Devon Energy / GeoSouthern Energy

DVN : NYSE : US$62.77
BUY 
Target: US$86.00

COMPANY DESCRIPTION:
Devon Energy is an oil and gas E&P company with assets in the U.S. and Canada. The company also has a significant midstream operation. It is headquartered in Oklahoma City, OK.
All amounts in US$ unless otherwise noted.

Energy — Oil and Gas, Exploration and Production
REPORTED GEOSOUTHERN ACQUISITION WOULD BE POSITIVE
Investment recommendation
We view the possible acquisition of GeoSouthern Energy very positively since it would give DVN added running room to grow its oil volumes from a new position in the Eagle Ford Shale. A deal would bolster the already solid U.S. oil production growth it is getting from its emerging Permian and Miss-Woodford plays. We believe that greater oil growth and a higher mix of oil as a share of its total output are key elements to DVN receiving a higher valuation for its deeply undervalued E&P business.
Key points:
 Acquisition would substantially add to DVN’s U.S. oil production:
U.S. oil currently accounts for 12% of DVN’s total volumes and we project growth of 31% in 2014 and 23% in 2015. This deal would likely increase DVN’s oil production by a significant amount, as GeoSouthern is the 4th largest oil producer in the Eagle Ford. The private company produced 23 MBopd in 2012 – that amount alone would increase DVN’s U.S. oil volumes by over 25%.
 GeoSouthern has a very attractive acreage position in the Eagle Ford from being a “first mover” in this play: GeoSouthern has a 50% working interest in 173,000 gross acres in the Black Hawk field; its partner is BHP Billiton. The company also has 68,000 net acres further north in Fayette County.
 Eagle Ford is a great fit for DVN’s shale expertise: DVN famously was first to develop on a “mass manufacturing basis” in the Barnett Shale (TX); we believe it could achieve similar results in the Eagle Ford.
 DVN’s very strong balance sheet allows for a $6B acquisition: DVN’s net debt/cap ratio (pro forma for the Crosstex deal) is just 18%. With $4.3B of cash on hand, we believe the company is very much able to not only grow this asset quickly, but acquire other assets as well.

The Hype About America’s Energy Boom

Oil Guru Destroys All Of The Hype About America’s Energy Boom

 

5/14

   

The gap between production and consumption is 9 million barrels of oil a day. “It is unlikely that the U.S. will become energy independent,” Berman argues.

The gap between production and consumption is 9 million barrels of oil a day.

Arthur Berman

Read more: http://www.businessinsider.com/arthur-berman-shale-is-magical-thinking-2013-1?op=1#ixzz2IXJjv61y

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.

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