_

The energy sector underperformed the broader market for the first half of 2010 before rising commodity prices provided some lift in the third quarter and set the stage for a rally into 2011. For investors, the weak start to the year means there is still time to get in at reasonable prices, but not every energy bet will be a winner. Higher oil prices will be a benefit, but excess demand could keep natural gas-focused names in the doghouse, while some analysts like coal to continue its unexpected star turn.

The Energy Select Sector SPDR ETF is up 20.1% since June 30, but only 5.1% on the year, compared with to gains of 15.8% and 7.1% for the S&P 500. Most of the outperformance so far in the back half of 2010 can be attributed to a volatile, but mostly weaker U.S. currency. “The dollar is inversely correlated with global equity prices and commodities,” explains Bob Morris of Citi. “Oil and coal are directly related to the global macro [situation]” says Morris, “and demand growth from emerging markets has been strong.”

Oppenheimer’s Fadel Gheit takes a contrarian view. Explaining that the economic fundementals of the oil market, supply and demand, have limited impact, he says “the main driver behind prices is financial speculation.” Gheit doesn’t deny the power of stronger than expected recovery, as it will obviosuly help demand, but he says “people are afraid of inflation, and they are also afraid of investing in real estate, so they are buying commodities.”

Futures contracts have already shown that it will be a good quarter for companies with greater exposures to oil, and bad for those with more natural gas in their portfolios. “Things are very simple in this market, significantly better oil prices will be realized, just look at the futures, oil’s going to be $5 to $6 above,” end of third quarter prices, he explains. Crude futures have been progressively trending upward, with December 2010 futures at $82.92, and a steady increase in futures prices to February 2012, when a barrel of oil is priced at $87.44.

In Pictures: 10 Energy Plays To Ride Higher Prices

Higher crude prices in the third quarter helped a number of companies, including the likes of Exxon Mobil and ConocoPhillips, sharply increase profits despite a decrease in production from a year ago.

Natural gas isn’t as lucky. “It is going sideways,” says Gheit, who explains “it’s simply a question of supply exceeding demand, there’s plenty of gas in inventories.” Morris agrees, saying “natural gas operates mainly on a North American market, the shale plays have oversupplied these markets,” thus depressing markets.

Natural gas futures contract prices have been progressively hit, with December 2010 prices at $3.84 every thousand British Thermal Units, or MBtu. Futures prices all the way to January 2013 have been falling in value.

“Emerging market demand has little to do with it, the market will continue to be correlated to financial [speculation],” says Gheit, and continues “that’s why we like any company more exposed to oil,” such as Whiting Petroleum, and Murphy Oil Corporation.

Original Article

_

EnCana curtailed spending to its promising Haynesville Shale prospects due to oil-services shortages. A bigger concern, however, could be the marginal economics of drilling wells at prices below $4.50 for natural gas.

Canadian-based EnCana (ECA) is the third-largest domestic producer of natural gas in North America, with acreage leased in substantially all of the major unconventional gas plays. To expand development and production capacity in 2010, the energy giant had budgeted approximately $5 billion in capital expenditures — slightly more than anticipated cash flow of $4.4 billion to $4.6 billion.

Given depressed gas prices and rising oil-services costs, management said on the third-quarter 2010 earnings call that the company planned to defer $200 million from its 2010 capital budget to 2011, due to rising costs associated with the backlog of completion delays for Haynesville Shale wells in northwest Louisiana.

As a result, exit guidance for 2010 production was revised downward slightly, from 3.36 billion cubic feet equivalent per day (Bcfe/d) to 3.31 Bcfe/d, still up about 10 percent from last year. EnCana’s flexible capital structure, however, should cushion any cash shortfalls — including asset destruction (or sales) — needed to reach stated goal of doubling 2009 production by 2014:

* Debt-to-capitalization (debt plus shareholder equity) of 30 percent and debt leverage just 1.3 times EBITDA, according to third-quarter 2010 regulatory filings;

* Unused commercial credit facilities totaling about $5 billion; and,

* Long-term debt of $7.6 billion (excluding $4.2 billion in future tax liabilities), with an average duration of about 13 years; and only about $1.82 billion in obligations mature in the next one to three years.

Full year 2010 cash flow assumed an average price for natural gas of at least $5 per thousand cubic feet. With only about 45 percent of remaining daily output pre-sold this year, each one dollar decline in NYMEX gas contracts for December delivery will result in a $375 million decrease in operating cash flow, according to an in-house pricing sensitivity analysis. Given sluggish commercial and residential demand and record inventory stockpiles, prices recently traded near 13-month lows of $3.31, before bouncing back to the $4 level by month-ended October.

Chief executive Ron Eresman admitted to analysts on the earnings call that management had held back on more hedging activity because they mistakenly thought gas prices would rebound back to the $6 to $7 range in 2011 (prices sufficient to guarantee  returns in excess of cost of capital by more than 40 percent). Ergo, the company hedged only about 1.2 billion (33%) and one billion cubic feet per day (less than 26%) of expected daily production for 2011 and 2012, at respective average prices of $6.42 and $6.46.

Despite weaker natural gas fundamentals, Halliburton (HAL) said on its own quarterly earnings call that rig counts in North America had increased roughly 40 percent from the end of 2009, and opined that creeping oilfield services cost inflation was sustainable into 2012. Why? Oil and gas operators also developing shale holdings have historically needed active drilling programs to maintain leases and production capacity (due to higher depletion rates characteristic of shale formations).

To date, EnCana has demonstrated success in offsetting the estimated 8 percent rise in oilfield services costs through operational efficiencies that have lowered year-on-year upstream spud and administrative costs by 17 percent (to $0.99 – $1.10 per Mcfe).  U.S. shale well-development and completion costs have fallen anywhere from 15 percent to 40 percent, depending on location. For example, in the Haynesville Shale play, well cost expenses dropped from $15.6 million in 2008 to $8.0 – $9.0 million per well by third-quarter 2010!

Completion costs account for approximately 40 percent of total well capital budgets. Management is pursuing multiple strategies that could further negate well-cost inflation, including:

* Gains in gas recovery yields;

* Better water reclamation techniques (average spud requires four million gallons); and,

* Absorb value chain savings – by acquiring supplier nodes, like hydraulic fluids suppliers.

EnCana believes it can also decrease overhead costs and reduce well completion time from a current mid-40 day range to under 35 days by bringing some field-related services in-house. For example, constructing a fleet of “fit-for-purpose” completion equipment and “gas factories” (multiple wells tightly spaced, drilled from a single pad and produced with a single pipeline connection).

“Do not spoil what you have by desiring what you have not. Remember that what you now have was once among the things you only hoped for.” ~ Greek philosopher Epicuris (BC 341 – 270)

Don’t be fooled by the company’s recorded land position of 430,000 net acres. A “use it or lose it” ideology applies to natural gas drilling rights — about 3 to 5 years in Louisiana. Management has already said that land retention — spud footprints — will drive development efforts in coming months.

That Haynesville is high priority to EnCana’s future survival is noted in its 2010 budget — about 21 cents of each dollar.

Management insists that it can profitably develop its Haynesville properties, with full cycle supply costs (including land acquisition) between $4.15 per MMBtu and $5.00 per MMBtu.

A Halliburton white paper published last summer illuminates the unconventional challenges that could impact the economics driving shale pay zones, especially the still emerging Haynesville play:

Still in the early discovery stage, the Haynesville Shale environment already has proved especially challenging. The reservoir changes over intervals as small as four inches to one foot. In addition, at depths of 10,500 feet to 13,500 feet, this play is deeper than typical shales, creating hostile conditions. Average well depths are 11,800 feet with bottom-hole temperatures averaging 300°F and wellhead treating pressures that exceed 10,000 pounds per square inch (psi). As a result, wells in the Haynesville require almost twice the amount of hydraulic horsepower, higher treating pressures and more advanced fluid chemistry than the Barnett and Woodford shales.

Granted, EnCana holds promising leaseholds in the DeSoto and Red River Parishes of northwestern Louisiana, near “sweet zones” for competitors like Petrohawk (HK) and Chesapeake Energy (CHK). In fact, EnCana opined on recent conference calls that wells brought online are seeing impressive initial production (IP) rates, with first 30-day IP averages of 15 MMcfe/d (attributed to improvements in multi-stage fracturing and a better understanding of choke pressures). Given these IPs, management safely projects estimated ultimate recoveries (EUR) could yield 6 to 9 Bcfe!

To the contrary, there is scant a posteriori experience or evidence to back such a game-changing claim:

* The experience of Chesapeake Energy (CHK), the dominant natural gas producer in the region, should be a warning to EnCana. First year decline rates for its Haynesville gas wells are, on average, 86 percent, according to published data. In fact, by the end of the third year, its wells are producing less than 8 percent of original recovery rates!

Moreover, the average of 44 Chesapeake gas wells (with at least 12-months worth of data) has proven initial EURs too optimistic: Given production declines, initial estimates of 6 Bcf were revised downward 60 percent to 2.4 Bcf, according to recent analysis prepared by well-known shale critic Arthur Berman, Labyrinth Consulting Services.

Goodrich Petroleum (GDP) has reported a similar change in production curves for its first wells, too: Decline in year one of 84 percent, accompanied by a downward revision in production during year two — as production decline rates accelerated from anticipated 32 percent to an actual 40 percent!

Some might argue such overall economic changes are immaterial, due to higher year one volumes. This is somewhat disingenuous, given further recoverability efforts would result in offsetting higher operating costs.

As of December 31, 2009, EnCana held proved and recoverable natural gas reserves totaling 11.06 Bcf, worth an estimated $8.4 billion (discounted at 10%). During the next 18 months, look for EnCana to revise reserves and asset valuations upward. Save for a doubling in natural gas prices, should management conclude these favorable outcomes were justified due to impressive IP rates from Haynesville gas wells, run — don’t walk — to the exits.

Original Article

_

BOEM claims drilling will resume after rig inspections. By Jeremy Alford

The uncontrolled release of oil into the Gulf of Mexico this year has brought about a new culture of safety in the domestic energy industry that is trickling down from the federal level. While the explosion of BP’s Deepwater Horizon rig is being credited with the wave of regulatory changes, the fact is that the industry faces similar — and thankfully less dramatic — challenges practically every year.

According to the U.S. Census Bureau, there were more than 3,500 spills in 2008, a vast majority of which emanated from ships and barges and resulted in less than 100 gallons each, although two of the spills yielded as much as 1 million gallons of spilled oil.

These are the kind of statistics that Peter Lehner, executive director of the Natural Resources Defense Council, a New York-based environmental advocacy group, conjures up when considering the ban that was lifted earlier this month on deepwater drilling. President Barack Obama instituted the moratorium following the BP incident in the name of safety and regulatory reforms.

Lehner argued that Obama’s work is incomplete and that the ban should have remained on the books. “To ensure a disaster like this never happens again, we must know what caused it in the first place. We’re still waiting for that answer, and until we get it the moratorium should remain in place,” he said. “Multiple panels are still investigating the accident. …We should wait for their solutions, because until we address the cause, we’re still gambling with the Gulf.”

The Obama administration, however, argues that it has sufficient safety regulations in place to move forward. In September, the U.S. Department of the Interior announced two new rules intended to help improve drilling safety by strengthening requirements for certain equipment, well control systems and blowout prevention practices.

The rules are also supposed to improve workplace safety by reducing the risk of human error. “These new rules and the aggressive reform agenda we have undertaken are raising the bar for the oil and gas industry’s safety and environmental practices on the Outer Continental Shelf,” said Secretary of the Interior Ken Salazar.

Under the new “Drilling Safety Rule,” operators will need to comply with tougher requirements for everything from well design and cementing practices to blowout preventers and employee training. Additionally, the “Workplace Safety Rule” requires offshore operators to have clear programs in place to identify potential hazards when they drill; clear protocol for addressing those hazards; and strong procedures and risk-reduction strategies for all phases of activity, from well design and construction to operation, maintenance and decommissioning.

Citing the federal government’s refusal to offer proper notice and accept public comments on the new rules, U.S. District Judge Martin Feldman of New Orleans overturned the safety measures on Oct. 19. His decision was related to a lawsuit challenging the moratorium, Bloomberg News reported. On Nov. 3, Feldman, the same judge who overturned the deepwater drilling moratorium in June — prompting the Obama administration to issue a new one in July, that also faced a legal challenge in Feldman’s court — is scheduled to hold a hearing on dismissing the lawsuit and related decision altogether.

Bureau of Ocean Energy Management, Regulation and Enforcement Director Michael R. Bromwich said that before deepwater drilling will actually resume in the Gulf, his agency intends to conduct inspections of rigs for compliance. Further rulemaking and more safety measures are expected from BOEM in the near future — and those actions may take into consideration any information that comes from the ongoing investigations into the Deepwater Horizon oil spill, Bromwich said.

Don Briggs, president of the Louisiana Oil and Gas Association, said the local arm of the industry is ready to get back to work and the overwhelming majority wants a renewed focus on safety.

The Obama administration must also find ways to get more shallow-water permits through the process, he said, which were not targeted by the recent moratorium but are at record lows. “The offshore industry welcomes these new rules to raise security standards and improve workplace safety in the Gulf of Mexico,” Briggs said.

“Companies stand ready to meet the requirements of these new rules, but BOEM must provide an adequate process for industry to attain permits necessary to restart their drilling operations.”

There’s also the human angle — meaning those who actually work on the rigs; in many respects, they want safety reforms just as much, if not more so, than anyone else. Gary Beevers, international vice president of the Texas-based United Steelworkers, said the federal government needs adequate time to do its inspections and ensure that proper health and safety provisions are in place.

Moreover, the industry should be helping the government ensure that all the rigs are safe to operate, he says. “We want drilling to return to the Gulf just like everyone else in the industry, but we have to make sure these rigs are safe first,” Beevers adds. “We don’t need another oil explosion and oil spill.”

A CLOSER LOOK

In response to the Deepwater Horizon oil spill in the Gulf of Mexico, the administration of President Barack Obama implemented a number of aggressive and controversial reforms for offshore oil and gas exploration. Those regulatory changes are being carried out by the Department of Interior’s Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEM.

Here’s a look at what’s in and what’s out:

In: BOEM is conducting comprehensive new environmental analyses of the Gulf of Mexico and the Arctic to help inform future leasing and development decisions.

In: Proposed lease sales and drilling projects must undergo thorough environmental reviews in accordance with National Environmental Policy Act.

Out: Interior closed the loophole, established in 2003, that exempted operators in the Gulf of Mexico from submitting plans for worst-case discharge scenarios.

Out: The Administration has submitted legislation to remove the requirement that hamstrings BOEM by requiring review and approval of exploration plans within 30-days.

In: Permit applications for drilling projects must meet new standards for well-design, casing, and cementing, which must be independently certified by a professional engineer.

In: Proposed exploration plans must meet new requirements to show the operator is prepared to deal with a potential blowout and the potential worst-case discharge scenario and the operator’s ability to respond to such a discharge.

Out: Over the last three decades, safety equipment and regulatory requirements fell behind the technology that allowed companies to reach new oil and gas reserves in deeper waters.

In: Operators must adhere to the new “Drilling Safety Rule,” implemented through emergency rulemaking, that raises the standards for blowout preventers, well design, casing, cementing and safety equipment. Blowout preventers must also meet new standards for testing and must be independently certified.

In: Under the new “Workplace Safety Rule,” operators will be required to develop a comprehensive management program for identifying, addressing and managing operational safety and environmental hazards and impacts, with the goal of reducing the risk of human error and improving workplace safety and environmental protection.

In: The CEOs of drilling companies must – for the first time ever – put their signature on the line to certify that their rigs comply with all safety and environmental laws and regulations.

Out: The Royalty in Kind program, which accepted oil and gas in lieu of cash as royalty payments on federal energy resources.

Original Article