeake Appalachia,Chevron Appalachia, LLC and Vantage Energy Appalachia LLC.

In Washington County, the DEP issued 23 permits for drilling into the shale. The permits were issued to EQT Production Co.;Range Resources Appalachia LLC.; Chesapeake Appalachia; CNX Gas Company, LLC; Noble Energy Inc. and Rice Drilling B LLC.

Twenty-one wells were drilled in Washington County throughout the month.

In Bradford County, further east and where the shale boom began, 19 permits were issued for new wells, and 22 wells were drilled during May. The permits were issued to Talisman Energy USA Inc., Chesapeake Appalachia, and Southwestern Energy Production Company.

Butler County

Drilling also appears to be ramping up in Butler County. There were six wells drilled during May and six permits were issued. The permits were issued to EM Energy Pa. LLC., R.E. Gas Development, LLC., XTO Energy Inc. and Swepi, LP, a division of Shell.

Beaver and Lawrence

In Beaver County, three permits were issued, and in Lawrence, two permits were issued in May.

The permits in Beaver County were issued to Chesapeake Appalachia, LLC and PennEnergy Resources, LLC. The permits issued in Lawrence County were issued to R.E. Gas Development LLC and Hilcorp Energy Co. A total of seven wells were drilled in Lawrence County, according to the DEP wells drilled report.

Three permits were issued in Allegheny County and three wells were drilled, according to the DEP. The permits were issued to Range Resources Appalachia.

One permit was issued in Armstrong County and two wells were drilled. The permit was issued to Snyder Brothers Inc., according to the DEP.

West Virginia

The West Virginia Department of Environmental Protection also issued permits for drilling in the Marcellus shale during May. There were no permits issued for drilling through the Utica shale.

There were a total of three permits issued in Marshall County during May. The DEP issued two permits for farms in Marshall County to the driller Noble Energy Inc., and one permit was issued to Gastar Exploration USA, Inc. on a piece of land owned by Bayer Material Sciences, LLC.

In Wetzel County, a permit was issued to Chesapeake Appalachia, LLC for property owned by Ridgetop Capital L.P.

Two permits were issued for wells to be drilled on two farms in Marion County by Trans Energy, Inc.


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An Exciting Time to be an Energy Investor

Posted on 26 May 2013 by shalenow

image001Is this a great time to be an energy investor? It definitely is, according to Matt Badiali, editor of the S&A Resource Report. “You can make a lot of money, unless you’re Bill Powers,” he says in this interview with The Energy Report. Badiali discusses the true potential for U.S. natural gas, as well as what type of energy really gets him excited.

Matt Badiali: The main reason we’re still at $95/bbl, with demand falling and production rising is exports. It’s been illegal to export crude oil from the U.S. since the ’70s. However, refiners have gotten around this rule by exporting “finished products” like gasoline diesel fuel, for example.

Remember, Europe and Asia are paying a lot more per barrel than we are. Our refined goods can be economically put on a ship and sold competitively in those markets for a lot more money than they can get here. One of the reasons that this is big business is that we’ve dramatically increased the amount of oil that we’re producing at home. The secret is about half of that oil isn’t what we consider crude oil—it’s natural gas liquids. It can legally be sent out to other markets because it’s not crude oil.

Let me give you an example. Mexico has consistently been one of the U.S.’ major sources of oil and gas imports. In 2005, we were getting about 1.4 million barrels per day (1.4MMb/d). However, as our demand has fallen off, exports have been growing. Now the U.S. only takes about 400,000 b/d from Mexico. Imports fell off 41%, but our exports to Mexico grew by 200%. The U.S. is now the world leader in exporting finished product, which I don’t think many people understand. That, in a nutshell, is why we’re still paying $90–100/bbl.

TER: Does exporting these resources help or hinder our energy independence? Do you think that unconventional drilling will turn us into “Saudi America” or are we overestimating well lives and underestimating the cost of fracking?

MB: On the one hand, there are the “Saudi America” folks who are really optimistic about both the technology and the ultimate supply of oil and gas in the U.S. On the other hand, you have energy investor Bill Powers, who has got his arms folded across his chest and his chin out, just saying “No.” That’s his answer to everything.

I don’t know if we’ll ever be energy independent. Honestly, to me, that’s a non-argument. It’s going to be market forces that drive whether we’re importing oil from somewhere else or if we’re using our own and exporting. That’s not as big a concern to me as the argument that Powers made, which is we don’t have enough. I think he’s wrong. I don’t think that he understands the context of our success.

The peak oil theory never ever considered the idea that we would ignore the conventional rocks and just go straight to the source. Our oil field went from the size of a group of oil tankers in the Gulf of Mexico to the Gulf of Mexico. That’s the size of these systems. They’re enormous. I’m sure Bill is a nice guy, but he’s dead wrong.

TER: What about the theory that these new sources are expensive to access?

MB: That was going to be my next point. Bill has said even Chesapeake Energy Corp. (CHK:NYSE) was forced to write-down 20% of its reserves in 2012. That was 4.6 trillion cubic feet of natural gas reserves gone, right? Clearly this is unsustainable. Well, the reason that they wrote those reserves down isn’t because the gas disappeared. It’s because we found so much that the gas price went to $1.80 per thousand cubic feet ($1.80/Mcf) in 2012. A company can’t produce natural gas for $1.80/Mcf in these unconventional fields. We have shut down drilling in huge shale plays because of the economic component.

TER: What price does it have to be in order to make these fields economical?

MB: It’s not a point; it’s a continuum. Some stuff works really well at $3/Mcf. The Marcellus in Pennsylvania works great at $3/Mcf. The Barnett Shale in Texas, on the other hand, wouldn’t be economic at that level. And the enormous Bakken Shale in North Dakota doesn’t work if oil prices fall too low. They have to put oil on trains, which is at least twice as expensive as what it would cost to put it in a pipeline.

TER: Do you think that will be the impetus to get pipelines built?

MB: I hope so, but that’s a slow process. As we develop these fields, natural gas prices are going to have to inch higher if we run out of cheap plays. The industry has been remarkably flexible at finding cheap sources or making things cheaper to meet the price of natural gas.

Low prices are going to stimulate demand. I’ve seen it happening in my own town. We have a couple of pulp mills on the island where I live. Several months ago, one of the mills switched from fuel oil to natural gas. They’re saving millions of dollars per month on fuel costs. The company that owns the mill is doing this at all its mills. We’ve seen a lot of power plants that have switched to natural gas because it’s cheap.

TER: Of course, it would be a game-changer if truck fleets switch to natural gas. But is that practical?

MB: I do think it’s practical. Americans are ingenious at ways of making use of cheap things. I see enormous demand for natural gas. Demand will increase, pushing the price of natural gas incrementally higher and driving down the price of oil.

TER: What about Bill Powers’ theory that the decline rates in fracked wells are much higher than anticipated? What are you seeing out at these wells?

MB: You finally found something that Bill and I agree on. The decline rates are enormous. But Bill is applying conventional oil field metrics to unconventional fields. In a normal field, these kinds of decline rates would mean that the field stinks. We’re drilling so many more wells in the shale that the decline rates don’t matter. Think about the scale. They’re so big people can’t get their heads around it. They simply refuse to understand it. Every day, every month, every year, we get better at using our technology and improving our ability to get at this stuff. The only barrier I see right now is political.

TER: How long will the price deferential between Brent and WTI stay as wide as it is now and what’s keeping it there? Is that political?

MB: That’s structural. Refineries in Europe were built and geared toward one kind of oil that comes out of the North Sea: Brent. It’s very hard and it’s expensive to change around the system to accommodate new oil. All these refineries are geared to Brent—the amount of Brent fell, the volume fell, the demand rose and prices soared.

It created a market for our finished fuels. We were sending ship after ship to Europe with diesel fuel. Our refiners made a huge profit because, at $90/bbl, we could stick it on a ship, send it to Europe and stay below $120/bbl to convert into diesel.

I’m sure there are some savvy entrepreneurs over there who will invest the money in changing around their refineries to accommodate different crude stocks.

TER: Where are you investing in to take advantage of this?

MB: The problem with these unsettled periods is that they’re hard to figure out. I invested in Italian oil company Eni S.p.A. (E:NYSE) because I want to take advantage of high prices. I’m still mildly concerned about the domestic oil price falling or being subject to down pressure. Why not buy a company with oil that is sold on the Brent crude price? It’s a major oil company that’s been around forever. It operates in all the places that U.S. companies won’t go. It pays a nice dividend.

I also have to give credit to Porter Stansberry. He’s done a remarkable job at seeing the big picture and knowing where the plays are. Stansberry recommended Burlington Northern Santa Fe LLC (BNI:NYSE), the railroad that was getting a lot of the oil from the Bakken out to the market. That was a great oil and gas play. He also recommended Chicago Bridge & Iron Co. N.V. (CBI:NYSE) to take advantage of the expanding pipelines.

I think that there are some fantastic opportunities in the pipeline space, but I’m late. They’ve gotten expensive.

TER: Do you like MLPs?

MB: I like MLPs, but I’m afraid that they’re a little expensive right now. You want exposure to that climbing price, but right now you have a 50/50 chance of the oil price going up or going down. I want more certainty. I’m looking for yield that might be mispriced. I’m looking for yield with hedges. There are some opportunities out there, however.

The thing you don’t want to do right now is buy natural gas royalty trusts that are pure natural gas. There’s one in particular that I’ve really liked for years called San Juan Basin Royalty Trust (SJT:NYSE). In a good market, San Juan Basin just prints money because it’s a royalty trust on a chunk of land in New Mexico and Colorado. The wells are being drilled and operated by ConocoPhillips (COP:NYSE). San Juan just shows up and gets a check and distributes the check to shareholders. It’s a great business—except ConocoPhillips recently said that gas prices are too low to economically drill any more wells in the San Juan Basin. That was that.

Related Article: Prices are Set to Rise, but Survival is Not Guaranteed for Natural Gas Companies

TER: Another form of energy that’s been in the headlines lately is uranium. When we talked in January, you pointed to a pushback on the nuclear moratorium in Japan because of increasing energy prices and brownouts. Japan’s working on new safety guidelines that could lead to reopening reactors. China has 29 reactors under construction and another 51 planned. What impact could that have on uranium prices?

MB: Oh, man. I’m so excited about uranium. There’s all this uncertainty in oil and gas, but there’s very little uncertainty in uranium. It’s just a matter of time. If you can be patient, you’re going to make a lot of money in the uranium space. Right now, uranium is priced as if we will never produce electricity from nuclear power again and that’s not true.

The Fukushima Daiichi event was such a horrible disaster and it just scared the heck out of all of us—nobody wanted to own uranium. There was a lot of overreaction. The fact is Fukushima was a dangerous plant to begin with. It was built in a colossally, geologically unstable location on a subduction zone. In comparison, the San Andreas Fault is a fender bender. The earthquakes that happen on subduction zones are 15-car pileups. That was exactly what happened at Fukushima.

There has been a timeline set out for the Japanese reactors to come back online. As Japan gets back to normal, it will be a catalyst. We still have construction happening in China. We have construction happening in India. We have construction happening in Saudi Arabia. There is new demand coming on in the next 12–18 months.

If you’re a conservative investor, try Cameco Corp. (CCO:TSX; CCJ:NYSE), the ExxonMobil of uranium. It has major supply agreements with all of the major nuclear power producers.

Then you go down from there to some other little producers. Denison Mines Corp. (DML:TSX; DNN:NYSE.MKT) is a great one. Energy Fuels Inc. (EFR:TSX) has production. These companies are producing at $40 a pound ($40/lb) and breaking even, but once the price of the uranium goes up, their profits are going to grow because they’ve already covered their costs. These companies are going to start popping up on people’s radar screens, and investors are going to wonder why they’re trading at 3x earnings.

The uranium sector right now is a textbook opportunity. It was a hated commodity that was left for dead and we see the uptrend coming. If you’re willing to wait 18–24 months, you can very easily double your money here.

TER: If it’s going to take a little while for Japan and some of these facilities in China to come online, are you looking at companies that are producing now or companies that will be producing once that demand kicks in?

MB: The conservative bet is to go with companies that are in production and making money at the current price. That’s Cameco. That’s Uranium Energy Corp. (UEC:NYSE.MKT) in Texas. Then you have the explorers that are developing new stuff. That’s UEX Corp. (UEX:TSX) in Athabasca in Canada. That’s Kivalliq Energy Corp. (KIV:TSX.V) up in Nunavut. That’s Fission Uranium Corp. (FCU:TSX.V) in Athabasca.

The explorers are the companies where you’re going to take on more risk because they’re not in production. However, I do think there’s a lot of upside. I would buy them when the uptrend starts to take hold. Right now, I’m more conservative.

TER: Energy Fuels has four producing mines and a number of others that are still in development. Do you like that mixture?

MB: Absolutely. Mines are finite producers. A mine is like a loaf of bread. You get so many sandwiches out of it and then you’ve got to get another loaf of bread. I love to see companies that have mines in production, mines about to go into production and several exploration projects. That’s the ideal mining company.

TER: Is this a good time to be an energy investor?

MB: Yes, without question. It’s exciting, it’s fun and you can make a lot of money, unless you’re Bill Powers—then you’re going to stand in the sidelines with your arms crossed and your chin up.

TER: Thank you for taking the time to talk to me.

MB: You’re welcome.

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At margins of shale oil boom, a tempered euphoria; Number of women landing jobs in oil, gas industry growing

Posted on 21 May 2013 by shalenow

A naturally occurring oil seep is seen in McKittrickFor the past three years, the boom in the U.S. shale oil industry has outstripped all expectations. Production surged far faster than any forecasts; drillers raced to secure space in new pipelines to get their crude to market.

Now, at the periphery, that may be changing – at least for a while.

News from two of the country’s less developed shale plays in Colorado and Ohio last week offer a reality check for the wave of euphoria that has washed across the industry. The stumbles mark a break from the past few years, when nearly every new project was an overnight success and output grew and grew.

On Thursday, Ohio, home to the Utica shale, finally released annual data on 2012 production that showed the state pumped less than 700,000 barrels of oil from its shale wells — barely enough to fill a small oil tanker. North Dakota’s Bakken shale pumps more than that every day. Even state officials said it the result was “lower than initially estimated.”

The day before, NuStar Energy LP had said it would shelve a plan to reverse a pair of underused refined products pipelines to ship crude from Colorado’s Niobrara shale oil play to Texas. It failed, twice, to garner enough commitments from potential customers to justify investing in the conversion.

Neither development was a surprise to industry experts, and both were likely affected by extenuating circumstances.

A growing preference for rail shipments likely dimmed interest in long-term commitments to use NuStar’s pipeline. Ohio’s shale may yet offer up large volumes of liquid gas and condensate, if drillers can find new ways to coax it out.

Yet taken together they offered a sign that the flush of enthusiasm and rush of investment that piled into shale fields from one coast to the other has hit a curve.

While the basic technologies of hydraulic fracturing and horizontal drilling was enough to coax an unexpected gusher of oil from shale rock in many regions, these more challenging seams may require incremental innovation to unlock.

“This is all about technology,” said Sandy Fielden, an analyst at RBN Energy in Austin, Texas.

“The bottom line is that this stuff is down there, it’s just figuring out the sweet spot of where to get it and the right conditions to get it out.”

For now, few are questioning the notion that the booming Bakken and Eagle Ford and Permian Basin in Texas will keep growing, driving domestic oil production beyond its highest in two decades and shrinking America’s reliance on imports.

But the breakneck pace of the past three years was unlikely to last forever.

“The companies have established their acreage positions, they have established sweet spots, but there are still a number of really enormous challenges in understanding how to most efficient and effective ways to maximize production in the long run,” Pete Stark, senior research director at IHS.

“We’re in the start of the second inning in a nine-inning ball game as far as know-how.”


Niobrara and Utica are not the first shale plays to disappoint investors. Michigan’s Collingswood enjoyed a mini-boom for a few months in 2010; California’s huge Monterey shale has thwarted drillers for years.

Yet the scale of the let-down is remarkable.

Just two years ago, Chesapeake Energy’s former CEO Aubrey McClendon put the Utica on the map, proclaiming it could hold a $500-billion bounty and that it would be the “biggest thing to hit Ohio since the plow”. Oil companies including Total spent billions of dollars buying drilling rights. State geologists estimated that it could hold between 1.3 billion and 5.5 billion barrels of oil reserves, a vast sum.

“The Utica has failed so far to live up to its hype,” said Ed Morse, managing director of commodityresearch at Citigroup.

According to Reuters calculations, the average oil production per well per days the well was active, was 80 barrels per day – about one-tenth what it is in North Dakota.

Jonathan Garrett at Wood Mackenzie in Houston says the Utica may yet prove to be a successfulnatural gas development, with close proximity to the East Coast demand center. But with natural gas trading at a low $4 per million British thermal units for the foreseeable future, that is not the outcome drillers had hoped for a few years ago.


In Colorado, where oil production has risen by less than 100,000 bpd since serious development began on the Niobrara several years ago, NuStar’s biggest problem was likely competition — from other pipelines and railways.

SemGroup Corp is building a 527-mile (848-km) crude pipeline to move oil from Colorado to the U.S. crude futures hub in Cushing, Oklahoma, by the first half of 2014, and already has twice expanded its capacity. Plains All American Pipeline LP is expanding and building new rail capacity in Colorado to haul oil out by train later this year.

Those projects combined will be able to move 230,000 bpd, on top of 30,000 to 40,000 bpd of Niobrara crude that already goes to Suncor Energy’s 93,000 bpd refinery in Commerce City, Colorado.

“We’re at a point now where we’re going to see some of these lower-quality projects weeded out,” said Bradley Olsen, director of midstream research at Tudor Pickering Holt & Co in Houston.

That surpasses current output in the play’s so-called sweet spots – the Denver-Julesburg (DJ) and Powder River Basin (PRB) – which reached 170,000 bpd as of January this year, according to energy consultancy Bentek. The consultancy projects output to rise to 235,000 bpd by the end of 2013.

The option to ship crude by rail is attractive to oil producers who are uncertain how long their wells may keep pumping out crude. Rail terminals are less expensive to build, can start up faster and do not require long-term contracts sought to justify the cost of building or converting pipelines.

Refiners also like being able to pick up the cheapest oil at the moment from one of dozens of rail terminals rather than be tied to a certain type of crude for five or 10 years.

“It could come from Niobrara. It could come from Bakken. It could come from West Texas. And that’s one of the nice things about rail systems — there’s flexibility to move those cars around to market to provide the greatest opportunities,” Alon Energy USA Chief Executive Paul Eisman said this month.


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Shale fracking proves $30 billion-a-year boon to waste disposal industry

Posted on 21 May 2013 by shalenow

The explosive expansion of drilling of natural gas and oil wells in shale deposits in the United States and Canada using a directional drilling method dubbed “fracking” may have spawned a $30 billion per year expansion of the waste disposal business, waste and investment industry executives were told Monday.


Oil and gas fracking represents a $200 billion-a-year capital investment, and the companies doing the drilling are spending between $20 billion and $30 billion on waste disposal, said Michael Hoffman, managing director at Wunderlich Securities, during a seminar on waste management investment on the first day of the WasteExpo 2013 Conference and Exposition in New Orleans.

The conference continues through Thursday at the Ernest N. Morial Convention Center.

fracking_mansfield_aerial.jpgA fracking operation on the edge of a working farm near Mansfield, La., was photographed in March. March 3 2011Ted Jackson, | The Times-Picayune archive

Producers drill wells straight down between 1,500 feet and 15,000 feet deep to reach shale rock, which has oil and natural gas embedded in it. The wellhole is then curved to a horizontal position and extended as much as a mile into the formation. Small explosions are set off to fracture the surrounding rock, while a high-pressure mix of water, sand and chemicals is pumped into the horizontal passage to help release the gas.

In Louisiana, 2,205 such wells have been drilled and are producing natural gas in the Haynesville Shale formation near Shreveport, with each well costing between $8 million and $10 million to drill, according to state officials. Another 232 wells are awaiting completion, are in the process of being drilled, or are permitted in the Haynesville formation.

Another 16 producing wells have been drilled in the Tuscaloosa Marine Shale formation, which cuts across the center of the state. The formation underlies St. Tammany, Washington, and Tangipahoa parishes and the parishes surrounding Baton Rouge.

Elsewhere, fracking is being used in the Marcellus Shale formation that stretches across Ohio, Pennsylvania, West Virginia and parts of Virginia, in several shale formations in Texas and in shales found in North Dakota and Wyoming.

The fracking process uses an estimated 136 billion gallons of water a year in the United States and Canada. Once used, the water must be treated and reused, or disposed. The drilling also produces other waste products, mud and rock.

The oil and gas exploration and production industry is exempt from the stringent federal regulations governing hazardous waste. But repeated concerns about the effects of fracking have resulted in increased regulation in many states, and the federal government is considering similar restrictions.

Restrictions similar to U.S. hazardous waste rules already govern fracking operations in Canda, said John Gibson, chief executive of the Tervita Corp., which makes $1.6 billion a year disposing of drill cuttings, drilling mud and other wastes in Canada and the United States, and another $3.5 billion a year transporting oil by pipeline from wellheads to larger pipelines.

“Canada has a tougher regulatory environment, but I believe the U.S. will evolve,” he said. Hoffman agreed, adding that it’s in the best interests of waste management companies to have stringent rules in place, which will help direct business to them.

“There’s clearly a need to manage an increasingly complex waste stream, in part because of the change in drilling technology going from a vertical approach to a horizontal is yielding a significant increase in the volumes coming at us, and more complex volumes of wastes,” he said.

Jason Wangler, another Wunderlich analyst, said the demand for increased regulation is in part the result of the location of shale beneath populated areas. “The old saying was, ‘Wherever oil is is where people aren’t,’ because it’s usually in places where nobody wants to live,” Wangler said.

But then the Marcellus Shale was targeted by drillers in Ohio and Pennsylvania, and the response by residents got the drilling companies moving to support increased regulation, he said.

“You’re moving into areas where people don’t know how big a drilling rig is. They don’t know how many trucks go through every day,” he said. “We’re seeing more environmental movements and the companies are trying their best to adjust to this, especially the larger ones, to effectively keep their names out of the paper.”

The companies want to be seen as good environmental stewards, Wangler said.

The federal government seems poised to develop a moderate approach to regulation, led by President Barack Obama, said Kevin Book, managing director of ClearView Energy Partners LLC, which tracks energy regulations. “We’re seeing the maturation of the political fracking revolution,” Book said.

The first new federal fracking restrictions govern fracking on federally owned lands and were issued last week by the Bureau of Land Management; Book said they include hints about the direction that the Environmental Protection Agency may take in the next two years as it rolls out its own rules governing fracking.

Those rules include provisions governing intellectual property and trade secrets that were taken from Colorado state regulations. Book said he expects other states to follow the lead of Colorado, Pennsylvania, Texas and Louisiana in developing their own fracking regulations before the feds do.

Meanwhile, Gibson expects states and the U.S. government to look north to Canada for some regulatory changes. A year and a half ago, Alberta, Canada, eliminated “land farming” of oil-field wastes, a practice where the wastes are sprayed over open land and allowed to break down naturally.

But Gibson also sees a need to increase regulation as fracking becomes more expansive, especially the abandonment of wellholes after they no longer produce oil or gas. “We’re going to have to see a focus on abandonment to be able to insure well integrity inside the circle of fracking,” he said, “so that as I flow fluid down this hole, it doesn’t flow across and up an adjacent hole into an aquifer.”

Gibson also warned that federal and state regulators aren’t nimble enough to keep up with changes in fracking technology. “We need regulations that are dynamic and adaptable,” he said.

But Gibson said 90 percent of his customers “really, truly believe in the social license to operate.”

“And so, no matter what the regulation is, the good customers … are going to exceed the regulatory requirement in order to insure they have the right to practice their profession of drilling wells and producing natural resources,” he said.


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US shale oil boom will make OPEC voice smaller in energy market- IEA

Posted on 14 May 2013 by shalenow

11.siThe quick progress of the ‘shale revolution’ in the US is set to reshape the world energy market by 2018, when OPEC becomes less influential and developing countries drive global demand.

The US shale oil will meet most of the demand from across the world in the next five years, even if it goes into ‘recovery motion’. The developing economies outside OECD, such as BRICS countries and Saudi Arabia, that’ll be driving increased demand.

The forecast is made by the International Energy Agency (IEA) in its closely watched semi-annual report.

“North America has set off a supply shock that is sending ripples throughout the world,” said IEA Executive Director Maria van der Hoeven.

“The good news is that this is helping to ease a market that was relatively tight for several years. The technology that unlocked the bonanza in places like North Dakota can and will be applied elsewhere, potentially leading to a broad reassessment of reserves,” Maria van der Hoeven added.

The US Government has forecast daily oil production in the country to skyrocket in 2014 to the highest level since 1988.

The price of oil slid below $95 a barrel on Tuesday as the Paris-based IEA, that advises 28 countries about energy issues, raised its U.S. oil production forecasts and cut its prediction for global crude demand.

On a global demand side, the IEA forecast it to rise by a total of 6.1 million barrels a day over the next five years, from 90.6 million barrels a day in 2013 to 96.7 million barrels a day in 2018.

The IEA says supply capacity of non-OPEC countries is set to be steadily rise, while hurdles in North and sub-Saharan Africa, as well as a regional fallout from the ‘Arab Spring’ will be affecting supply from OPEC members.

In case global demand rises, this will leave OPEC – an organization largely seen as the last resort to meet demand fluctuations – with the output levels almost unchanged from the current levels, the IEA said.

Global refining industry and oil trading patterns are also set to be affected by the rising capacity of the developing world, the report said.


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Shale gas: An energy revolution for your portfolio

Posted on 13 May 2013 by shalenow

Oil and gas industryShale gas operations in the United States are expected to push the country toward energy independence in the years ahead, but their impact on U.S. and Canadian share prices could be just as profound.

Moody’s Investors Service is a big believer in the drilling revolution – which untaps enormous gas reserves using new “fracking” technology – and argued in a new report that it will keep gas prices low, and quantities plentiful, for at least the next decade. And that will create corporate winners that stand to benefit from the lower input costs that cheap natural gas provides.

“A surplus of natural gas production will give North American refiners and chemical producers a long-term competitive advantage over their peers worldwide, while the shale boom also improves the credit profiles of U.S. electric and gas utilities,” said Steven Wood, managing director at Moody’s, in a statement.

He mentions names. Among refiners set to benefit: Phillips 66, Marathon Petroleum Corp. and Valero Energy Corp. Among chemical companies that are singled out, fertilizer producers received the biggest nods, given the importance of natural gas to their production. These companies include CF Industries Holdings Inc., Agrium Inc., Methanex Corp. and Rentech Nitrogen Partners.

As for regulated utilities, Mr. Wood points out that natural gas represents their single largest expense – and while cheaper energy is usually passed on to customers, the lower utility bills of customers translates into better relations between utilities and regulators.

“Indeed, the currently more amicable environment has helped the utilities improve their cost recovery through base-rate increases, with little impact on overall customer bills,” he said.

Even railroads stand to benefit from the shale boom. “The western railroads Burlington Northern and Union Pacific Railroad will see the most advantage, since they are close to the Bakken and Eagle Ford shale regions,” Mr. Wood said.

These energy-producing regions require vast amounts of fracking sand and other materials, and railroads are ideally positioned to provide them.

The question is to what extent has this shale revolution already been priced in to share prices?

While a number of fertilizer producers have been fumbling in 2013, refiners have enjoyed a good run: Valero is up 22 per cent and Marathon is up nearly 21. Among the railroads, Union Pacific has risen more than 22 per cent. Even utilities, which aren’t usually associated with stellar returns, have risen more than 12 per cent this year.

However, the gains are largely associated with an investor preference for relatively stable, defensive industries as the global economy shows few signs of anything but sluggish growth. This demand is likely overshadowing any sort of bullish enthusiasm for the shale revolution – which has its share of critics (and not just vocal environmentalists who advocate alternative energy).

For example, Arthur Berman (no relation), a prominent energy consultant and researcher based in Texas, has argued that gas prices would have to rise considerably to make most shale gas production profitable.

“We do not dispute that the shale gas resource is large; we question the near- to medium-term supply, the amount of shale gas that is available on demand,” he wrote earlier this year. “The number of gas-directed drilling rigs has plummeted in the past year because of low price and we fear that demand may exceed supply unless this trend is reversed.”

These doubts can rankle the shale industry. But investors should love them: As long as doubts remain, the shale revolution has further to run.

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Energy Independence

Posted on 12 May 2013 by shalenow

120615010449-fracking-afp-story-top(TIME) – Michael Levi is my favorite energy wonk — and not just because we both had to endure waiting for hours in the cold outside the 2009 United Nations climate-change conference in Copenhagen. (Though he got in first.)

Levi, the senior fellow for energy and the environment at the Council on Foreign Relations, is a smart, pragmatic observer of the energy wars — and he’s an excellent blogger. He knows how to cut through specious arguments on both sides of the energy-and-climate debate while keeping in target the bigger challenges facing the United States and the world.

Levi has a new book out on the energy debate called “The Power Surge: Energy, Opportunity and the Battle for America’s Future.” It’s one of the best analyses of the amazing changes taking place in the energy sphere today, touching on everything from fracking to climate change to the Keystone XL pipeline debate.

I had a chance to talk with him about Canadian oil sands, the myth of energy independence and why we need a negotiated peace settlement to end the energy wars.

We’ve seen other energy revolutions go through a boom and bust cycle. What makes this moment different?

Two things make this moment special. The first is the diversity of changes that are happening. This isn’t just one isolated area. Today you’ve got booming production of oil, natural gas. You have oil consumption, rapidly falling, rising renewable energy. It’s not just one boom, it’s several at the same time.

The other thing is that there are multiple forces driving the change. In oil it’s not just fracking, it’s expanded offshore drilling. In renewables, it’s not just one technology. It’s wind, it’s solar, both centralized and distributed. On the car front, it is everything from better traditional engines to electric vehicles and natural gas for long-distance trucking. So when you have multiple trends and drivers, the transformation is more robust.

READ: Nets still empty, years after Gulf oil spill

Your point is that the best future for America is to capitalize all the options: renewable, oil and gas, efficiency, reduced consumption. How can those things coexist?

Take expanded oil production and reduced oil consumption. To tackle climate and oil, what we really need to do is reduce oil consumption. That’s where vulnerability stems from. You can reduce consumption and increase production the same time. You balance with lower imports. When someone says expanded U.S. production will lead to greatly increased global consumption and cause intolerable climate change, you have to ask what kind of increased global consumption do you need so that damage to the climate occurs.

To get people to use more oil, the oil has to be cheaper. If we don’t believe that increasing U.S. oil production will do much to decrease oil prices, and I think that’s still the consensus, we can’t simultaneously believe it is disastrous for the climate.

We can also talk about the electricity world. Abundant natural gas makes the economics of renewables a bit more challenging. But fundamentally, that’s not the big barrier to renewable-energy growth. It is still cost and the question of government policy. But there are ways for renewable energy and natural gas to work together. Renewable energy is delivered inconsistently, while natural gas can be turned on and off rapidly to fill in those gaps.

I don’t want to suggest that you can have absolutely everything. There are conflicts. But we are better off when we focus on the real tensions between different sources instead of imagined tensions. There are enough real decisions we need to make that we don’t need to spend our time focused on imagined ones.

What are the real tensions?

The first big place is on local environmental concerns and squaring them with national goals. Whether it is hydraulic fracturing (fracking) for natural gas or large solar arrays in the desert where people want to protect land, our local environmental desires run up against the developments that can benefit us nationally. We need an intelligent informed conversation about that.

On oil production and consumption, in the near term reducing U.S. oil demand doesn’t have a big impact on prices. You can square increased production with lower consumption. In the long run, if you want to tackle climate change, you will need lower oil consumption, and that will affect U.S. oil production. But that’s a longer-term issue.

On the renewable-energy front, natural gas is displacing coal rather than renewable power. It cuts emissions but does pose a risk to renewable-energy growth and the development of that technology. If we don’t guard against that, we could find ourselves in 10 to 15 years regretting we didn’t develop renewables earlier.

We talk about energy independence, but you make the case that oil is sold on a global market. Is energy independence anything more than just a slogan?

It is rarely more than a slogan. People use the phrase energy independence as shorthand for producing as much oil as you consume. That’s reasonable, but you need to be careful not to read into that something much bigger, that we will actually be independent of events overseas.

I have found it extraordinary to see analyst after analyst start taking about energy independence as if it’s a real thing that insulates us from foreign events. That’s not true. If in 1973 we could have produced as much oil as we consumed, the impact would have been enormous. We didn’t have a free-flowing market for oil, or a petroleum reserve as we do now. But the world is different now, and what happens today is important and valuable but doesn’t solve the problem that existed then.

READ: U.S. gas prices down from 2012 peak

Does that go for those in the renewable-energy community who make the same claim that we need to become energy independent?

If you don’t use oil, you are considerably more energy independent than if you do. Oil prices can go up, and if you don’t use oil, it doesn’t hurt you directly.

Those who say we can become more energy secure by reducing demand for oil have a stronger platform. But it takes a long time to reduce demand. You can increase oil production faster than you can cut oil use in cars and trucks because the typical car stays on the road for 15 years or longer. It takes a long time to turn the fleet over.

Where people are stuck in the 1970s is the idea that wind or solar can get us off foreign oil. In the 1970s we used a lot of oil in power plants. But today we don’t, and renewable power does not get us off oil.

We often here about the national-security benefits of Canadian oil sands. Are those claims accurate?

The security benefits of more Canadian oil production have been greatly overblown. They are not zero. In a military crisis it would be better to have more oil close to home, but I don’t think we’ll get into that kind of extended crisis. But when it comes to volatile global prices of oil, Canadian oil doesn’t give us a special benefit. When Libya went haywire two years ago, Canadian oil went up more than Mideast oil did. But expanded Canadian production does help keep the price of oil down a little bit, and that helps the economy.

There are real climate damages from Canadian oil, but the climate damage and the economic and security benefits are small. It’s trite to say this is more a symbolic debate than a meaningful one, but it is. The real impacts are local, where the oil is produced in Alberta, and those are issues that Canadians struggle with all the time. The U.S. has plenty of environmental challenges of its own without getting wrapped around Alberta’s environmental issues.

So how do we get these two sides of the energy debate working together?

We’re not going to have a world where the Sierra Club and Exxon sing “Kumbaya” together. But ultimately both sides can get more from an approach that capitalizes on developments across the board than in just trying to beat the other side down. That doesn’t mean a grand national-energy plan. It means starting with small but real deals that allow the two sides to work together, as we did in [the energy legislation of] 2005 and 2007.

I’m drawn to things like reforming the way we do environmental permitting for energy development, whether it’s oil and gas or renewables. People who want to transform the energy system should be able to do it. I like the president’s Energy Security Trust, where you use some oil-and-gas revenues to fund renewable-energy research and development.

But it’s frustrating because people who for decades talk of oil production being transformational now say, if you spend a couple hundred million a year of the revenues from that, it’s not worth drilling. If oil production is as transformational as they claim, it should be worth it even if you just took that money and burnt it. And on the flip side, those who talk about the importance of innovation say the deal is not worth it because we can’t take any more oil and gas development. People should focus on what they can gain rather than fixating on what they lose.

READ: Spill strengthens arguments of Keystone foes

On the environmental side of things, there’s a desire for elemental change in energy that stems from serious fear of climate change. How scared are you?

Before I started spending my time on energy and climate, I spent most of it working on national security issues. I wrote a book on nuclear terrorism. In that world you think about risks. When people give me the median projections of what will happen on climate change, some of them scare me, and some wouldn’t push me to put climate change on top of the list.

What really worries me are the lower probability but higher-consequence outcomes. There are some people who say we can’t focus on those events, but to me, that is the job of government. It is not to optimize society. It is to protect people against big risks that they can’t handle themselves. And climate change is one of those big risks.

I’m not in the camp that if you don’t follow my plan, we’ll all die, but I do believe this is a top-tier issue. And not because of the certainties but because of the risks.

What are energy policies that to you seem effective and politically doable?

I try to stay away from specific policies. Too often we jump right to policies and fight over the details without stepping back and asking about what kind of future we want. The Keystone debate is an example — we have all these fights over the details, but the question is really, ‘Do we want more oil or less?’

But in the near term, I’d like to see money taken from oil and gas and put into clean energy. I’d like to see a better way to do permitting, including for new pipelines and power lines. And given the roadblocks in Congress on pricing of carbon, I’d like to see an effort to use the Clean Air Act to reduce emissions in the power sector.

But as we go further out, the big pieces that we need are to make people pay a penalty if they pollute, so the market can drive us toward lower emissions. We need to clamp down on excessive oil consumption, because we still use too much. And we should take steps to expand access but also improve regulations so we can sustainably grow oil-and-gas production without endangering people or creating a backlash.

Is cap and trade still an option for you? We’ve seen a lot of problems with the Emissions Trading Scheme in the European Union.

I think people have misread what happened in Europe. People don’t want stricter standards for greenhouse gas emissions. Because of that, carbon prices are low. Too many observers have said this is because cap and trade is flawed. The problem isn’t the machine, the problem is the political willingness to take action.

People focus on the policy machinery and not on whether people actually want to do things. Transparent and flexible policies are essential to making big cuts in emissions. You are talking about big economic transitions when you get serious about climate change, and we aren’t smart enough to know how that should proceed. That means you do need to eventually use tools that allow the market to do a lot of it, and whether that is cap and trade or a carbon tax or something else is secondary, as long as you have something flexible.

Each side in energy debate seems to be able to stop each other more than they can promote their own agenda. Will that ever change?

Hope springs eternal. But what scares me is that this isn’t just a pattern from the last few years, but from the last 40 years. In the 1980s, opponents of drilling were very good at getting offshore drilling constrained, and opponents of clean energy were good at shutting down programs for renewable power.

But that didn’t do great things for us as a country. If we get back to a point in American politics where people are willing to agree on things, I hope people who care about energy and climate have answers for them that they can embrace. If you don’t have a good idea about what you actually want to ask for on energy, you can have all the bipartisan enthusiasm you can get, but you won’t make real progress.


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Marcellus, Mississippian, Permian: What Is The Acreage Worth? – Economic Analysis

Posted on 08 May 2013 by shalenow

Several recent M&A data points that involve significant blocks of undeveloped acreage in the Marcellus, Mississippian, Permian and other prolific resource plays bring in the spotlight the dispute regarding the valuation of so called “resource potential” – a somewhat vague metric that is often used in investor presentations as a selling point. Acreage transactions provide an important market test to the concept. In this note, I use M&A examples to illustrate economics and valuation dynamics related to undeveloped acreage.

Chesapeake’s Marcellus Sales

Two significant undeveloped acreage divestitures by Chesapeake Energy (CHK) in the Marcellus area were announced last week. In the first transaction, Chesapeake (and its non-operating partner Statoil [STO]) agreed to sell 162,000 net acres in Northeast Pennsylvania, including 51,000 net acres in the prolific Susquehanna County, to Southwestern Energy (SWN) for $93 million in cash. In the second transaction, Chesapeake and Statoil agreed to sell 99,000 net acres in Southwest Pennsylvania, including 10 existing wells, to EQT Corporation (EQT) for $113 million in cash. (I estimate net proceeds from the two transactions to Chesapeake at below $135 million – hardly enough to move the needle for the company as it is facing a ~$3.5 billion budget shortfall in 2013 alone).

While the price per undeveloped acre implied by the headlines ($574/acre in the first transaction and estimated $650/acre in the second transaction) may appear surprisingly low at the first glance, particularly given that in both cases the properties provide exposure to the Marcellus’ sweet spots, a closer examination suggests that the pricing was by no means irrational and is certainly not a result of a “fire sale” (both packages have been on the market for quite some time, were broadly marketed and went to the highest bidders). From the acquirer’s perspective, cost of purchased acreage is not nearly as low as may appear from the headline figures. In fact, by the time the properties are fully developed, the “fully loaded” cost per acre to the acquirer may come out well above $10,000 per acre.

To explain the valuation math, I turn to the example of the first transaction in which Southwestern acquired 162,000 acres from Chesapeake. As a reminder, the acreage being acquired is located mostly in Susquehanna, Wyoming, Sullivan and Tioga Counties in Pennsylvania and in some areas is a direct offset to Southwestern’s acreage, making SWN one of logical buyers.

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(Source: Southwestern Energy May 2013 Investor Presentation)

According to a map from Chesapeake’s most recent presentation (below), the acreage is located mostly on the fringes of Northeast Pennsylvania’s dry gas sweet spot. It is important to note, however, that the acreage is largely untested and is situated in areas that lack gathering and takeaway infrastructure and therefore have seen very scant offset operator activity. Therefore, it would be incorrect to conclude that the acreage is of marginal quality. To the contrary, drilling results by Cabot Oil & Gas (COG) on its Zick Pad and Reilly Pad in eastern Susquehanna and many well results in northern Wyoming County and northern Sullivan County (in some cases less than five miles from portions of the leases being acquired by Southwestern) suggest that the acreage likely provides exposure not just to the play’s Tier 1 areas but also to its Core (which I define as the most productive part of the play where 10+ Bcf EURs can be consistently achieved for ~4,000 laterals).

(click to enlarge)
(Source: Chesapeake Energy May 2013 Investor Presentation)

So why is the per acre price so low? To understand the valuation, let’s look at the transaction from Southwestern’s perspective. Lease expirations and infrastructure constraints provide the explanation.

The peak of leasing activity in the Marcellus took place in 2008-2009. That was the time when natural gas prices were high ($6-$10/MMBtu) and operators were willing to pay high price for prospective land. At that time, bonuses in the more competitive areas of Northeast Pennsylvania reached $3,000-$4,000 per acre (~15% royalties and 5-year primary term were not uncommon). A typical lease often provides an option to renew for another 4-5 years at a cost similar to the primary lease bonus. Many primary leases are scheduled to expire in 2013-2014 and operators face the dilemma: to give up the undrilled land or to exercise the expensive option.

Let’s assume for a moment that after acquiring Chesapeake’s acreage, Southwestern attempts to retain by production essentially all of the new acreage (key assumptions and calculations for this scenario are shown in the right-hand column in the spreadsheet below). Southwestern will begin drilling in earnest on the newly acquired acreage no earlier than in 2014. As a result, extension options on many leases will need to be exercised to provide additional time. Assuming $3,000/acre average option cost and additional 4-year term allowed, the total outlay for option exercise would be $450 million (based on 150,000 acres), on top of the $93 million already paid. In addition, Southwestern would need to initiate a 4-rig drilling program (which would double the company’s rig count in the Marcellus) and drill ~60 wells/year to satisfy the HBP requirement in the four-year period (I assume here that one well can only hold 640 acres). As a result, incremental capital spending will amount to ~$200-$300 million in 2013 and ~$500-$600+ million in 2014, non insignificant amounts from Southwestern’s perspective.

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(Source: Zeits Energy Analytics)

Perhaps the biggest issue is infrastructure availability to handle the ensuing production ramp up from the new acreage. Midstream service providers (the area is dominated by Williams Partners [WPZWMB]) have struggled to deploy gathering capacity to meet operators’ existing plans: field gathering and compression have been a significant constraint; in addition, high-pressure gathering lines are close to full utilization and major capacity expansions have been typically subscribed few years in advance of in-service dates. Given that incremental production volumes from a four-rig program can translate to as much as ~400 MMcf/d already by the end of Year 2 of the program, gathering capacity, and even takeaway capacity, can be a major issue.

The validity of trying to retain the entire acreage position also comes in question from a cash flow timing perspective. 150,000 acres can yield 1,500+ incremental drilling locations. Given the natural limitations on production volumes, an incremental inventory of that size may require two decades or more to be fully developed. Effectively, the development of less productive areas will end up pushed out into very remote future, making economics of marginal acreage unattractive.

Given that the acquired acreage is almost inevitably a “mixed bag” in terms of its potential productivity and concentration, a more likely scenario is that Southwestern will “cherry pick” the most promising and contiguous parts of the acquired leasehold for option exercise (SWN may also be able to “high-grade” its existing drilling inventory). Assuming that Southwestern decides to keep only 50,000 acres (the “Select Core and Tier 1″ column in the spreadsheet above), incremental drilling inventory can be fully developed in ten-fifteen years with a two-rig drilling program. The “fully loaded” cost per acre in this case, including the cost of “idle carry,” is ~$12k per acre (at the time when the average well is being drilled). The economic effect of such cost is approximately equivalent to a 1-1.5 Bcf reduction in each drillsite’s EUR and can be supported by wells in the Core and Tier 1 portions of the play.

EQT Corporation, the acquirer of Chesapeake’s second acreage package, seems to be following such “cherry picking” strategy. EQT has announced that 42,000 acres of the 99,000 acres they are acquiring from Chesapeake will likely expire undrilled. EQT will attempt to hold approximately 50,000 undeveloped acres and, similar to Southwestern, will likely have to exercise expensive extension options on that portion of the acreage. Per acre economics in EQT’s transaction are similar to Southwestern’s acquisition.

Statoil’s Marcellus Acreage Acquisition

In another notable acreage transaction in the Marcellus, in December 2012, Statoil announced acquisition of 70,000 net acres, the majority of which were located in liquids-rich part of the play in Ohio and West Virginia, for $590 million in cash. Statoil estimated the risked resource potential for the acquired acreage at 1.8-3.0 Tcfe net to Statoil. (It is almost ironic that Statoil appears to be a seller of acreage alongside Chesapeake in the two most recent transactions discussed above. It is also surprising that Statoil did not use the opportunity to negotiate a buyout of Chesapeake’s interest in the Southwest Pennsylvania package which would be complementary to its September acquisition).



At the time of the acquisition, the properties were producing ~30 MMcfe/d. The acquisition also included a gathering line. Assuming ~$100 million value for the existing production and gathering assets, the transaction valued undeveloped acreage at ~$7,000 per acre.

While on the surface, the valuation is a striking contrast to the ~$650-per-acre valuation in EQT transaction, a closer look shows that the differential is not as wide as it may appear. According to Statoil, approximately half of the acreage it was acquiring was already held by production, while the remaining half had “attractive expiry profile,” indicating that Statoil may be able to retain by production the entire acreage position within primary lease terms. As a result, the differential in per-acre valuation relative to the EQT transaction is effectively reduced to $2,000-$3,000 per acre. The remaining differential can be explained by the liquids-rich nature of the properties acquired by Statoil (acreage acquired by EQT appears to be, at least in part, within the dry gas window).

Other Acreage Sales By Chesapeake

The discussion above reminds that undeveloped acreage in “hot” plays, if not held by production, is often a short-shelf-life perishable good.

Building large acreage positions in promising plays, particularly at a time when the play is not sufficiently delineated and cost of land is relatively low, is a strategy that operators often pursue to be able to pick and choose the best blocks to drill upon. The remainder of the position is often relinquished. It would be incorrect, therefore, to extrapolate “drilling location math” – which would be a legitimate tool for limited tracts of land designated for full development – on to the entire lease positions that often include hundreds of thousands and even millions of acres.

From this perspective, some of the valuations that Chesapeake has received in its recent divestiture transactions should not be totally surprising. Particularly notable are the Mississippian Lime JV with Sinopec (SHI) and the 2012 divestiture of the Permian acreage to Chevron (CVX) and Royal Dutch Shell (RDS.A).

Chesapeake’s Mississippian Lime JV Transaction with Sinopec

On February 25, Chesapeake announced that it has agreed to sell to Sinopec a 50% interest in its 850,000 net acres in northern Oklahoma, including existing production, for $1.02 billion in cash (no drilling carries). Existing production averaged ~34,000 Boe/d in the 2012 fourth quarter and associated net proved reserves were ~140 MMBoe. In my analysis, the implied valuation per undeveloped acre in this transaction was approximately $800-$1,400. (I assume that approximately half of the proved reserves being sold are PDPs and estimate the PV-10 value of existing production being purchased by Sinopec in the $490-$700 million range, or $7-$10/Boe, based on my decline curve analysis and certain assumptions.) Given that Chesapeake contributed to the Joint Venture its acreage in the core of the play in Oklahoma, the valuation per undeveloped acre in this oil play does not strike as particularly high. The very large size of the acreage position, with likely expiration issues, may explain the conundrum.

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(Source: Chesapeake’s February 2013 Investor Presentation)

Chesapeake’s Delaware Basin Acreage Sale To Chevron

On September 12, Chevron announced that it was acquiring from Chesapeake 246,000 net acres, including 7,000 Boe/d of existing net production, in the Delaware Basin in New Mexico. While the acquisition price was not disclosed, I estimate that the price paid by Chevron was in the $850-$1,050 million range (the combined consideration paid for two asset packages, the 246,000 net acres acquired by Chevron and the 166,000 net acres, including 3,000 Boe/d of production, in the Midland Basin acquired by EnerVest, was approximately $1,365 million). Using certain assumptions with regard to future production declines, oil-NGLs-gas mix, and operating economics, I estimate that the amount of proved developed reserves acquired by Chevron was in the 15-20 MMBoe range with an estimated PV-10% value of $300-$450 million, using the current commodity strip prices. The balance of the price paid in the transaction implies a valuation of $1,750-$2,750 per undeveloped acre.

The northern part of the Delaware Basin in New Mexico contains several oil and wet gas plays, both conventional and unconventional, stacked together within several thousand feet of hydrocarbon-bearing rock. The most significant horizontal oil and liquids plays, the Bone Spring Sands and the Avalon (Leonard) Shale, are located primarily in Eddy County and Lea County of New Mexico. Part of Eddy County is also prospective for the deeper Wolfcamp Shale play. In this context, the price paid by Chevron does not strike as particularly high. The implied undeveloped acreage valuation contrasted with several other transactions in the Permian, including Devon Energy’s (DVN) $1.4 billion JV with Sumitomo Corp. which implied $7,200 per undeveloped acre and Concho Resources’ (CXO) $1.0 billion acquisition of Three Rivers Operating which implied estimated $2,750-$3,500 per undeveloped acre.

Chesapeake’s Delaware Basin Acreage Sale To Shell

On September 9, Royal Dutch Shell announced that it was acquiring from Chesapeake 618,000 net acres in the Permian Basin in West Texas for $1.935 billion in cash. The acquisition includes 26,000 Boe/d of existing production. Based on the acreage map provided in the press release, the transaction included acreage in the highly prospective core of the northern Delaware Basin.

(Source: Royal Dutch Shell’s September 9, 2012 news release)

The acreage is located primarily in Reeves, Loving and Ward counties of Texas where significant parts of the acquired leasehold are prospective for the oil-bearing 3rd Bone Spring Sands (conventional depositions being developed with horizontal fracturing) as well as the Wolfcamp and Avalon (Leonard) shale “combo” plays. The acreage also includes what appears to be a sizeable exploration tract in the center of Brewster County. By the time of the acquisition, several operators have reported strong drilling results in this area. As an example, Cimarex Energy (XEC) estimates average EUR in its 3rd Bone Spring play in the Ward County at 730 MBoe (the 19 gross wells drilled during the first half of 2012 had average 30-day IP rate of 850 Boe/d, 79% oil) with well costs in the $7.5-$8.5 million range. This translates into very compelling drilling economics, comparable to the better parts of the Bakken and Eagle Ford. In the Wolfcamp, where Cimarex has drilled and completed 24 horizontal wells, the company’s 30-day IPs have averaged 6.6 MMcfe/d (47% gas, 23% oil and 30% NGLs), a very impressive result given the very early stage of the play’s development, which translates into a still very robust 20%-30% after-tax rates of return based on the $8.0-$8.5 million well cost.

Based on limited disclosed information and using certain assumptions, I estimate that proved developed reserves being acquired by Shell in this transaction are in the 60-80 MMBoe range with an estimated PV-10% value of $900-$1,250 million, using the then current commodity strip prices. The balance of the price paid in the transaction implies a valuation of $1,400-$2,100 per undeveloped acre, assuming the core leasehold position is approximately 500,000 net acres (being unable to better evaluate the Brewster County acreage, I attribute no value to it).

So what is undeveloped acreage worth?

All of the above examples have one characteristic in common: the market test has revealed that the values of, arguably, very high quality (large, often “blocked up” and reasonably well delineated) acreage positions in some of the most prolific resource plays in reality turned out to be not all that high. It is not even obvious if the seller was able to recover total cost of its investment in land (which would include leasing costs, geophysical work, cost of capital, and associated G&A expenses).

The trend appears to be fairly common for the North American E&P industry. Investors often face situations when they need to critically assess the value of undeveloped land positions in companies’ asset portfolios. As all the examples above indicate, the analysis may not be straightforward.

In some situations, undeveloped acreage can be very valuable and marketable – some 2012 transactions registered values north of $30,000 per acre (as demonstrated by QEP’s [QEP] 2012 acquisition of the South Antelope block in the Bakken or Marathon Oil’s [MRO] 2012 purchase of Paloma properties in the Eagle Ford).

On the other hand, in many other situations, undeveloped acreage may we worth… nothing.

Several questions are particularly relevant:

  • What percentage of total acreage will the operator be realistically able to hold and what percentage will expire worthless? What is the cost of “rolling” the leases?
  • How many decades would it take to fully develop the entire drilling inventory and what is the value of such inventory’s “tail”?
  • What is the ratio of “resource potential” to proved reserves? (Proved reserves often reflect a five-year PUD conversion plan)
  • Is a giant acreage position an accomplishment in capturing valuable land or a reflection of workflow mismanagement and chaotic leasing strategy?

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Exxon Mobil And BP Offer Stable Exposure To Thriving New Energy Landscape

Posted on 07 May 2013 by shalenow

imagesAs an investor in commodities, you always need to keep track of the big picture that’s impacting not just the macro factors, but also the granular details in each market you’re investing in. As discussed in my last column, commodities are facing a particularly strong headwind that’s a direct result of a slowdown in global economic activity. The structural problems facing Europe are beginning to have a detrimental effect on activity in other key regions of the globe, namely Asia and China. China has been one of the locomotives behind the spectacular demand in natural resources over the last decade, for everything from soybeans to coal to copper. However, as Chinese economic activity begins to decline so has its demand for natural resources, which has pushed prices of commodities to decade lows.

Within this broad macroeconomic scenario, there is an equally potent subcurrent that is having a major influence on an important commodity subasset class: energy. The energy complex, along with the metals and agricultural complexes, has experienced weakness this year. This weakness is not only a result of the big-picture macro issues facing global economic activity, but it’s also a result of a direct issue that’s particular to the energy asset class: increased supply as a result of technological improvements stemming from hydraulic fracking and access to shale oil.

Specifically, will the shale boom that began in the United States herald a new era in the global energy supply dynamics?

Shale Oil: The Beginning of a New Era

It is very hard to ignore the revolutionary impact that certain technologies have had on the commodities industry over the decades and the centuries. Technological improvements such as the development of the steam engine, electric transmission through copper wiring, and gasoline-powered automobiles have changed entire industries. The advent of hydraulic fracturing and horizontal drilling may also end up having a revolutionary impact on the energy industry.

This technological development, which began in the United States, has pretty much turned the whole energy picture on its head in North America. Previously untapped and unrecoverable reserves are now being exploited at a commercial and industrial level. For example, oil production in the U.S. has increased by over 20% year over year. A decade ago, the recoverable reserves in the Bakken formation located in North Dakota and Montana (which is at the heart of this shale oil revolution) stood at 150 million barrels of recoverable oil; that number has now jumped to 7.5 billion barrels, representing an increase by a multiple of 50. This technological improvement has had such a dramatic impact on the American oil landscape that the United States may not only achieve that elusive goal of being “energy independent,” but may very well become a net crude oil exporter to the world’s other large consumer markets.

This year’s crude oil exports from the United States reached a 13-year high, according to the Department of Energy, and this trend will only accelerate. This scenario was unthinkable just five years ago when politicians were running on platforms that promised to wean the U.S. off of foreign oil. That is now likely to become the case, but not because of any political action — instead because of drastic technological improvements in reserve-recovery techniques.

Thriving in a New Energy World

The technological revolution that began in the United States will soon make its way to the most remote places of the world. Already, countries such as Estonia and Lebanon are exploring ways to access previously commercially unrecoverable reserves. And traditional energy powerhouses such as Saudi Arabia and Russia are beginning to invest heavily in the technologies that will allow them to tap their own shale oil reserves.

As this technology upends the global energy landscape, are the world’s petro-nations in a race to the bottom? Investors in crude oil have enjoyed strong earnings over the last decade, as the demand for oil remained high while supplies remained limited. However, as vast reserves of crude are tapped around the world and demand remains anemic, will we be seeing oil back to previous levels of $70 or even $50 per barrel? In this current environment, that is not out of the realm of possibility.

The smart investor will develop an investment plan that is able to withstand the cycles that are inherent in the oil business. We recommend sticking with large companies that have global reach, that are active throughout the oil supply chain, and that have experienced weather supply shocks and other severe market dislocations. Two companies that fit this profile are Exxon Mobil (XOM) and BP (BP).

Exxon’s footprint in the global energy landscape is second to none, and it is one of the technological leaders behind the shale oil boom. It also boasts a diversified revenue stream across products and regions that allow it to withstand market dislocations in the long term. BP is a slightly more unconventional play because of the recent issues it faced in the Gulf of Mexico and Russia. However, it survived both episodes where many oil companies would have gone belly up. It is experienced in crisis and has a defensible economic moat across regions and products that allow it to survive and thrive in any energy environment.

The energy complex is very dynamic, and investors need to go with nimble yet large companies that can provide value throughout the energy life cycle. And Exxon and BP fit that bill.

Disclosure: The author doesn’t have any positions in the stocks mentioned.

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SemGroup buying Chesapeake assets in Mississippi Lime area for $300 million

Posted on 02 May 2013 by shalenow


SemGroup Corp. is buying assets in the Mississippi Lime play from Chesapeake Energy Corp. for nearly $300 million, the companies announced Wednesday.

Tulsa-based SemGroup is purchasing Mid-America Midstream Gas Services LLC, a Chesapeake unit that has natural gas gathering and processing assets in the production area, which stretches from northern Oklahoma into southern Kansas.

SemGroup expects to close the deal by the end of the third quarter, pending regulatory approval.

“These assets are positioned for exceptional growth and will significantly increase our strategic position in the Mississippi Lime play,” SemGroup CEO Norm Szydlowski said in a statement.

The deal includes two natural gas processing plants in the Rose Valley area, 200 miles of gathering pipeline and a 20-year

commitment from Oklahoma City-based Chesapeake to gather and process natural gas on 540,000 acres of natural gas lease rights sold as part of the deal.

“This purchase expands our scale in highly attractive, liquids-rich areas with strong producer activity and organic growth opportunities, while adding to our future inventory of drop down assets for Rose Rock Midstream,” Szydlowski said.

The two Rose Valley processing plants are scheduled to be operational by 2014 and 2016, the companies said. They require a combined $125 million in additional capital expenditures to bring them online.

Processing capacity of SemGroup assets in the Mississippi Lime would increase more than twofold once the two Rose Valley processing plants are operational, the company said.

SemGroup Corp. is the surviving entity of SemGroup LP, which filed for bankruptcy in 2008 and later re-emerged without founder Tom Kivisto.

SemGroup Corp. earned $22.1 million last year.

The midstream deal is the second large sale of assets announced by Chesapeake Energy this week. The company said Monday it would sell $93 million worth of natural gas properties in the Marcellus Shale of the Northeast. Chesapeake says it hopes to sell between $4 billion and $7 billion in assets this year.

Chesapeake also announced Wednesday a first-quarter profit of $15 million. Revenue totaled $3.4 billion.

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