Squeezed by lower natural gas prices and escalating capital costs, U.S.-based exploration and production (E&P) companies likely will maintain their current level of spending or slightly pull back in 2007, energy analysts said last week.

A decline in capital spending has been foreshadowed by energy executives in third quarter earnings calls in the past couple of weeks, with reports that higher costs are cutting into profits (see related story). Some producers, including EnCana Corp., cut back on 2007 production plans, while Cabot Oil & Gas Corp., Chesapeake Energy Corp. and Questar Exploration & Production Co., shut in some gas because of low prices and high storage levels (see NGI, Oct. 30).

Standard & Poor’s Ratings Service credit analyst Paul B. Harvey noted the “softening commodity prices for oil and natural gas, especially natural gas, have decreased nearly 60% from the start of 2006, and could pressure credit quality. High-yield E&P companies, which typically have high cost structures, limited liquidity, and are often weighted to natural gas, could be at risk if the trend is prolonged.”

Harvey said, “In general, the E&P industry environment appears solid, although not as robust as many participants had planned at the beginning of 2006.” The result could be reduced spending in 2007, if commodity prices continue to show softness. However, given the smaller reservoir sizes and projected demand growth, many companies view the longer-term outlook as favorable.

In an Energy Industry Brief, Raymond James energy analysts J. Marshall Adkins, Wayne Andrews and Pavel Molchanov acknowledged there are questions about whether E&Ps will be able to continue to fund expansive exploration efforts next year. However, “E&P margins are compelling,” and the biggest constraints are a shortage of drilling rigs and skilled labor.

“Given current [finding and development] F&D costs at around $2.00/Mcfe, and under [Raymond James] long-term $10.00/Mcf gas forecast, we project that producers would be earning [internal rates of return] IRRs near 80%,” said the trio. “Even if gas were to drop to $6.00, and stay there permanently, we estimate IRRs at 30%.”

Contrary to the market perception that the average E&P is not fully funding its drilling capital, the average company is “actually generating free cash flow to fund acquisitions, stock buybacks or debt pay down. While some companies must borrow, most E&P balance sheets are perfectly capable of taking on some incremental leverage. All in all, the rumors of the drilling cycle’s untimely demise and calls for the end of the cycle have been greatly exaggerated.”

The average E&P “is not only fully funding its 2006 drilling budget, but is actually generating free cash flow above and beyond the drilling spending programs,” according to Raymond James analysts. For 2006, spending by the E&P companies covered by Raymond James represents 85% of projected operating cash flow. “The remaining 15% is free cash flow, available for acquisitions, debt reduction, dividends and/or stock buyback.”

Within Raymond James’ coverage portfolio, cash flow spent on drilling has declined from nearly 100% in 2002 to between 70-80% from 2003 through 2005. This year, the collapse in gas prices from the $10/Mcf level to below $7, combined with bullish spending programs planned in advance, caused the percentage of cash flow spent on drilling to rise to around 85%.

“Yes, this is slightly higher than it was over the past three years, but…for the past two decades, most E&P companies have consistently overspent their cash flow. We estimate that over the 1982-2002 period, spending by producers averaged 100% to 130% of their cash flows. Over the past four years, on the other hand, they have been under spending their cash flow.” Most E&Ps, noted the analysts, are not averse to borrowing if it helps to achieve growth.

The Raymond James analysts said some observers may be lumping acquisition spending and perhaps stock buybacks and debt pay down in the same category as drilling capital. “We do not agree with this approach because E&P companies view acquisitions as a growth driver that is incremental to drilling, not a substitute. Likewise, stock buybacks are effectively dividends of cash back to shareholders, not investments in production growth…”

Even though F&D costs are higher, gas prices have increased even more.

The “soaring demand for rigs and other services has obviously enabled oil service companies to gradually push through cost increases,” while the size of incremental reserve bookings from new field discoveries has been diminishing.” Raymond James’ E&P’s have seen a 35% increase in average F&D costs over the previous three years, to $1.87/Mcfe in 2005 from $1.39 in 2002. “Clearly, favorable gas prices have more than offset the rise in costs, implying that producers should be boosting capital spending in this widening margin environment.”

A more cautious approach is expected by energy analyst John Gerdes of SunTrust Robinson Humphrey/The Gerdes Group (STRH).

“Over the past couple years, the E&P industry has been assaulted by massive cost increases,” Gerdes said. “Moreover, cost pressures haven’t been limited to capital expenditures associated with drilling and completing wells, but also include material increases in operating, production and overhead expense.” Gerdes said the “capital intensity,” i.e., the cost to find and develop reserves, of STRH’s coverage portfolio has increased almost 100% since 2004. Meanwhile, per-unit cash expenses rose about 20% in 2005 and are expected to increase another 5-10% this year.

“As a consequence of massive cost increases, the median capital intensity of our E&P coverage is now about $3.20/Mcfe. In other words, the median company in our coverage portfolio requires $3.20 of capital to bring on one Mcfe of production.” Add to that operating and overhead expenses, estimated at around $2.00/Mcfe of production, pre-interest/tax costs average $5.20/Mcfe, said Gerdes. “Importantly for the outlook for E&P capital spending, a $5.20/Mcfe median cost structure likely implies certain projects require less than $4.00 to generate a cash-on-cash return.”

STRH’s base case price expectations in 2007 forecast gas prices at the “higher” end of $7/Mcf and the low $60’s/bbl. If the price forecast holds, capital expenditures “should exceed cash generation by about 12%.” STRH’s 2007 E&P capital spending outlook anticipates drilling activity roughly comparable to current levels, except for a few “notable” exceptions in its coverage group, which include Chesapeake Energy Corp., EOG Resources and Southwestern Energy Corp. Those three companies “should experience further advances in the Barnett Shale and Fayetteville Shale.”

Oilfield service pricing in 2007 is “essentially static” relative to current market conditions, said Gerdes. “Notably, our expectation of stabilizing E&P capital spending over the next year largely reconciles with initial indications from E&P companies, as managements tend to budget capital outlays within plus/minus 10% of cash generation.”

Commodity prices next year are “unlikely to be robust enough to suggest that capital spending will significantly exceed current levels,” said Gerdes. “Moreover, an inability to generate free cash flow even in a fairly robust commodity price environment is a clear indication of the significant cost pressure (and elevated cost structure) the E&P industry has endured the past two years.”

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