I have heard people say, ‘Looks like a good prospect. Too bad we have to drill it.’
— Andrew Oram, vice president and senior credit officer at Moody’s Investors Service
A multitude of factors, both geological and economic, point toward a peak in the world’s oil supply by 2015. Today’s sermon focuses on sharply rising upstream finding and development (F&D) capital costs that jeopardize ongoing and future oil projects. It does not appear, as most economists believe, that higher oil prices and Adam Smith’s invisible hand will bring forth abundant new oil supplies to meet rising demand, as happened in the North Sea and Prudhoe Bay in the 1980’s. Inflation is hampering the global oil industry’s ability to ease a tight market that has little spare capacity.
High Oil-Field Costs Crimp Search for New Supplies (Wall Street Journal, August 1, 2007) explains how inflated capital costs are impeding new oil & gas developments.
But during the current four-year rise in oil prices, inflation for equipment, labor and other crucial oil-field needs has largely kept up with the rise in oil prices. In recent quarters, this has crimped results at the world’s oil producers, including Western majors such as Exxon Mobil Corp. as well as the world’s biggest state-run oil companies, and has also led to delays and cancellations of major projects. While plenty of activity remains in place, the high prices are nibbling away at other projects that were expected to bring significant new supplies of oil and natural gas to the world.
“Supply is going no place, and demand is rising 2.5% to 3% a year,” says economist Philip Verleger Jr. of Aspen, Colo.
Last February, CERA/IHS announced the Upstream Capital Costs Index (UCCI), which tracks finding and development cost trends in 28 oil & gas projects over time. Starting in 2005, costs had risen 53% due to escalating prices for drilling rigs, offshore installation vessels, equipment (compressors, generators), shipyards, fabrication and qualified personnel. Producers facing dramatically higher capital costs (Oil & Gas Journal, February 19, 2007) states that deepwater project costs rose 15% in the 2 quarters prior to the index’s release because of “[higher] rig rates, technology limits, and skills requirements.” An update in May, 2007, reports that “the dramatic cost surge in the oil and gas industry continues, but the rate of growth shows some signs of slowing” (graph left). The index stood at 179, meaning that project costs have risen 79% since 2000. The annualized inflation rate is 14%.
Even before costs starting soaring in 2005, the per-barrel cost for new oil was increasing. The Oil & Gas Journal (May, 9, 2005) cited a Banc of America Securities study which looked at 12 major international oil companies. The “fully loaded finding and development cost rose to an all-time high of $9.55/boe in 2004 from $7/boe (barrel of oil equivalent) in 2003.” The increase was “primarily driven by a 50% drop in proven reserves added per successful well in the US and net negative reserve revisions.” The group’s 10-year average was put at $5.15/boe. A Lehman Brothers study found that “industry’s costs to find and develop oil in 2006 averaged about $20.40 a barrel, four times the $5 a barrel cost in 2001. As a result, the report said, incremental oil supply growth barely will be able to keep up with demand growth until 2011” (Wall Street Journal, op. cit.).
Upstream cost inflation as measured by the UCCI, which began in earnest in 2005, is a case of piling on — F&D costs have been rising steadily for several years now.
Geology and difficult physical environments are the primary drivers of per-barrel upstream F&D costs outside the Persian Gulf. Moody’s David Oran (link at the top) notes that “the deepwater Gulf of Mexico lower Tertiary deposits, unconventional resource plays and oil sands [are] sources of potential growth but with high price tags.” Other reasons for higher F&D costs include smaller field developments as measured by estimated recoverable reserves, and applications of enhanced oil recovery (EOR) in older producing fields. It is instructive to look at a successful recent development, the Tui field in the shallow water off New Zealand.
This field, like most offshore projects, will have a production profile1 similar to the one shown (graphic, above left). The production will ramp up quickly, peak for a short while, and then follow a long decline, with decline rates running 10-15% after the peak. The profile resembles the first derivative of an asymmetric Gompertz aging function, not the bell-shaped curve of the derivative of Hubbert’s logistic.
Tui is very small, with recoverable reserves of only 27.9 million barrels. Using a supertanker converted into a Floating Production, Storage and Offloading (FPSO) facility, production will quickly reach 50 thousand b/d before falling off. Nonetheless, at an assumed oil price of $60/barrel, and with Tapia Malaysian crude selling well above $70, Australian Worldwide Exploration Ltd. (AWE) expects its $700 million F&D costs to be paid off within 6 months of the first oil.
John S. Herold analyst Chris Ruppel tells us that projects like Tui are the exceptions to the rule (Bloomberg, July, 11).2
Assuming an oil and gas price equivalent to $60 a barrel, a search of published project costs and output data shows the next most economic developments [after Tui] pay for themselves in about six months, Ruppel said. These include BHP’s Shenzi, which is due to start pumping 100,000 barrels and 50 million cubic feet of gas a day in 2009, Statoil ASA’s $4.5 billion Gjoa field off Norway’s southwest coast and the $500 million Oooguruk venture being developed by Pioneer Natural Resources Co. and Eni SpA off Alaska.
Tui “is an interesting phenomena,” said Herold’s Ruppel. “Your typical offshore projects are more in the range of 10 to 15 years” to break even because of their high cost and decline rates, he said.
Production at Tui will dip to 10 thousand b/d within two years as the water cut increases. AWE beat the financial odds by ordering subsea pipes and the drilling rig in 2005, before the project was even officially approved. And although it sounds expensive, $700 million is not much money for offshore developments. Tui is a shallow water field (400 feet), so it did not have the higher costs of drilling out in the deeper water.
Typical larger offshore developments will not pay for themselves, according to Ruppel, until production is well into the tail-end of curve. With upfront capital costs rising sharply, combined with the high inherent costs of drilling deep offshore in geologically challenging reservoirs, it is easy to see that many projects may be delayed, postponed or canceled (Bloomberg, July 27).
Chevron postponed two Gulf of Mexico oil projects valued at $6.5 billion last month. At the Tahiti project, which had been scheduled to start output next year, shackles needed to connect the production platform to the seafloor were found to be faulty. A project called Jack was put on hold because of a shortage of drilling rigs.
A project called Jack! Only last fall the world was reassured3 that peak oil was a phantom menace because of successful oil flows from a record-setting appraisal well called “Jack #2” in the lower Tertiary of the Gulf of Mexico. Now, it’s an afterthought.
Why did oil industry capital costs rise sharply in 2005? CERA/IHS’s Richard Ward, who heads up the UCCI project, gives his interpretation in a video interview (Windows Media Player wmv file). Ward cites three reasons: 1) strong global economic growth, which creates competition for commodities (metals) or facilities (shipyards) used in the oil & gas industry; 2) the high oil price, which puts more projects on the table and therefore spurs intra-industry competition for equipment like drilling rigs; 3) inflated pricing from Engineering, Procurement & Construction (EPC) companies who are big asked to make longer commitments and so need to hedge their risks.
CERA/IHS expects inflation to moderate, and perhaps even level out in 2008. A supply-side response will redress equipment shortages, and projects will fall by the wayside due to the increased costs, thus reducing demand pressures within the oil & gas industry. A thorough knowledge of freshman year Economics 101 remains the chief qualification for carrying out analyses at CERA/IHS.
It probably has not escaped Ward’s attention—though he makes no comment about it—that part of the solution for industry inflation is to decrease the number of new projects coming on-stream, which can only decrease the future oil supply. In so far as the cure for industry inflation is a slowdown in upstream activity, whereas the initial goal was to accelerate upstream development to meet growing global oil demand, the situation presents a classic Catch-22.
Let’s contemplate the bigger picture. The graph (left) shows the IEA’s quarterly supply data since the beginning of 2005 and averaged totals since 2003. This data invites comparison with the UCC index (first graph, above). Capital costs inflation took off just after 2004, when the oil supply rose 3.3 million b/d, a 4.1% jump in a single year. After 2004, the oil supply grew only 1.9 million b/d in three years, a 2.3% overall increase. Liquids production has been in a bumpy plateau for 9 consecutive quarters through March of 2007.
Since the start of 2005, per-barrel F&D cost increases have easily outpaced the growth in the oil price. The inflation-adjusted oil price (2006 dollars) rose from an average of $47.97 in 2005 to about $61.60/barrel in the first half of 2007, according to Barclays (Wall Street Journal, op. cit.), an increase of about 32%. The UCCI data indicates a 79% increase in F&D capital costs in this period, which is in addition to geological and environmental reasons for steadily rising per-barrel costs since 2001. Unless the adjusted oil price keeps up with industry inflation, planned supply-side additions will continue to be vulnerable to postponement or outright cancellation.
To borrow an analogy from physics, it appears that the amount of work that must be done to increase supply jumped substantially after the world exhausted much of the readily available, last remaining, cheaper oil in 2004. Perhaps it is not too large a stretch to invoke an increase in entropy, where growing industry F&D costs provide an indirect “measure of the unavailability of a system’s energy to do work.” The oil supply will grow (or not) as some function of the actual work that gets done to maintain and increase it. Work ceases if rising costs make some oil uneconomical to produce, or the necessary drilling rig is unavailable.
Increasing “entropy” results in insufficient investment in the oil field maintenance required to partially offset the 8% natural declines in existing global production. (This is the estimated rate according to Schlumberger’s Andrew Gould.) Net declines are smaller—about 4%—only because investment in additional wells, infill or directional drilling, or EOR, boosts production flows. Diminished investment makes additions to the global oil supply from new projects concomitantly harder to come by, at least outside the Persian Gulf, where F&D costs are presumably still lower than elsewhere. About 1 million b/d of the 2004 increase came from Saudi Arabia, which has subsequently lowered production by an amount approximately equal to its higher 2004 output for reasons that are not clear.
“It [cost inflation] is another negative in an environment that has a lot of negatives already at work,” said Joseph Carson, chief economist at investment management firm Alliance Bernstein in New York (Wall Street Journal, op. cit.). It is hard to disagree. The economic argument often invoked to counter peak oil claims is that the high-price environment of the 1970’s and early 80’s “made a greater amount of untapped oil economical to pump.” The assumption is that what worked then will work now. This time around, from the vantage point of 2007, it appears to be a different story.
Notes
1. The NPC report (Supply Chapter, p. 26-27, Figure S3A-26) says that most oil fields, not just deepwater fields, have the production profile shown. They state “that managing the shape and duration of the production profile is a central issue not only in the peak oil debate but in all prospects for oil supply.” Indeed it is.
2. The same Bloomberg article breathlessly reports that —
First-year production from the 27.9 million-barrel Tui field will almost double New Zealand’s oil output. By late-2008, when the OMV AG-led Maari project 65 kilometers south of Tui is due to start producing, oil and condensate production will exceed 66,000 barrels a day, beating the previous record set in 1997.
But it is clear that peak flows are ephemeral, as the typical production profile above shows. How long will New Zealand’s production exceed 66 thousand b/d? A few weeks? A few months? Take Note: Many people who dismiss peak oil misunderstand this point. New oil fields are usually announced along with their peak flow rates, which gives the impression that oil production is always increasing and rapid, steep declines don’t happen.
3. Will wonders never cease? Real life is always better than fiction. To paraphrase Friedrich von Schiller— Against forgetfulness the gods themselves struggle in vain.
