Despite lower drilling activity levels and service costs in 2002, exploration and production (E&P) costs rose for the third straight year, mostly because of the lack of easily exploitable prospects, CreditSights analysts reported.
This year, as producers ramp up drilling activity to combat rapidly falling natural gas inventories, service costs again will move higher, pushing up overall costs yet again. Brian M. Gibbons Jr. and Andy Devries, analysts with CreditSights, noted that while escalation of costs appeared to slow in 2002, finding and development (F&D) costs from all sources increased 13% to $1.46/Mcfe in 2002, up from $1.04 in 2001, with a three-year average of $1.26.
Using the cost structures for 16 North American-focused independents, which work predominantly in the United States, the analysts used recently reported company estimates to gain an understanding of 2002 trends ahead of more formal data to be released in Securities and Exchange Commission 10-Ks. Once the 10-Ks are published, CreditSights plans to formalize the study, but analysts said the preliminary outlook “should serve as a good proxy for what to expect.”
Preliminary conclusions show that three-year F&D costs from the drill-bit (excluding acquisitions) increased to $1.58/Mcfe in 2002 from $1.41/Mcfe in 2001, a 12% increase, but well below the 40% increase in 2001 over 2000. F&D costs from all sources increased 13% to $1.46/Mcfe in 2002 bringing the three-year average to $1.26/Mcfe, up from $1.04/Mcfe in 2001. Production costs for the industry rose 4% to $0.82/Mcfe in 2002 for a three-year average cost of $0.77/Mcfe, up from $0.68/Mcfe in 2001.
Gibbons and Devries believe several factors contributed to reserves and production values differing, mostly because of proximity to the end-market (transportation costs), the amount and quality of the oil or gas, and the costs to find, develop, and produce, which are driven by geology and technology.
“Our goal is to evaluate the long-term sustainability of companies whose asset base is inherently a depleting resource,” said analysts. “We analyze whether companies can increase reserves, make new discoveries, re-invest capital efficiently and control cost structures. Capital spending trends play a large role in the analysis, providing signs of shifts in absolute changes, geographic breakdown, exploration versus development, and drill-bit versus acquisition changes.
Company data in aggregate also provides insight into how the industry as a whole is performing; whether supplies increasing or decreasing; changing sources of (conventional vs. unconventional; Rockies vs. Texas; oil vs. natural gas); and the question of drilling new reserves vs. making acquisitions.
CreditSights analyzed costs on a per-unit basis ($/bbl, or $/MMcf), to compare companies on an “apples-to-apples basis,” as well as take into account both the level of spending (oilfield service costs) and the amount of reserves being discovered, or produced (F&D or production costs). Analysts also evaluated reserve replacement (new reserves/production) trends and reserve life (total reserves/production) to understand the sustainability of each company, or the ability to replenish the asset base.
The analysts used the metrics on an absolute and relative basis to gain a perspective of how each company’s business is performing versus its own historical standards and versus the industry’s performance. “We look at one-year costs to gain a perspective of the each business performed in the period, but we rely more heavily on longer-dated, three- and five-year analysis, given the long lead times of oil and gas projects. The time between initial capital investment in the exploration stage and revenues associated with first production can be several years.”
Not all of the companies in CreditSights’ analysis reported a breakdown in F&D costs such as drilling and acquisition components. So, to evaluate the companies accurately, CreditSights evaluated two sets of data that have different companies and sample sizes.
“In general, most companies announce or report an estimate of expected F&D costs from all sources, however few companies provide the detail behind the cost calculation,” said analysts. “This means we have been able to assemble a good sample of companies to form a basis of opinion on all-in F&D costs, but that we have a smaller sample and therefore less reliable set of data for F&D drilling-only costs. Another caveat is that our industry average calculations are calculated on a simple basis since reserve data for most of the universe is not yet available. We believe the trend in the data points is more important than the absolute level.”
According to CreditSights, F&D leaders in 2002 were Pioneer Natural Resources, at $0.94/Mcfe; Burlington Resources, at $1.03/Mcfe; and EOG at $1.09/Mcfe. Burlington (at $1.07/Mcfe) and Pioneer (at $1.13/Mcfe) also led the way on three-year average performance, said CreditSights. Ocean Energy, which plans to merge with Devon Energy, placed third at $1.15/Mcfe “despite one of the highest one-year 2002 rates in the group, $2.07/Mcfe.” Meanwhile, CreditSights noted that Devon continued to struggle with high costs in 2002, posting yearly and three-year average F&D costs of $2.16/Mcfe and $2.00/Mcfe, respectively.
F&D costs from all sources in 2002 increased 13% to $1.46/Mcfe, bringing the three-year average to $1.26/Mcfe from $1.04/Mcfe in 2001. Occidental ($.74/Mcfe), XTO ($.77) and Pioneer ($1.05) led the industry for lowest one-year costs in 2002 and lowest three-year average costs for the three-year. “Industry laggards were Unocal, Forest Oil and Newfield Exploration on a yearly and three-year average basis,” said analysts.
Using Depletion, Depreciation and Amortization (DD&A) costs, the industry saw a 3% increase to $1.10/Mcfe in 2002, with the three-year average at $1.04/Mcfe, up from $0.93/Mcfe in 2001. Using these costs, Burlington, Pioneer and Anadarko Petroleum Corp. were the low-cost leaders last year and for the three-year period.
“It is interesting to note that the yearly and three-year rankings are nearly identical with the exception of Chesapeake,” said analysts. Gibbons and Devries said the costs should serve as a proxy for DD&A rates, “as they represent the book value of oil and gas reserves sold…they are theoretically the long-term F&D cost of the company. Companies with the lowest DD&A rates have had the lowest F&D costs in the industry over long periods of time. ”
Last year, production costs rose 4% to $.82/Mcfe, for a three-year average cost of $.77/Mcfe, up from $.68 in 2001. Leaders in 2002 were EOG, $0.63; Newfield Exploration, $0.70; and Chesapeake, $0.71, with the U.S. gas-levered EOG ($.61) and Chesapeake ($.65) also three-year leaders. “Burlington showed the greatest increase as costs escalated to $0.97/Mcfe from $0.64/Mcfe in 2001. Devon posted the most impressive cost improvement pushing production costs down 12% to $0.79/Mcfe from $0.90/Mcfe in 2001.
Reserve replacement rates (including acquisitions and divestitures) on a three-year average through 2002 were 240% for the industry, led by Anadarko at 465%, Chesapeake 303%, and Occidental 286%. Last year was the lowest replacement year for the past three years at 160% versus a high of 294% in drilling-intensive 2000. “Again, because of the small sample size and the simple average nature of the industry average, we caution against reading to deeply into the absolute numbers but rather a focus on the trends. Devon, Ocean and Burlington showed the weakest all-in reserve replacement rates. ”
Reserve life for the industry improved for the second straight year to 11.3 years, up from 11.0 in 2001 and 10.6 in 2000. “Pioneer continued to lead the pack in 2002 with a 17.8-year reserve life on account of several recent-year discoveries that have been in development (booked reserves not yet producing). Burlington and Chesapeake round out the top three at 12.3 and 12.1-year reserve lives while Devon and Newfield bring up the rear at 8.6 and 6.5 years.”
For more information on the study, visit www.creditsights.com.
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