Last Updated Nov 3, 2010 1:39 PM EDT
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.
Chief executive Randy 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 300Â°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!
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.