Sharply lower natural gas prices in 2012 from 2011, used under required 12-month average price tests, resulted in significant negative revisions for many domestic gas- and liquids-weighted producers, rendering some current projects uneconomic and pushing a boat load of proved undeveloped reserves (PUD) out of the five-year development window, according to an analysis by Fitch Ratings.
The Securities and Exchange Commission (SEC) requires domestic exploration and production (E&P) companies to use the 12-month test, which was about $2.76/Mcf in 2012 versus $4.12 in 2011. The commission also mandates that PUDs be developed within five years or be deleted from an operator’s reserves numbers.
Fitch analyst Mark C. Sadeghian led a team to explore the full-cycle costs for a sample of domestic explorers to determine what actually happened last year after the mandated revisions were stripped away. Full-cycle costs include the cash costs/boe, which include lease operating expenses, production taxes, transportation expense, general/administrative/interest expenses to produce, and the three-year all-source finding and development (F&D) costs/boe.
Analysts reviewed E&P full-cycle costs between 2007 through 2012, and zeroed in on how 2012 played out versus 2011 to see what has happened since SEC’s price mandates were enacted in 2010 (see NGI, Jan. 25, 2010). The 2012 revisions numbers were higher than in 2011, but a review of the full-cycle costs were “critical” because “adjustments for prices tell a different story,” Sadeghian said.
The U.S. producers sampled were more than 60% weighted to either natural gas or liquids. Fitch also sampled “balanced” operators with an even mix of production.
Seventeen of the operators sampled reported negative gas-based price revisions in 2012. Among the most prominent were Chesapeake Energy Corp., 5.41 Tcfe on prices and reserve reductions in the Barnett and Haynesville shales; Southwestern Energy Co., 2.09 Tcfe on lower prices and a 2.12 Tcf reduction in Fayetteville Shale reserves; Quicksilver Resources Inc., 1.2 Tcfe from Barnett revisions; Devon Energy Corp., 930 Bcf, with 100 million boe linked to the Barnett and 25 million boe to the Rocky Mountains; Linn Energy LLC, 803 Bcfe in price revisions; and Newfield Exploration Corp., 615 Bcfe mostly on revisions in the Arkoma Woodford Shale.
Operational metrics evaluate the “long-run credit quality,” and the “full-cycle costs are among the most important of these metrics, as they indicate a company’s position relative to its peers and serve as a broader proxy for changes in marginal costs in the industry,” said Sadeghian. Companies with “significant” gas-linked price revisions also included Forest Oil Corp., Apache Corp., Occidental Petroleum Corp., Pioneer Natural Gas Co. and SandRidge Energy Inc.
After stripping out the negative gas-based price revisions, the rise in full-cycle costs was “blunted” across the samples, Sadeghian said. “Unsurprisingly, the largest difference between unadjusted and adjusted full-cycle prices in 2012 occurred for gas-weighted companies (minus $5.34/boe difference) followed by balanced-portfolio (minus $2.23/boe) and liquids-heavy companies (minus 69 cents/boe).”
On an adjusted basis, the full-cycle costs in 2012 were moderately higher, according to Fitch. Median costs for the group increased by 7.5% year/year to $44.91/boe from $41.76. By group, gas-weighted producers had the smallest increase, up 1.3% to $31.44/boe in 2012 from $31.00, while liquid-weighted names climbed 3.3% to $44.91 from $43.47. The largest increase in costs was among balanced-portfolio companies, whose median rose by 11.3%, to $51.59/boe in 2012 from $46.34.
Determining the impact of infrastructure spending and other long-term spending on full-cycle costs is “harder to gauge,” said Sadeghian. “Ramped-up investments in less-developed shale plays and long-lead time projects can increase F&D and full-cycle costs because of lags between project investment and ultimate reserve bookings. The uptick in such investments across the sample appears to have inflated 2012 full-cycle costs, even after stripping out gas price effects.
“This is supported by the fact median F&D saw the largest price increase of any cost component in the full-cycle calculation, despite strong efficiency gains in drilling and services, particularly in onshore shale plays.”
Fitch’s analysis made no adjustments for factors that also may have affected the 2012 full-cycle costs, including one-off impacts from asset sales or land acquisitions, adjustments for the changing production mix to liquids from dry gas development, or for longer-term changes in drilling programs.
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