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The USA has had a rather rocky relationship with oil. In the 19th century, the discovery of massive reserves of oil set America on course to become a hugely powerful nation. Cities started to flourish. And vast suburbs sprung up as the country adapted to cheap car travel.

More recently, America has had to curb its consumption. The era of gluttonous oil consumption came to an end as the USA became dependent upon imported oil. The USA began to feel the strain of rising oil prices. When oil spiked during the financial crisis, Americans left their car at home. And industrial oil consumption collapsed.

But now, thanks to two new commercially deployed drilling techniques, the USA is set to free up an abundance of trapped gas and oil. And that could help the US economy back on its feet – even as our own is stagnating.

Because, while the glamour boys of the oil industry are heading off to deep waters, and plunging hundreds of millions of dollars down exploratory holes with very uncertain results, plenty of other oil men prefer a low risk play that offers a fast pay-back.

I met one of them last week. Matt Lofgran is chief executive of Nostra Terra Oil & Gas (AIM: NTOG), and before long he was scrawling figures on a piece of rough paper – figures that show just why he is joining the rush for US on-shore assets.

‘An energy renaissance’ in America

Make no mistake – America’s energy security has taken a dramatic swing for the better. Goldman Sachs has predicted that America will soon regain its title as the world’s largest oil producer, knocking Russia and Saudi Arabia off the top of the tree.

As I mentioned earlier, this is not down to the USA suddenly stumbling upon new oil fields (although one of my Red Hot Penny Shares selections may have done just that, and the share price is up fifty-fold as a result!). No, the real reason is that the ever inventive oil industry has found a way of extracting some of the oil that is known to exist but which has not previously been accessible.

“America’s renaissance,” says Goldman Sachs, “is down to hydraulic fracturing, or ‘fracking’. A process that has already significantly changed the gas industry and has been adapted to oil.” I have mentioned these techniques in past Penny Sleuths, but just to recap, ‘fracking’ and horizontal drilling are techniques which involve the cracking of rock strata from underground that allows trapped gas or oil to flow freely. Without doubt these methods have significantly changed the gas industry, although not to everybody’s benefit.

The price of gas in the USA has tumbled from over $10/mmbtu to $2.80/mmbtu. This is great news for consumers and is likely to trigger a switch from coal-fired to gas-fired power plants. It is also good news for another of my Red Hot Penny Shares selections that knows how to turn cheap gas into expensive liquid fuel.

But it is not, of course, so good for gas producers and some of these are now in financial difficulties and are off-loading assets at distressed prices.

Targeting a high oil price

That sounds like an opportunity for someone, but the easier play today is to apply this same fracking technology to oil rather than gas fields. Although you may think that the gas price and the oil price should move in tandem, in fact they do not. Logistical and other considerations mean that while there is effectively a world price for oil, gas prices are set locally.

Today, the price of gas in the USA is low, but the price of oil is still high so it makes sense to target the latter. Throughout North America from the Red Earth and Swan Hills fields of Alberta, to the Woodbine and Eagleford properties of Texas, old fields are being reworked with the new techniques of fracking and horizontal drilling. To get an idea of how profitable this can be, Lofgran referred me to the website of SandRidge Energy (NYSE:SD) which has licences in Texas and Oklahoma.

In its ‘Operational Guidance’ Sandridge quotes lifting costs of $15-$17 per barrel of oil; ‘DD & A’ (depreciation, depletion and amortisation) costs of $18.25-$20.20 per barrel; ‘General and Administration’ costs of $5.85-$6.50 per barrel; production taxes of $1.75-$1.95 per barrel; and interest expense of $8.70-$9.60 per barrel.

Add up the mid-point of those numbers and you get a figure of $58.575 per barrel, all in, which leaves a healthy profit margin on each barrel sold for $90 plus.

For separate projects, Sandridge quotes Internal Rates of Return of 62% and 82%, which look highly attractive under any circumstances but especially for what is essentially quite a low risk play.

There could be a stampede

Of course there are a few reasons for caution. Where there is a stampede into a sure thing you can bet that eventually some will overpay for their entry ticket. Depletion, the rate at which the flow of oil subsides, is not entirely predictable. And if the USA finds too much oil, it could just throw the whole world market into imbalance and sink the oil price.

But for the time being the outlook is rosy – and one of the most exciting participants, with a penny share price, is starting to make good money for readers of Red Hot Penny Shares.

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Big Oil knows where the money is, and its buried with the shale gas. The latest such foray into that arena is ExxonMobil’s agreement to buy Denbury’s shale assets in North Dakota’s Bakken field, which is awash in oil and gas.

Oil companies, which are constrained in the United States as to where they can drill, expect their investments in shale gas to pay off. It’s a way to diversify their holdings in a complementary fashion. In other words, natural gas is often found alongside oil deposits. And while developers have been forced to “flare” the fuel because they have been unable to monetize it, high electric utility demand for it is now providing the push to build the required infrastructure.

“This agreement provides a strategic addition to ExxonMobil’s North American unconventional resource base,” says Andrew Swiger, senior vice president of ExxonMobil. “ExxonMobil’s financial and technical strength will support continued development of America’s natural resources, which strengthens U.S. energy security while creating jobs.”

For its part, Exxon will get 196,000 acres, increasing its total land in the Bakken to 600,000 acres. Texas and North Dakota lead the United States in oil and gas production. The acquisition is considered small for Exxon but it is in keeping with its economic strategy, which is to acquire more such assets. Two years ago, it bought XTO Corp. for $31 billion. Since then, it has spent about $3 billion to collect shale gas leases throughout the United States.

In exchange for its Bakken shale assets, Denbury will receive $1.6 billion in cash and acquire ExxonMobil’s interests in the Hartzog Draw field in Wyoming and Webster field in Texas, which currently produce about 3,600 net oil equivalent barrels per day of natural gas and liquids.

Denbury said in a formal statement it is focusing on fields where it can leverage its know-how of enhanced oil recovery mechanisms using carbon dioxide. By capturing such releases from power plants, they can then be funneled into oil wells to ease the production process. To that end, the company’s Chief Executive Phil Rykhoek said that this ability “offers one of the most compelling rates of return in the oil and gas industry today.”

Potential Problems

The Potential Gas Committee, a research arm of the natural gas and petroleum industries, has said that this country has a natural gas resource base of nearly 2,000 trillion cubic feet — more than in the last 46 years. Most of the increase since the last 2009 study is the result of re-evaluating shale gas plays along the Gulf Coast Mid-Continent and Rocky Mountain areas.

Eric Potter of the University of Texas has given further estimates that 5,500 wells in the Barnett Shale region in Dallas will generate $100 billion for the Texas economy over several years.

All that is why the oil giants are interested in shale. ExxonMobil, in fact, has previously said in its annual energy outlook that it anticipates natural gas to grow faster over the next 20 years than either oil or coal.

Beside ExxonMobil, Chevron bought Atlas Corp. in February 2011 for $3.2 billion. RoyalDutch Shell, meantime, acquired East Resources for $4.7 billion in cash. 

As for ExxonMobil, it now possesses the resource equivalent of 45 trillion cubic feet of shale gas, shale oil and coal-bed methane. By betting on natural gas, all of the oil firms are expecting tighter air quality restrictions; natural gas emits far fewer emissions than either oil or coal.

“As the outlook shows, the world will still rely on oil and natural gas to meet much of its energy demand for years to come …,” says the American Petroleum Institute. But it goes on to say that the progression toward carbon constraints will force a move toward natural gas and other less carbon-intensive fuels to meet electricity demand.

But potential problems loom. For starters, flaring remains an issue and especially in the Bakken fields. But the industry is insistent that it will make the necessary investments to transport the natural gas.

Furthermore, shale is mined by pumping water, sand and chemicals deep underground to break it free from the rocks where it is embedded. Many communities and environmental groups say the process contaminates the groundwater. The issue, though, is getting a lot of attention and a recent high-profile panel appointed by the U.S. Department of Energy has concluded that through proper stakeholder involvement, the drilling processes in question could be safely done.

It’s a natural extension for Big Oil to reach out to shale gas producers. And it’s also beneficial for those smaller gas developers, which need access to capital. That’s why similar deals such as the one Exxon just entered into will continue.

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U.S. oil imports have declined very significantly over the past four years.  The Obama Administration claims credit for increased oil production and reduced U.S. oil imports based on recent policy changes.  Mitt Romney proposes other changes to substantially decrease future U.S. imports.  All politics aside, what factors have actually contributed towards reducing U.S. oil imports recently?

To begin this analysis we will review historic U.S. crude & petroleum oil imports, oil consumption and domestic production trends.

Total U.S. ‘net’ oil imports (gross imports minus exports) were at lowest levels during the early 1980’s following the Iranian revolution, and increased to a maximum of 12.5 MBD (million barrels per day) by 2005.  Imports have since declined very significantly.  Since 1973 U.S. domestic oil production (crude oil + natural gas (NG) liquids) declined continuously to a minimum of 6.7 MBD in 2008.  This decline of production was due to a combination of restricted access to on-/offshore reserves and depletion of existing fully developed reserves.  Oil + NG liquids production have increased continuously over the past four years largely due to significant drilling technology development breakthroughs.  U.S. total petroleum oil consumption has varied from a low of 15.2 MBD in 1983 up to a maximum of 20.8 MBD in 2005.  Petroleum oil consumption has declined since 2005 due to a number of factors that will be covered in detail.

Do you recognize a historic supply-demand pattern?  U.S. oil consumption has generally trended the level of net imports over the years.  This trend appears to have changed since about 2007, the beginning of the economic recession and a year before U.S. total crude oil and NG liquids production began increasing.  So, what major factors have contributed to recent reduced U.S. net oil imports?

The above EIA data shows the primary factors that contributed to the 3.3 MBD reduced U.S. net imports 2008-12.  The largest factor has been the combination of increased crude oil and NG liquids production and the second largest factor is reduced petroleum oil consumption.  Significant increases in petroleum oil refining volume gains (processing efficiency) accounts for the majority of the ‘gains and adjustments’ developed by the EIA.

How much has the current Administration’s recent policy change to open additional Federal on-/off-shore areas to new development contributed to increased oil & NG liquids production?  Developing new oil & gas reserves is fairly complex.  The process involves competitively bidding for available reserves, seismic surveying, permitting, drilling exploratory & production wells, installing infrastructure (roads, utilities, pipelines, intermediate storage, etc.), and expanding/putting the most economic oil & gas fields into full production.  This overall process normally takes 3-5 years from bidding/planning-to-full production.  The current Administration’s new policy to open Federal on-/offshore areas for possible development did not begin until 2010.  The timing of this policy change, the multiple year process required to develop new production, and the fact that nearly all recent oil & gas development has occurred on non-Federal and private land, makes the current Administration’s claimed credit for significant 2008-12 increased oil & gas production not very feasible or significant.

Declining U.S. petroleum oil consumption is the second most significant contributing factor towards reduced net oil imports.  Which U.S. End-use sectors have contributed the most towards reduced petroleum oil consumption?

The Residential sector petroleum oil consumption has decreased slightly 2008-12 due to a combination of energy efficiency improvements supported by the current Administration and the economic recession impacts.  Following the housing bubble and massive foreclosures, a large number of homes were vacant 2008-12, which reduced petroleum heating oil and LPG consumption significantly.  The recent energy efficiency improvements are estimated to contribute about 20% of total reduced Residential sector petroleum consumption or about 1% of total U.S. reduced petroleum consumption.  The Commercial sector petroleum oil consumption surprisingly increased slightly during this same period.  This includes petroleum heating oil and motor fuels consumed in stationary engines/equipment.

The Electric sector has experienced the third largest reduction of petroleum oil consumption and has decreased by about 50% 2008-12.  Reduced Electric sector petroleum has been due to ‘fuel switching’ from more expensive petroleum distillate and residual fuel oils to lower cost natural gas, and substantially expanded renewable capacity.  Renewable power has been strongly supported by the current Administration and has increased from 3.1% to 5.9% of total U.S. power generation (excluding hydropower) 2008-12.  Added renewable power possibly accounted for 50% of total reduced Electric sector  petroleum consumption and about 6% of total U.S. reduced petroleum consumption.

The Industrial sector petroleum consumption decreased very significantly 2008-12.  Reduction in petroleum has been due to a broad range of factors, mostly related to the economy.  As the recession increased, Industrial output decreased.  This factor reduced overall consumption of petroleum oil including heating fuels and (non-road) equipment motor fuels.  Other reductions included decline in metals production (less petroleum coke), reduced petrochemical production (less petroleum feedstocks), and reduced road work by cities and states (less asphalt).

The Transportation sector has overwhelmingly been the largest source of reduced petroleum oil consumption among all End-use sectors.  Which Transportation modes have contributed most towards this reduced petroleum oil consumption?

All the different modes of transportation have experienced reduced petroleum motor fuels consumption 2008-12.  The smallest reduction of Transportation sector petroleum consumption occurred within the specialty modes/supplies; aircraft aviation gasoline (av. gaso.), LPG motor fuels, and lubricants.  The next smallest reduction has occurred in large marine vessel shipping that consumes heavy residual fuel oils.  The reduction in marine shipments is largely related to the economy and reduced Industrial sector in-/output.

The third largest source of reduced Transportation sector petroleum motor fuels consumption is commercial jet fuel.  This was largely due to the economic recession, and the resulting reduced passenger travel and reduced commerce transport.  The second largest source of reduced transportation petroleum consumption is diesel motor fuel.  Diesel motor fuels (on-road and off-road vehicles, and lighter marine shipping) have also been reduced primarily due to significant reductions in overall economic activity or reduced commercial diesel vehicle usage.  Up to 25% of reduced diesel consumption has been due to a combination of increased biodiesel blending (more detail to follow) and new heavy duty truck increased fuel efficiency.

The largest source of reduced Transportation sector and total U.S. petroleum motor fuels consumption is gasoline.  During 2008-12 reduced petroleum gasoline consumption was about 310 KBD (thousand barrels per day), which is equivalent to 35% of total U.S. reduced petroleum oil consumption.  The cause for reduced petroleum gasoline consumption is due to a combination of new vehicles improved fuel efficiency, increased biofuels, and the economic recession.  The number of registered on-road ‘light duty vehicles’ (LDV) that are primarily fueled by gasoline has increased steadily every year since World War II.  In 2008 the total number of registered LDV’s peaked at 197 million.  Registered LDV’s have since declined to about 190 million.  In addition, the average annual ‘vehicle miles traveled’ (VMT) also declined significantly 2008-12.  This historic reduction in U.S. total registered on-road LDV’s and VMT are largely related to the economic recession and the economy.  The combination of reduced income of Households and possibly high un-/under-employment has caused fleet size and VMT to shrink significantly since the recession.  Reduced fleet size and VMT is estimated to have contributed to about 5% of the 2008-12 reduced Transportation sector gasoline consumption.

New LDV sales were dropping substantially 2008-09 due to the recession (13 to 10 million LDV’s per year).  Consistent with the American Recovery and Investment Act (2009) strategy of increased Government spending to possibly help improve the economy, Congress passed the ‘Car Allowance Rebate System’ (CARS).  CARS was commonly called the ‘Cash-for-Clunkers’ program.  Purchasers of new LDV’s received generous rebates (subsidies) for scrapping their older inefficient LDV’s.  During 2009 the CARS program subsidized 690 thousand new LDV purchases for a total of $2.9 Billion.  Although critics argue that CARS had insignificant impacts, since most purchases would have eventually occurred without the subsidies in the future, the program directionally did help encourage added LDV sales during 2009.   In the best case, the current Administration’s CARS program contributed about 2% of the 2008-12 reduced Transportation sector gasoline consumption and about 1% of total U.S. reduced petroleum consumption.

The largest sources of Transportation sector reduced petroleum gasoline consumption 2008-12 was due to improved fuel efficiency of all new vehicles and increased biofuels.  During 2008-12 consumers purchased 44 million LDV’s, with increasing fuel efficiency required by the CAFE standards (excluding the 690 thousand CARS qualified LDV’s).  The 2008-12 CAFE standards were established under the Energy Independence and Security Act (EISA) in 2007.  Increased (non-CARS) new purchased LDV fuel efficiency contributed to about 48% of total Transportation sector reduced gasoline consumption 2008-12.  How much did the current Administration’s recent CAFE standards contribute to the Transportation sector’s 2008-12 reduced petroleum consumption and U.S. imports?  The answer is zero.  All effective 2008-12 CAFE standards were established by the previous Administration’s EISA 2007.

The balance of reduced Transportation sector gasoline and total U.S. net petroleum oil imports is due to increasing biofuels; primarily conventional ethanol.  Not shown in Table: DOE/EIA MER Petroleum Overview Data 2008-12 is the increased conventional corn ethanol (and smaller amounts of soybean biodiesel).  Increased ethanol biofuels accounted for about 45% of the total reduced Transportation petroleum gasoline consumption 2008-12.  Increased ethanol (and biodiesel) blending resulted from the latest ‘Renewable Fuel Standard’ (RFS2); also created under EISA 2007.  Similar to the bulk of new LDV purchases, the current Administration’s policies did not significantly affect biofuels production-consumption 2008-12.

Overall, the most significant factors that have reduced 2008-12 U.S. total crude and petroleum oil imports are: 1) increased crude oil and NG liquids production, 2) reduced petroleum oil consumption from increased energy efficiency improvements, increased biofuels and renewable power, and, 3) the weak economy.  When the economy eventually returns to normal, petroleum consumption will likely increase.  Unless continued increases in oil & gas production are achieved, and further increases in energy efficiency improvements and renewable energy capacity are made, we are not likely to continue reducing future oil imports at current rates.

So, how much credit for 2008-12 reduced U.S. oil consumption and net imports should be attributed to the current Administration?  This analysis indicates the Administration’s continued support of renewable power and increased Residential efficiency, and the new CARS program have contributed to about 8% of total reduced U.S. petroleum oil consumption and about 2% of total reduced U.S. oil imports.  The benefits from opening up addition Federal on-/offshore to new production, the future new CAFE standards, and further increase of renewable energy is yet to be developed.

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BHP Billiton’s onshore U.S. shale plays will play an essential role in the company’s long-term strategy, despite the recent writedown of its Fayetteville shale assets due to weak North American natural gas prices.

U.S. natural gas prices would need to rise to $3.50/Mcf before BHP Billiton would reshift its drilling focus back towards dry natural gas, said J. Michael Yeager, the company’s group executive and chief executive of petroleum, at the Barclays CEO Energy Power Conference Tuesday in New York.

BHP Billiton has scaled back its Fayetteville and Haynesville drilling programs due to weak prices for dry natural gas, and has reallocated its rigs to liquids-rich plays such as the Eagle Ford and Permian plays in south and West Texas, Yeager told conference attendees.

Instead, the company is aggressively pursuing its Eagle Ford assets, with plans to spend over $1 billion over the next five years to expand Eagle Ford production infrastructure. This infrastructure includes six new processing plants, added capacity of 100,000 barrels per day of liquids and 1 billion cubic feet per day of gas and approximately 800 miles of pipeline, Yeager told conference attendees.

“The Eagle Ford is probably the most prolific field in the U.S., if not the world,” Yeager said.

With strong rates of return, with many wells exceeding 100 percent and average single well payback in one year, Yeager sees potential for higher recovery factors over time through reduced well spacing or improved technology.

BHP Billiton is also fully appraising its Permian acreage, which has had encouraging results so far. The company has increased its acreage from 378,000 acres at the time it acquired these assets to more than 440,000 acres. BHP Billiton plans to drill more than 60 wells in the Permian in fiscal year 2013, targeting oil from multiple pay horizons. The Wolfcamp shale is over 900 feet thick in some areas, Yeager noted.

The company will have approximately 40 rigs operating in the onshore U.S. in fiscal year (FY) 2013, with over 85 percent directed towards the liquids rich-Eagle Ford and Permian Basin, Yeager said.

While the company has shifted its focus to oil and liquids plays, it is prepared for a ramp-up in dry gas production as prices improve, noting that BHP Billiton’s dry gas shale properties are among the lowest costing plays in the United States. Yeager noted that the company remains optimistic about the long-term outlook for natural gas.

In the Haynesville, the company’s core acreage delivers “very strong” per well recoveries with some over 20 billion cubic feet (Bcf). The acreage has more than 20 percent forward rates of returns, even at current prices, and the company is adding significant value through continuous improvement initiatives, Yeager said.

BHP Billiton is focused on opportunity preservation and operational momentum in its Fayetteville operations. The company already is realizing significant operational improvements which will reduce costs and enhance value, Yeager said.

The company has approximately 1.6 million combined net acres across Texas, Louisiana and Arkansas, with a resource base of approximately 8 billion barrels of oil equivalent and four giant fields – Haynesville, Eagle Ford, Fayetteville, and the Permian – with 50-year lives, Yeager said.

BHP Billiton’s U.S. onshore assets offer strong returns and fast payback, as well as multiple upside opportunities and significant flexibility to respond to market conditions, Yeager said.

Shale liquids will represent the largest component of BHP Billiton’s $6.5 billion capital program planned for FY 2013. The company’s Gulf of Mexico and Western Australia activity will drive conventional spending in its capital program.

The company anticipates strong growth from its U.S. Gulf operations, where it anticipates future production growth from its Shenzi, Atlantis and Mad Dog fields, which are now online and producing. The company is planning to drill three significant wells in the Gulf in FY 2013.

Shenzi is still producing over 100,000 barrels of oil equivalent per day (boepd) after three years, with 94 percent average uptime during that period. The company achieved first water injection in May to increase reservoir performance, and has successfully appraised acreage north of Shenzi, said Yeager.

While the new offshore regulations in the Gulf following the Macondo incident have lengthened the drilling time per thousand feet from two to four days, BHP Billiton still has an advantage to the industry overall, Yeager noted.

The industry average drill time was five days before the Gulf drilling moratorium, and six days after the moratorium was lifted.

“We’re working through it like everyone else is,” said Yeager, noting of the changes in offshore drilling before and after Macondo.

Still, the company sees great potential in the Gulf, such as the Shenzi oil reservoir, which is taller than BHP Billiton’s 25-story office building.

The BP-operated Atlantis field is now online again after being down most of April, May and June, and the BP-operated Mad Dog is producing again after the drilling rig on top of the platform – which was blown off the top by Hurricane Ike in 2008 – has been replaced. The first new Atlantis producers are being drilled since the moratorium. Pre-commitment funding has also been approved for the Mad Dog phase 2 project, a new 130,000 boepd development that will double field deliverability, Yeager said.

The company is forecasting 8 percent production growth in the next fiscal year to 650,000 to 660,000 barrels of oil per day from its global operations, Yeager said. Fifteen percent of that production growth will be driven by liquids. Gas production will remain flat as production from the Macedon and North West Shelf in Australia offset lower shale dry gas volumes.

In the past five years, the company’s volumes have grown to over 600,000 boepd and underlying earnings before interest and taxes has grown to over $6 billion. The company’s workforce has also doubled to 4,000 employees.

BHP Billiton’s global asset base will offer plenty of training opportunities for its young workers, Yeager said.

BHP Billiton has proved reserves of over 2.5 billion barrels of oil equivalent and a total resource base of approximately 11 billion barrels of oil equivalent.

The company is expanding its production position offshore Western Australia, with:

continued development of the Pyrenees oil field

new volumes from Macedon

long term growth driven by the 10 trillion cubic feet Scarborough liquefied natural gas (LNG) development

additional growth potential from the Browse LNG project.

The company will drill one well offshore Western Australia in FY 2013 and has seismic activity planned in the region.

BHP Billiton will evaluate new plays offshore India with more than 3,106 miles (5,000 kilometers) of 2D seismic planned for fiscal year 2013. The company also will evaluate an extension to a key emerging play offshore South Africa, where it will conduct a 3,861- square mile (10,000 square kilometer) 3D seismic acquisition.

The company will also drill a well and gather over 3,728 miles (6,000 kilometers) of 2D seismic data offshore Malaysia in FY 2013.

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Plains Exploration & Production Co.’s $6 billion move into Gulf of Mexico oil fields marks its largest acquisition ever — a bid to boost the oil component of its energy output over lower-priced natural gas via techniques for wringing more barrels out of mature fields.

The hefty price tag to be paid by Plains Exploration & Production (US:PXP) in separate deals with BP PLC (US:BP) and Royal Dutch Shell (US:RDS.A) (US:RDS.B) outweighs the Houston energy firm’s current market capitalization of $5 billion, as it bets big on tapping into the riches of the Gulf.

To fund the deal, Plains has lined up $7 billion in debt commitments, with plans to channel its cash flow to reduce its debt starting by the end of 2013.

Shares of Plains fell 8% Monday as investors initially reacted to its heavier debt load going forward.

On the up side, Plains held out the possibility of increased oil output from the fields as well as exploration potential in nearby areas.

“Significant upside production potential exists in the currently producing reservoirs through numerous low-risk, high-margin drilling/recompletion and well workover opportunities,” Houston-based Plains said.

Plains will boost oil volumes to 89% of its total production in 2013, up from about 61% projected for 2012. Since oil is much more lucrative than natural gas, Plains will boost its cash flow considerably by adding more crude production.

All told, Plains sees up to $5 billion in cumulative excess cash flow between 2013 and 2016. The deals are expected to close by the end of December.

With financing from a group of banks led by J.P. Morgan Securities LLC, Plains will gain 67,000 barrels of oil-equivalent production a day in addition to potential increases that would accrue from oil-reservoir stimulation technology.

Analysts at Tudor Pickering Holt said they’re hoping to see more details on the financing of the acquisitions, but their initial take is that Plains may not have to sell more common stock to raise money to close the deal.

That would be good news for stockholders, who won’t see the value of their shares diluted by a big equity sale. Instead, the transaction stands to be “accomplished via additional debt, asset sales and free cash flow,” the Tudor Pickering analysts said.

In the biggest chunk of the deal, BP will get $5.5 billion from Plains for its interests in the Holstein, Marlin and Horn Mountain production platforms in Gulf waters located south of New Orleans.

A shifting Gulf focus for BP

For BP, the deal represents part of a divestment plan announced in the wake of its 2010 Macondo oil well blowout, which resulted in the death of 11 workers, the destruction of the Deepwater Horizon oil rig and the largest maritime oil spill in U.S. history. Meanwhile, Royal Dutch Shell will get $560 million for its 50% stake in Holstein.

The legal fight over the oil spill took a difficult turn for BP in recent days as the U.S. government leans toward pursing gross-negligence charges against the oil company.

Tudor Pickering analysts said BP got a good price for the oil fields — about $700 million more than they projected.

“A reduced and more focused exposure to the Gulf of Mexico is welcome for BP, we think, in the midst of recently-escalated federal pursuit of Macondo gross-negligence charges,” they wrote.

For its part, BP said the sale fits its strategy to focus on “giant fields and deepwater exploration.”

Taking aim at the oil-rich region, BP said it’ll bear down on four major operated production hubs and three non-operated deepwater production hubs.

“While these assets no longer fit our business strategy, the Gulf of Mexico remains a key part of BP’s global exploration and production portfolio and we intend to continue investing at least $4 billion there annually over the next decade,” said Bob Dudley, BP’s group chief executive, in a statement.

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The U.S. government said nearly 8 percent of the daily oil production and around 6 percent of natural gas production in the Gulf of Mexico remains shut-in.

Energy companies in the Gulf of Mexico and along the southern U.S. coast shuttered facilities ahead of Hurricane Isaac, which struck the region as a Category 1 storm in late August.

The U.S. Interior Department’s Bureau of Safety and Environmental Enforcement said personnel are yet to return to two of the 596 manned production platforms in the Gulf of Mexico. One rig of 76 remains unmanned.

The BSEE estimates that 7.98 percent, or around 110,000 barrels of oil per day, of the usual daily oil production is shut-in. In terms of natural gas, about 6.11 percent, or 274 million cubic feet, of the daily natural gas production is idled.

“The remaining shut-in oil and gas production has been slow to return due to damage at onshore processing facilities,” the agency stated.

The BSEE said oil and natural gas operators with installations in the region have submitted reports of mainly minor damage from Isaac.

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U.S. crude stocks fell sharply last week as Hurricane Isaac’s passage through the Gulf of Mexico shut in production and closed ports, data from the industry’s American Petroleum Institute showed on Tuesday.

Crude inventories fell by 7.2 million barrels in the week to Aug. 31, compared with analysts’ expectations for a drawdown of 5.3 million barrels. The API-reported inventory drop was the largest since the week to July 27, when stocks fell by almost 12 million barrels.

Hurricane Isaac temporarily disrupted the majority of oil production in the U.S. Gulf of Mexico for several days, shut import terminals and shuttered several refineries in the region. Drilling companies are busy restoring output this week.

U.S. crude imports fell by 1.7 million barrels per day (bpd) to 7.9 million bpd, the API said.

Refinery utilization fell 3.8 percentage points to 87.1 percent of capacity, API figures showed.

In PADD 3, the Gulf Coast region, crude stocks fell by nearly 7.6 million barrels and gasoline inventories were down by 1.8 million barrels, while distillates fell by 800,000 barrels.

Total U.S. distillate stocks fell by 132,000 barrels. Analysts polled by Reuters had expected a larger 1.9-million barrel draw.

Gasoline stocks fell 2.3 million barrels, compared to forecasts for a larger decline of 3.4 million barrels.

U.S. crude futures slightly extended their earlier gains following the release of the API stock data, rising in post-settlement trading to $95.95 per barrel. Crude had settled earlier up 6 cents per barrel at $95.36.

Crude stocks at the delivery hub of Cushing, Oklahoma, rose by 58,000 barrels last week, API said.

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Apache Corporation (NYSE, Nasdaq: APA) surpassed the 3 million mark with its popular tree giveaway program, announcing Tuesday it awarded nearly 500,000 more trees to communities in 2012.

Since donating its first seedling in 2005, Apache has awarded 3.2 million trees to nonprofit organizations in 16 states through grants from its philanthropic affiliate in an effort to enrich the communities where the company operates. That first year, the Apache Foundation donated 1,521 trees. This year, it awarded 494,011 trees.

The Downtown Shreveport Development Authority is among this year’s recipients and will receive 100 trees from Apache.

“This is wonderful news for downtown Shreveport,” said Deputy Director Janie Landry. “We are delighted and very appreciative of this grant.”

In all, 71 groups in Texas, Alabama, Louisiana, Mississippi and Oklahoma will get trees from Apache this year. The trees go to nonprofit organizations including cities, counties, schools, parks, universities, youth associations, wildlife refuges and community groups.

The trees allocated for the 2012-2013 planting season are native to the areas where they are donated to ensure a potential for growth and include oak, maple, pecan, cypress, crape myrtle and birch. Recipients must show they can properly care for the trees.

“We had a record number of requests this year,” said Obie O’Brien, who oversees corporate outreach programs for Apache as vice president of Government Affairs. “We look forward to continuing the program for years to come. Enriching the communities in which we operate is something we greatly value.”

Planting trees is a valuable natural resource that improves air quality, provides essential habitat and enhances neighborhoods. It is estimated each tree can remove 110 pounds of carbon dioxide per year for 50 years, or about 2.5 tonnes during the life of the tree.

Earlier this year, Apache presented the city of Houston with $135,000 in proceeds from two company-sponsored fundraising events. The donation was earmarked for the reforestation of city parks, which were devastated by a year-long drought. The company also donated 50,000 trees to the city Parks and Recreation Department.

In Galveston, Apache stepped forward to help the island reach its goal of planting 25,000 trees in five years after it lost many trees during Hurricane Ike. Apache also planted mature oak trees along Broadway Boulevard, the main entrance to the city.

In the Texas Hill Country town of Bastrop southeast of Austin, Apache has joined efforts to replace pine trees destroyed in last year’s wildfires that burned more than 32,000 acres. The foundation has pledged $60,000 to help pay for this year’s crop of 550,000 loblolly pine seedlings, which will be delivered to Bastrop County this winter to replant 400 acres in hard-hit Bastrop State Park and 450 acres of private property.

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