Good News on Chesapeake : $5.4 Billion Divestment.

Readers will note that we have been out of CHK for a very long time but today’s news marks a real turn in the company . Finally it will have a substantial reduction in the debt that kept our manged accounts away from the sector and this stock in particular.

Chesapeake Energy Corp. (CHK), the company that forced out its co-founder last year amid an investor revolt, plans to sell natural gas and oil shale fields to Southwestern Energy Co. (SWN) for $5.4 billion in its biggest-ever divestment.

The transaction includes 1,500 wells and drilling rights across 413,000 acres in the southern Marcellus Shale and eastern Utica Shale in Pennsylvania and West Virginia, Oklahoma City-based Chesapeake said in a statement today.

Chief Executive Officer Doug Lawler is exiting some shale prospects to devote drilling crews and rigs to oil-rich formations that have delivered rates of return in excess of 20 percent. Before today, Chesapeake had sold or spun-off more than $3 billion in gas fields, office buildings, pipelines and rigs this year, as it unwinds deals done by former CEO Aubrey McClendon.

Today’s announcement marks a major step in Chesapeake’s transformation and a dramatic improvement in our financial strength as we seek to maximize value for our shareholders,” Lawler said in the statement.

The transaction, which is expected to close before the end of the year, won’t impact Chesapeake’s production growth targets, Lawler said. Chesapeake, which had fallen 31 percent this year, surged 11 percent to $19.65 at 8:45 a.m. in New York, before the start of regular trading. Southwestern fell 5.3 percent to $33.80.

Reserves Boost

For Southwestern, the transaction represents the first major foray into oil-rich shale for a company that has been almost exclusively focused on gas production. Wells that are part of the deal produce the equivalent of 56,000 barrels of crude a day, 45 percent of which is oil and so-called gas liquids such as propane. The acquisition also is Southwestern’s largest-ever deal, according to data compiled by Bloomberg.

The purchase will increase Houston-based Southwestern’s reserves by one-third to the equivalent of 890 million barrels of crude at a cost of about $24 per barrel.

“We think the sale is transformational for both parties,” Scott Hanold, an analyst at RBC Capital Markets, said in a note to clients today.

A shortage of gas-processing plants and pipelines in the Appalachian region could delay Southwestern’s plans to expand output from its new assets. Those bottlenecks should ease in the coming years as more infrastructure is added, Hanold wrote.

Dismantling Empire

In an internal e-mail today, Lawler announced plans for a town hall-style meeting with employees on Oct. 20 to discuss the impact of the sale and long-term growth plans. Senior managers and human resources executives have already met with employees at the affected divisions to talk about transitioning to Southwestern, he said in the e-mail.

Chesapeake announced plans in July to expand in the Rocky Mountains amid Lawler’s campaign to reduce costs, unload unprofitable gas fields and untangle complex financing arrangements created during the reign of his predecessor.

Since becoming CEO two months after McClendon’s dismissal in April 2013, Lawler has outperformed the average gas and oil production estimates of analysts in quarterly Bloomberg surveys.

Southwestern expects to sell equity and debt before closing to finance the transaction. Bank of America Corp. advised Southwestern and will provide a $5 billion bridge loan.

Statoil ASA (STL), co-owner of some of the West Virginia and Pennsylvania assets, has 30 days to acquire the stake at the agreed price, Southwestern said.

(Southwestern scheduled a conference call for 11 a.m. New York time. To listen, dial 877-407-8035 in the U.S. and 201-689-8035 from overseas.)

Moody’s Shale Gas – Sector Review

eeking Alpha via 

11:52 AM (7 minutes ago)

to me
 as reported by Seeking Alpha April 1
not great review for Quicksilver

Moody’s: Marcellus shale gas producers to benefit most • 2:51 PM

  • Marcellus shale gas producers will benefit more than producers elsewhere in the U.S. because of several favorable circumstances, even if prices were to decline to 2012 levels, according to a Moody’s report.
  • Anadarko Petroleum (APC), Southwestern Energy (SWN) and Chesapeake Energy (CHK) – all of which entered the play early during a weak natural gas price environment – especially have benefited, Moody’s says.
  • An infrastructural overhaul is still needed as buyers move away from traditional production hubs such as the Haynesville and Barnett, the credit rating agency says; the transition already has caused a decline in credit quality for Exco Resources (XCO), Forest Oil (FST) and Quicksilver Resources (KWK).


Chesapeake Energy Capital Classic

Chesapeake Energy Capital Classic (Photo credit: Wikipedia)

CHK : NYSE : US$20.19
Target: US$26.00

Chesapeake Energy is one of the largest U.S. natural gas producers with an operating focus on the Barnett ShaleHaynesville Shale, Marcellus Shale, Granite/Colony Washes, Eagle Ford Shale and unconventional oil plays in the Anadarko/Permian Basins and Rockies.

Investment thesis

We lowered our price target $2 to $26 per share due to the base effect of ~5% lower Q4/12 production (~3% lower liquids output). Our liquids
outlook this year is in line with guidance though our ’15 liquids expectation of ~217 Mbpd is ~13% below the company’s 250 Mbpd goal.
Divestiture process increasingly opaque
In ‘12, Chesapeake generated ~$10.1 billion in proceeds from asset sales with ~$0.9 billion of sales scheduled to close early this year. In ’13, the
company plans to sell an incremental $3-6 billion of properties that may include a Mississippian JV or outright land sale and an Eagle Ford
property package producing 10+ Mbopd. We believe these divestitures should yield ~$2 billion in proceeds. Further, Chesapeake could materially sell down their 1.785 million net acres in the Marcellus, divest their 30% stake in FTS International, IPO up to 50% of their oilfield service company and/or execute another JV in the Utica.
Chances better than 50/50 that CHK can achieve a more appropriate 2x net debt-to-EBITDA leverage ratio At year-end, Chesapeake’s net debt-to-EBITDA was ~3.6x. Assuming the company can generate ~$4 billion of additional monetization proceeds with minimal production give up, CHK would lower net debt-to-EBITDA to the industry median of ~2x.

In subsequent years, assuming a steady state capital plan, the company remains $1.5-2 billion free cash flow negative though net debt-to-EBITDA only gradually rises.
Eagle Ford/Utica results solid
Eagle Ford wells have generally commenced at 500-1,000+ Boepd and recover ~500 Mboe (~80% liquids). Utica wells have commenced at an
average of ~1,000 Boepd (0%-30% oil) implying a ~800 Mboe recovery.

The Rise and Continuing Fall Of Chesapeake Energy

Chesapeake Energy

Chesapeake Energy (Photo credit: Wikipedia)

Chesapeake remains ” AVOID”  ( see The AMP Portfolio ( avaialble at )

here is a recent article ( in part ) from The New York Times

Rex W. Tillerson, the chief executive of Exxon Mobil, which spent $41 billion to buy XTO Energy, a giant natural gas company, in 2010, when gas prices were almost double what they are today, minced no words about the industry’s plight during an appearance in New York this summer.

We are all losing our shirts today,” Mr. Tillerson said. “We’re making no money. It’s all in the red.”

Like the recent credit bubble, the boom and bust in gas were driven in large part by tens of billions of dollars in creative financing engineered by investment banks like Goldman Sachs, Barclays and Jefferies & Company.

After the financial crisis, the natural gas rush was one of the few major profit centers for Wall Street deal makers, who found willing takers among energy companies and foreign financial investors.

Big companies like Chesapeake and lesser-known outfits like Quicksilver Resources andExco Resources were able to supercharge their growth with the global financing, transforming the face of energy in this country. In all, the top 50 oil and gas companies raised and spent an annual average of $126 billion over the last six years on drilling, land acquisition and other capital costs within the United States, double their capital spending as of 2005, according to an analysis by Ernst & Young.

Now the gas companies are committed to spending far more to produce gas than they can earn selling it. Their stock prices and debt ratings have been hammered.

“We just killed more meat than we could drag back to the cave and eat,” said Maynard Holt, co-president of Tudor Pickering Holt & Company, a Houston investment bank that has handled dozens of shale deals in the last four years. “Now we have a problem.”

A Master Salesman

Aubrey K. McClendon, chief executive of Chesapeake Energy, had a secret, and he was anxious to share it.

He called Ralph Eads III, a fraternity buddy from Duke who had become his go-to banker. Mr. McClendon explained that he had quietly acquired leases on hundreds of thousands of acres somewhere in the southern United States — he would not say exactly where — that could become one of the world’s biggest natural gas fields.

But to develop the wells, he needed billions of dollars.

“I can get the assets,” Mr. McClendon told Mr. Eads, a vice chairman of Jefferies, according to three people who participated in that call, nearly five years ago. “You have to get the money.”

Get it he did. Mr. Eads, a pitch artist who projects the unrestrained enthusiasm of a college football coach, traveled the world, ultimately raising an extraordinary $28 billion for Mr. McClendon’s “secret” venture in the Haynesville Shale, as well as other Chesapeake drilling projects.

Other bankers working in the glass office towers of downtown Houston were equally busy. While the skyscrapers are home to global giants like Chevron and lesser-known companies like Plains Exploration and Production, they also house storefronts for Wall Street deal makers who play a vital, though less visible, role in the nation’s surging energy production.

Mr. Eads, 53, a Texas native, is a prince of this world. His financial innovations helped feed the gas drilling boom, and he has participated in $159 billion worth of oil and gas deals since 2007.

A Sigma Alpha Epsilon fraternity brother of Mr. McClendon, he headed to Wall Street directly after Duke. He first earned a national profile in 2001, while working for the El Paso Corporation, a natural gas pipeline operator. Regulators accused El Paso of creating an artificial gas shortage in California in the previous year, contributing to a power crisis in the state. Although El Paso eventually settled the complaints for $1.7 billion, Mr. Eads said El Paso was guilty of nothing more than coming up with creative financial transactions.

After Mr. McClendon’s urgent request for money, Mr. Eads put in a call to Mr. Flores to see if he might be willing to finance part of Chesapeake’s Haynesville project.

“Aubrey and I have calculated it, and it might be the largest gas field in the world,” Mr. Eads said he told Mr. Flores, noting early results from a single well that showed unprecedented gas flows.

The type of deal he pitched, nicknamed “cash and carry,” was certainly aggressive and innovative. Plains would pay Chesapeake $1.7 billion to gain ownership of about one-third of the drilling rights that Chesapeake had leased in the Haynesville. Plains would also commit to paying out another $1.7 billion to cover half of Chesapeake’s drilling costs, in return for part of the future profits.

“It’s going to be a great investment,” Mr. Flores said on the day the deal was announced in July 2008.

But the deal, like others later struck by Chesapeake, benefited Mr. Eads and Mr. McClendon and their companies far more than the people writing the big checks.

Chesapeake spent an average of $7,100 an acre on the drilling sites it had leased in the Haynesville. Plains paid Chesapeake the equivalent of $30,000 an acre.

Jefferies and the other firms involved in arranging the deal made an estimated $23 million on this transaction.

Much of the money that Mr. Eads raised for American gas drillers came from overseas oil and gas companies, like Total of France and Cnooc, the China National Offshore Oil 

Corporation. He told them the American shale revolution was an opportunity they simply could not afford to pass by.

“This is like owning the Empire State Building,” Mr. Eads said, recalling one of his favorite lines. “It’s not going to be repeated. You miss the boat, you miss the boat.”

In China, he was in awe at just how much money was available to invest. One senior executive at a major Chinese oil company that Mr. Eads declined to identify, citing the confidential nature of the negotiations, explained that the country wanted to move as much as $750 billion from United States Treasury bonds into the North American energy business.

Mr. Eads was only happy to oblige, helping to secure $3.4 billion from the Chinese for Chesapeake through two deals.

Not everyone believed the story line of endless profits and opportunity. Mr. Eads said one oil company executive whom he would not identify had rejected his pitch, complaining, “The reason for the glut is you guys.” The executive said he expected natural gas prices to plummet.

In private, Mr. Eads acknowledged that his pitches involved a bit of bluster.

“Typically, we represent sellers, so I want to persuade buyers that gas prices are going to be as high as possible,” Mr. Eads said. “The buyers are big boys — they are giant companies with thousands of gas economists who know way more than I know. Caveat emptor.”

Investment banking revenue at Jefferies reached $1.1 billion in 2011, a record for the firm, up from $750 million in 2007. Energy deals were cited among the biggest drivers of that surge, which came despite major problems at the firm because of its exposure to European sovereign debt.

Mr. Eads would not say how much he had been compensated for this bonanza. But Dealogic, a firm that tracks Wall Street transactions, estimated that Jefferies collected at 

least $124 million in fees from Chesapeake since 2007, a large share of its overall revenue on oil and gas deals, which ranged between $390 million and $700 million during the same period, according to two different industry estimates.

Even before the recent round of deals, Mr. Eads was a wealthy man. He lives in a sprawling, 11,000-square-foot lakefront mansion in Houston and has a wine cellar with 6,500 bottles. In 2010, he bought an $8.2 million home in the exclusive West End of Aspen, Colo., whose other homeowners have included Jack Nicholson and Mariah Carey.

Mr. Eads’s success has produced no shortage of jealousy in Houston.

“A lot of people don’t like him because he got ahead of everyone else,” said Chip Johnson, chief executive of Carrizo Oil and Gas, who made two big deals in which Mr. Eads was involved. “He got the reputation for overselling, but I have a hard time believing you can fool the big companies.”

“Without him,” Mr. Johnson added, “the country would not have had the huge gas supply as quickly as we did.”

Others have been more critical.

“He is like the bartender serving drinks for people who can’t handle it,” said Fadel Gheit, a managing director at Oppenheimer & Company, about Mr. Eads. “And the whole gas industry has gotten a rude awakening, a hangover, with gas prices plummeting. The investment bankers were happy to help with a smile and get their cut.”

A Train Without Brakes

Quit drilling,” T. Boone Pickens, the Texas oilman, barked to his fellow board members at Exco Resources, a small, independent drilling company based in Dallas that, like Chesapeake, had made a big bet in the Haynesville. “Shut her down.”

Exxon and Chesapeake Diverge On Shale Gas

English: To create this SVG-format logo, I too...

English: To create this SVG-format logo, I took the EPS file at, ran it through pstoedit, and then did the following modifications using Inkscape and Notepad: fixed priority (center of “O” in “Exxon”), centered on a correctly sized grid, and made markup simpler and more readable. Used in Exxon. Source: Category:Oil company logos (Photo credit: Wikipedia)

August 30

I have written before on the great articel Fortune Magazine published on Chesapeake – prior to the public debacle . It pointed out that Chesapeake had committed itself to thousands of deals requiring , not only lease payments but continued drilling to maintain the leases.

As a result Chesapeake is producing natural gas and having to  sell it at a price lower than its cost of  production. A new article by Richard Zeits says that Exxons reaction to the low natural gas price is to cut its gas drilling to the absolute minimum.  This will mean abanding leases and having to reduce its potential reserves – someting Exxon has been loath to do . Exxon has been criticized in the past as demanding too high an internal rate of return – and thus leaving aside potential .

However, the very great fiscal discipline it dispalys is sorely lacking at its competitors. The strong shift in its operating priorities, even at the cost of losing some of its valuable gas acreage, may indicate Exxon’s negative outlook on the US natural gas fundamentals both in the short and the long term.

This is even more dramatic considering the very leases Exxon may abando are in the areas others covet – – the Marcellus and Fayetteville.

In the Marcellus, Exxon has approximately 660,000 net acres under lease. Last summer, Exxon substantially expanded its acreage in the play by acquiring two privately held Pennsylvania operators, Phillips Resources and TWP, for $1.7 billion. The acquisitions added 317,000 net acres to Exxon’s existing Marcellus position which stood at 390,000 acres at the end of 2010. To date, Exxon’s Marcellus drilling program has been somewhat slow relative to other operators such as Range Resources (RRC) and Chesapeake Energy (CHK) who also have very large leaseholds in the play.

BP Writes Down Shale Gas Acreage By $2.8 B : Storage Figures Into Values

English: Point of Ayr Gas Terminal This termin...

English: Point of Ayr Gas Terminal This terminal, owned by BHP Billiton Petroleum, processes gas extracted by the Liverpool Bay platforms via a 33 km subsea pipeline. The gas is then supplied to the Powergen combined cycle gas turbine (CCGT) power station, which went into operation at Connah’s Quay in July 1996. (Photo credit: Wikipedia)

August 5

Marius Kloppers is right to take his lumps.

The BHP Billiton chief executive has waived his 2012 bonus after the mining giant took a $2.8 billion writedown on some of its U.S. shale gas acreage. The hit looks small when compared with BHP’s $170 billion market cap, and wasn’t unexpected. But BHP paid almost $5 billion for the asset just 18 months ago. That’s embarrassing for a company that trades on its reputation as a canny operator.

In February last year, BHP’s purchase of 487,000 acres of Fayetteville shale reserves from Chesapeake Energy was seen as a breakthrough after a string of failed mega-deals. BHP is one of the few big miners to own a substantial petroleum business. Gaining a foothold in the U.S. shale revolution seemed to make good strategic sense.

The $4.75 billion price tag looked stretched from the outset. When the deal was announced it was already clear that booming shale production was creating a gas glut that would threaten the profitability of wells that mainly produce gas. At the time, U.S. gas prices stood at about $4.50 per million British Thermal Units, down by a quarter from 2010 highs. They plunged to below $2 per mbtu earlier this year. Even at today’s price of about $3 per mbtu, drillers are still losing money.

BHP’s decision to write down the Chesapeake assets suggests it doesn’t see the glut easing anytime soon. Like other gas drillers, it is shifting its focus to the more oil-rich shale deposits it acquired when it bought U.S. driller Petrohawk for $12 billion in July last year. That bigger, more ambitious purchase is not affected by the writedowns.

BHP is hardly the only company to fess up to overpaying for shale. Shell, BG and Encana Energy all took impairments in the second quarter. The 1.9 percent rise in BHP’s London-listed shares following the announcement suggests investors expected Kloppers to bite the bullet.

Still, the timing isn’t ideal. Rising costs and cooling demand mean BHP and other big miners are under pressure to return more cash or else explain how multi-billion dollar growth projects can still make attractive returns. In January, Deutsche Bank estimated that BHP would have to spend about $50 billion to achieve a near-fourfold increase in shale output by the end of the decade. The writedowns will make it harder for Kloppers to make his case.

Storage: The theoretical working storage is about 4,400 Bcf (though demonstrated capacity is close to 4,100 Bcf), and we are sitting on 3,217 Bcf as of July 27. Back in January, pundits were making prediction that an overfill scenario would take a mini-miracle to avoid. The latest EIA forecast points to a 4,000 Bcf storage peak scenario. Depending on weather going forward, it is very likely that we will come close to the 4,100 number that produces a scare much like 2009, when price dropped 42% in a month. One difference between stocks/bonds and hard commodities such as natural gas is that the prices are still largely representative of exchanges of physical goods. What this means is that if we approach the storage peak season in late October/early November with a level close to the physical storage limit, there is a danger that producers can scramble to offload gas causing a short-term panic.

Shale Production Depressing Oil – (as well as nat gas) ( Bloomberg)


August 2

The shale boom that sent natural-gas prices to a 10-year low is being felt for the first time in the oil markets.

Williams Partners LP (WPZ) joined Marathon Oil Corp. (MRO) and Devon Energy Corp. (DVN) yesterday in blaming a glut of propane and related products for lower profits in the second quarter. Spectra Energy Corp. (SE) and Apache Corp. (APA) followed suit today. Next week more companies are expected to show the effects of falling prices for so-called natural-gas liquids used in backyard barbecues and motor fuels as producer Chesapeake Energy Corp. (CHK) and Targa Resources Partners LP (NGLS), a pipeline and storage company whose trading symbol is NGLS, release earnings.

Enlarge image Gas Liquids ‘Bloodbath’ Brings Shale Pain to Oil Market: Energy

Gas Liquids ‘Bloodbath’ Brings Shale Pain to Oil Market: Energy

Gas Liquids ‘Bloodbath’ Brings Shale Pain to Oil Market: Energy

George Frey/Bloomberg

Gas liquids supply from the Rocky Mountain region of the U.S. has increased at a 47 percent compound annual growth rate since 2006, when explorers first started seeking to add more liquids to production, Tudor Pickering said in a July 12 report.

Gas liquids supply from the Rocky Mountain region of the U.S. has increased at a 47 percent compound annual growth rate since 2006, when explorers first started seeking to add more liquids to production, Tudor Pickering said in a July 12 report. Photographer: George Frey/Bloomberg

The “NGL bloodbath,” as it was dubbed by Tudor, Pickering, Holt & Co. last month, is rippling across the oil and gas industry as explorers cut production and reduce cash flow projections, service companies forecast lower demand for drilling rigs, and pipeline partnerships suffer falling revenue for their gas liquids processing plants. The price of an ethane- propane NGL mix was down 58 percent yesterday from a high in January, outpacing the 19 percent drop in crude from a February peak.

“The same thing is now happening to liquids that happened to natural gas itself,” said James Williams, an energy economist at WTRG Economics in London, Arkansas. “We now have too much. We have an oversupply, so it’s depressing the price.”

NGL Disappointment

U.S. energy producers had counted on more lucrative oil and gas liquids to lift profits as the price of gas in New York tumbled earlier this year to an intraday low of $1.902 in April. As companies drilled for more liquids, the same oversupplies that gutted gas prices began to deflate NGLs.

Gas liquids are a heavier, or “wetter” component produced along with natural gas, and can include ethane, propane, butane, isobutane and natural gasoline. Gas liquids supply from the Rocky Mountain region of the U.S. has increased at a 47 percent compound annual growth rate since 2006, when explorers first started seeking to add more liquids to production, Tudor Pickering said in a July 12 report.

With demand staying flat while supplies rose, the average price of a mixture of ethane and propane plunged 53 percent in the second quarter from a year earlier, data compiled by Bloomberg show.

Williams, which gathers and processes gas from the Gulf of Mexico to Wyoming, said its net income fell to 29 cents per unit from 91 cents in the same quarter of 2011.

Negative Effects

“Our earnings were negatively affected by a rapid, significant decline in NGL prices,” Alan Armstrong, chief executive officer of parent Williams Cos. (WMB) said in a statement. The warm winter and downtime at chemical plants that consume NGLs were the main drivers of the decrease, he said.

Pipeline companies Targa and Enbridge Energy Partners LP (EEP), both based in Houston, which process gas to separate NGLs, warned of lower earnings in part because of the collapse of liquids prices. Both companies get revenue by keeping and selling a portion of the liquids they produce at their gas- processing plants, according to T.J. Schultz, an analyst with RBC Capital Markets.

Enterprise Products Partners LP (EPD), the second biggest U.S. pipeline operator, is moving away from that practice in favor of charging a flat fee for processing, Chief Executive Officer Mike Creel said in a conference call yesterday. The company claimed 96,000 barrels a day of NGLs in the second quarter compared to 120,000 a year earlier.

Devon Shift

Rapidly falling gas liquids prices and NGL plant shutdowns contributed to earnings declines at Devon, which sold NGLs for an average of $31.42 a barrel in the second quarter, 26 percent less than a year earlier. Oklahoma City-based Devon now is moving some of its drilling rigs away from gas and gas liquids fields to look for oil, Chief Executive Officer John Richels said on a conference call.

Marathon, based in Houston, cut its rig count in Oklahoma’s Anadarko Woodford formation to two from six because of lower NGL prices, which were to blame in part for a 5.8 percent decline in second-quarter net income from the first quarter, the company said yesterday.

Apache’s net income dropped 72 percent from a year earlier after realizing less than $34 per barrel for NGLs in the second quarter, the company said in a statement. That was less than the $38 that Eliot Javanmardi, an analyst at Capital One Southcoast in New Orleans, estimated.

Spectra’s profit fell 25% to 33 cents per share, and low NGL prices will affect its earnings for the rest of 2012, according to the company’s statement today.

Chesapeake Energy

Because NGLs comprise about 60 percent of Chesapeake’s overall liquids production, lower prices will have a significant impact on the Oklahoma City-based company when it reports earnings Aug. 6, said Mark Hanson, an analyst at Morningstar Investor Service in Chicago.

“There’s lots of moving pieces with Chesapeake but we’ll probably see a downward revision for operating cash flow this year” as a result of falling NGL prices, Hanson said in a telephone interview. The negative effects will extend into the rest of 2012 if the NGL market continues to deteriorate and Chesapeake accelerates production of those commodities, he said.

Service Companies

Service companies also felt the effect as cutbacks trickled down to drilling operations. Nabors Industries Ltd. (NBR), the world’s largest provider of land drilling rigs, said the market deteriorated sharply toward the end of the second quarter.

“Operators are even more reluctant to sign contract extensions of meaningful length since both cash flow and drilling budgets are declining,” Tony Petrello, chief executive officer, said on a conference call.

In some areas, Houston-based Baker Hughes Inc. (BHI), an energy service provider, is seeing its own pricing pressured by the declines.

“I characterize it as a knife fight right now in terms of pricing,” Martin Craighead, chief executive officer at Baker Hughes, said July 20 on a conference call.

There may be some rebound in pricing in the second half of the year as winter temperatures trigger more demand for the heating fuel propane and a ramp-up in exports provides a bigger market for ethane, according to Tudor Pickering analyst Bradley Olsen.

Ethane supply will likely outpace incremental demand increases until new chemical plants that use the liquids as raw materials for their products come on line around the middle of the decade, Devon’s Richels said.

“As long as natural gas prices remain low, we’d expect ethane prices also to be weak in this period,” he said.

Natural Gas Headed to $ 8

Texas Barnett Shale gas drilling rig near Alva...

Texas Barnett Shale gas drilling rig near Alvarado, Texas (Photo credit: Wikipedia)

by Richard Finger


“There is a glut of natural gas. Everybody knows that. There’s so much of the latest multi stage hydraulic fracturing going on from New York State
to Texas and all places in between, prices will be low forever. But just as a full watering hole can deplete quickly the current gas storage glut can recede.
In fact it already has been and at an alarmingly brisk pace and there may be a confluence of other events which could hasten the process. Consider
this. The weekly EIA natural gas storage numbers reported each Thursday came in with a 28 billion cubic feet (bcf) injection. The inventory
increase last year at this time was 67 bcf while the five year average accretion was 74 bcf. So true that one week does not a trend make. But this
makes eleven straight weeks that have experienced below average storage injections. After Thursday’s numbers were released inventories stood at
3.163 Trillion Cubic Feet or 19.2% above last year but only 17.5% above the five year average. A seemingly decent cushion until you consider as recently as May 10 stockpiles were 48.4% and 49.9% ahead of the previous year and the five year averages respectively. So the question becomes,
why are rates of gas injection dropping so precipitously unless the shale plays are actually unable to produce the necessary incremental volumes.
A Little History And Some Facts
Natural Gas production in the US was declining steadily until 2005 into what many perceived as an irreversible trend with an implication of persistent shortages. Enter the knight in shining armor; horizontal resource drilling. Daily gas production increased from 51 bcfd in 2005 to an average of 66.2 bcfd (billion cubic feet per day) in 2011. Some months have even spiked above 70 bcfd. The natural gas rig count peaked at 1,600 in the summer of 2008.

No coincidence gas prices topped out concurrently the first few days in July at $13.28 per mcf. So in six plus years while gas drillers
were able to increase daily supply by 30% demand has increased only half that amount. The result has been a spot gas price that bottomed on
April 17, 2012 at $1.89 per mcf (thousand cubic feet). But the pendulum is now trending in the other direction as power suppliers and the transportation industry begin to capitalize on the low price of natural gas.

The EIA (US Energy Information Association) has
prognosticated a 2012 daily production average of 68.98 bcfd and consumption of 69.91 bcfd. Methinks those production
numbers extravagantly optimistic and yet the agency continues to publicly adhere to them. Firstly, actual output over the last two months has already slipped to a bit under 64 bcfd.

Next, the natural gas rig count collapsed to 486, a thirteen year low, on June 22 and had made only minimal recovery to 518 rigs as of last week.
Lastly, numerous major gas producers such as COP and CHK have shut in parts of their dry gas production and are switching their drilling programs away from dry gas to natural gas liquids and oil. Conversely, consumption may exceed EIA projections.
Here’s why. Hotter than usual temperatures across much of the country especially in the population heavy
northeast is causing excess energy demand. Another thought provoking data point from the EIA last week reported that for the first time in history natural gas fired power plants generated more electricity than coal fired plants. That’s quite a milestone. Each now comprise 32% of U.S. power generation. Gas is cleaner and at current prices is a cost effective coal alternative. Adding to short term supply pressures, four nuclear power plants are down, all effecting east coast residents. Though still in early stages numerous fortune 500 companies such as Fed Ex and UPS are transitioning to natural gas powered trucks. A national fueling system is near completion with locations along the major interstate arteries.
Drilling Economics
The earliest horizontal resource drilling was done by Mitchell Energy (now part of DVN) in 2005 in the Barnett Shale which is in and around Fort Worth, Texas. Horizontal fracturing into shale has become much more sophisticated since those early days, with enhanced recovery of
gas in place, although at much greater cost per well. An  average 20 stage horizontal dry gas well in the South Texas Eagle Ford Shale or the East Texas/North Louisiana Haynesville play may cost $8.5 to $12 million. It will be drilled to vertical depths of 8,000 to 12,000 feet below surface.

Let’s assume an average well cost of $10 million with an estimated ultimate recovery (EUR) of 6 bcf. At $2.00 per mcf gross expected
revenues are $12 million and at $3.00 mcf revenues are $18 million and so on. Don’t forget about the expense side of the ledger. There is the mineral owner royalty payment which is often ¼ or 25% which comes right off the top.

Reuters : Chesapeake and Encana Plotted Bid Fixing

Chesapeake Energy

Chesapeake Energy (Photo credit: Wikipedia)

June 25

(Reuters) – Under the direction of CEO Aubrey McClendon, Chesapeake Energy Corp. plotted with its top competitor to suppress land prices in one of America’s most promising oil and gas plays, a Reuters investigation has found.

In emails between Chesapeake and Encana Corp, Canada’s largest natural gas company, the rivals repeatedly discussed how to avoid bidding against each other in a public land auction in Michigan two years ago and in at least nine prospective deals with private land owners here.

In one email, dated June 16, 2010, McClendon told a Chesapeake deputy that it was time “to smoke a peace pipe” with Encana “if we are bidding each other up.”

The Chesapeake vice president responded that he had contacted Encana “to discuss how they want to handle the entities we are both working to avoid us bidding each other up in the interim.”

McClendon replied: “Thanks.”

That exchange – and a dozen other emails reviewed by Reuters – could provide evidence that the two companies violated federal and state laws by seeking to keep land prices down, antitrust lawyers said.

“The famous phrase is a ‘smoking gun.’ That’s a smoking H-bomb,” said Harry First, a former antitrust lawyer for the Department of Justice. “When the talk is explicitly about getting together to avoid bidding each other up, it’s a red flag for collusion, bid-rigging, market allocation.”


Chesapeake and Encana say they discussed forming a joint venture in Michigan but opted against it. Partnerships can defray the steep costs of shale development, which include amassing thousands of acres of land and drilling dozens of wells.

In response to questions from Reuters, Encana said it was undertaking an internal investigation, saying it “is committed to conducting its business in an ethical and legal way.”

It acknowledged that its U.S. branch “discussed, but did not go forward with, a joint venture with Chesapeake Energy,” but added that it “cannot specifically address the questions posed at this time.”

Chesapeake spokesman Jim Gipson also said there had been discussions with Encana about “forming an ‘area of mutual interest’ joint venture” in Michigan. But he said “no such agreement was reached between the parties…. Nor did Encana and Chesapeake make any joint bids.”

The revelation of the discussions between Encana and Chesapeake, the second-largest natural gas producer in the United States, comes at a time when McClendon is under fire.

The company’s board stripped him of his chairmanship after Reuters reported that he took out more than $1.3 billion in personal loans from a firm that also finances Chesapeake. The IRS and the Securities and Exchange Commission have launched inquiries.

Private industry cartels are forbidden in the United States, where price-fixing between competitors is illegal under the Sherman Antitrust Act. Companies can be fined up to $100 million and individuals up to $1 million for each offense. Victims can also seek triple the amount of damages.

Antitrust lawyers said the fact that the companies discussed a formal joint venture wouldn’t dispel legal concerns.

“Nothing in the documents suggests any benefit to the joint venture other than making the price fall,” said Darren Bush, a former attorney in the Antitrust Division of the Department of Justice and a law professor at the University of Houston. “If it has no other purpose, then it’s just a shell and doesn’t change the liability for illegal conduct.”

CITI Energy Sector Review

Age of the bedrock underlying North America, f...

Age of the bedrock underlying North America, from red (oldest) to blue, green, yellow (newest). (Photo credit: Wikipedia)

Athabasca Oil* (ATH : TSX : $10.11)


Husky Energy* (HSE : TSX : $22.68)


Cenovus Energy* (CVE : TSX : $31.01)


Baytex Energy* (BTE : TSX : $42.84)


Crescent Point Energy* (CPG : TSX : $38.67)


Pinecrest Energy* (PRY : TSX-V : $1.94)


Suncor Energy* (SU : TSX : $27.49)




CitiGroup issued a  report on the changing dynamics within the North American energy sector. The report titled “North America, The New Middle East” makes the point that technical innovation that has unlocked new sources of energy, demographics and technology will be responsible for making North America virtually energy independent in the coming decade.

The U.S. has become a net petroleum product exporting country and has edged out Russia as the world’s largest refined petroleum exporter. In the report the CitiGroup noted, “A simple explanation would point to lower demand and a struggling economy, which requires less imported energy. But, that would only get you half the answer. U.S. demand has fallen by some 2 million barrels per day since its peak in 2005. The more exciting part of the answer is on the supply side as the U.S. has become the fastest growing oil and natural gas producing area of the world and is now the most important marginal source for oil and gas globally.

 Add to this steadily growing Canadian production and a comeback in Mexican production and you get to a higher growth rate than all of OPEC can sustain.”

The report cites five incremental sources of liquids growth that could make North America the single largest source of new supply in the next decade. They include:

1) oil sands production in Canada;

 2) deepwater in the U.S. and Mexico;

3) oil from shale and tight sands;


4) natural gas liquids (NGLs) associated with the production of natural gas; and

5) biofuels.

Putting these together, North America as a whole could add over 11 million barrels per day of liquids going from over 15 million barrels per day in 2010 to almost 27 million barrels per day by 2020-22. The ramifications for such growth within North America and around the world are profound from an economic and geo-political perspective, however the most important impact will be the reindustrialization of America based on dramatically lower cost feedstock than is available anywhere in the world, with the possible exception of Qatar. CitiGroup noted, “The economic consequences from this supply and demand revolution are potentially extraordinary.

We estimate that the cumulative impact of new production, reduced consumption and associated activity may increase real GDP by 2.0 to 3.3%, or $370-$624 billion respectively. $274 billion of this comes directly from the output of new hydrocarbon production alone, while the rest is generated by multiplier effects as the surge in economic activity drives higher wealth, spending, consumption and investment effects that ripple through the economy. This potential reindustrialization of the U.S. economy is both profound and timely, occurring as the U.S. struggles to shake off the lingering effects of the 2008 financial crisis.”

The report does note that risks to the thesis include environmentalism and political interference, especially in Mexico.




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