The latest data on finding and development costs for 2004 will not be in for some time, but this much we do know: they are trending up. Dayrates for drilling rigs rose as much as 15% last year and are estimated to go up almost as much in 2005. Pricing power for drilling mud, fracture stimulation and other goods and services boosted service companies last year, but producers had to reach deeper into their pockets. No doubt about it, F&D costs have risen during the past five years, especially in the past two. Luckily, commodity prices have gone up even more, so margins are preserved. Still, monitoring F&D costs is a constant job. Evidence of cost creep abounds. Dramatic jumps in steel costs occurred throughout 2004 as shortages developed and worldwide demand rose. That and the rising U.S. rig count gave Lone Star Steel, a unit of Lone Star Technologies, strong financial results. The Dallas-based company's revenue from oil country tubular goods (OCTG) went up 50% in first-quarter 2004 and rose another 37% in the second quarter-about half from higher sales volume and half from increased prices. Lone Star's average raw-material cost of steel climbed again in the third quarter-by 20%. Pipe Logix, a monthly newsletter published by Tulsa's Spears & Associates, reports that OCTG prices rose 73% from January through early December 2004. Land-rig contract dayrates rose slightly during the year's first three quarters, about 10%, but they began increasing more rapidly in the fourth quarter, so the year will end up with growth of between 10% and 15%, vice president Richard Spears says. Service companies such as Halliburton, Schlumberger and Baker Hughes announced book or listed price increases in 2004, but the real question is, what are they actually charging in the field? Demand for fracture or pressure-pumping jobs has escalated on the heels of increased well activity in the tight-gas Barnett Shale, Pinedale Anticline and north Louisiana plays. "Despite almost full utilization of frac crews for the entire year, frac prices in the U.S. remained fairly well flat into the third quarter," he says. "Increases at the field are now being instituted, so we expect average frac prices to be up 10% to 20% for the year." Higher costs are a continuing challenge for operators. John S. Herold Inc. and Harrison Lovegrove & Co. tracked these in their "Global Upstream Performance Review 2004." The study found that U.S. F&D costs nearly doubled from 1999 to 2003, from $4.93 per barrel of oil equivalent (BOE) to $9.69 in 2003. Costs have risen faster recently. The three-year average was $9.51, up significantly compared with the longer-term five-year average of $7.83. The trend was much the same worldwide. JPMorgan's analysis of 24 E&P companies' results found that 2003 drillbit finding costs went up about 10%. "Future development costs per unit of proved undeveloped (PUD) reserves have continued to increase steadily, further evidence of basin maturity and a shortage of quality inventory," says analyst Shannon Nome. "This suggests producers are finding it difficult to replace PUDs with locations that are equally or more economic than the ones they are currently developing." F&D costs are a function of dollars spent versus reserves booked, but other factors come into play, such as timing from a fiscal year-end to the start of the next year, the type of geology that leads to many or few offset locations, cost-reduction initiatives, and conservative or aggressive booking practices. Few can hope to match Ultra Petroleum's industry-leading F&D of 29 cents per thousand cubic feet equivalent (Mcfe), achieved in 2003 when it grew its proved reserves 50% by drilling in Wyoming. Many of the E&P companies active in so-called gas manufacturing or resource plays-XTO Energy, Quicksilver Resources, Southwestern Energy and Patina Oil & Gas, for example-report lower F&D costs than their peers. Drilling in a variety of play types onshore and offshore-not to mention in deepwater or abroad, where costs are higher-increases F&D. Gulf of Mexico-focused Spinnaker Resources and Stone Energy have higher F&D costs than landlocked peers. But peer comparisons can be misleading in a number of ways, and one-year statistics are unreliable given the long lead times in reserve bookings. "That's why we use a three-year average F&D number [when comparing peers]. It's not fair to have a one-hit wonder, or some acquisition that drives finding costs down to 10 cents an Mcfe," says Greg Kerley, chief financial officer of Southwestern Energy Corp. in Houston. "A snapshot in time is not accurate," echoes Brian Jennings, CFO of Devon Energy Corp. in Oklahoma City. "Timing is a key issue. If you drill a well this year and find reserves, you may book them. In the second year, you come back and put a wellhead on it, connect the pipe and start producing. So, in the first year you spend money and book reserves, but in the second year, you just spend money without booking new reserves for that well, so your second year F&D looks like a disaster." PUDs in the denominator A producer can tackle F&D costs any number of ways, in the numerator (costs incurred) or in the denominator (reserve additions). But as finds become smaller in a maturing North American resource base, especially onshore, the F&D cost goes up accordingly. It stands to reason that if a company finds half the reserves it found before, but spends the same number of dollars, then F&D rises. Reserve revisions can alter the equation, too. Shell Oil saw its F&D numbers go up in 2004 after it "de-booked" a significant amount of reserves. Evaluate Energy, a London data and research firm, reports that before the reserves were revised downward, Shell's F&D averaged $3.98 per barrel of oil equivalent from 1996 to 2002. Now that Shell has fewer proved BOEs in the denominator, its F&D average has been recalculated to be $6.31 per BOE, well above that of its peers among the majors. It doesn't necessarily mean that suddenly Shell is paying more per foot to drill a well. Analysts agree an F&D number is not a reliable gauge, yet it remains one they and investors use often to compare companies' performances. Making-and booking-a big discovery certainly improves the unit-cost equation overnight, but this is not something a company can do on command. It typically happens only after years of work and millions of dollars invested. This is particularly true for expensive wildcatting in offshore or international plays. Devon Energy knows this all too well, as in 2003 it had a lot of PUDs to develop that came with its recent multi-billion-dollar acquisition spree. Last year, analysts criticized the company for posting a 2003 F&D cost near $15 per BOE, well above its peer average. Part of the reason was its acquisition of Ocean Energy, which had nearly 40% PUDs versus Devon's average of about 20%. What's more, Ocean's undeveloped assets were mostly in deep water and will be costly to delineate and develop, compared with Devon's legacy onshore North American assets, such as in the low-cost San Juan Basin. "Devon took a lot of heat on our drillbit F&D in 2003," says Jennings. "But most companies in the industry are increasing their PUD percentage and ours has actually gone down. You'll see a marked improvement in our F&D number for 2004, down to between $9 and $11 per BOE-we are very confident we'll be in that range." Several deepwater finds Devon made in 2003 and 2004 have not yet been booked. The $60-million, ultradeep Jack well in the Gulf of Mexico, for which Devon's share of costs was $30 million, showed up in 2003 expenditures. But the reserves that were found there won't be booked until 2005, Jennings says. The companies first need to further delineate the reservoir with more drilling, and then the partners will be able to decide on the appropriate production scheme, which in turn will affect costs in the numerator. Brad Beago, E&P analyst with Calyon Securities (USA) Inc. in Houston, says, "If you tell me a company has F&D of a $1.50, that tells me nothing. If they are in South Louisiana, that's a great F&D. If they're in coalbed methane, that's probably twice the F&D of their neighbors." The percentage of PUDs a company has-and their location-makes a big difference, Beago adds. Companies active in the big resource plays like coalbed methane and other Rockies plays-where low reservoir risk means many locations can be inferred from a few wells drilled-enjoy a high percentage of PUD locations they can book. Other companies may have spent the same amount of drilling money in a given year, but not booked as many reserves, depending on where they drilled. EOG Resources, for example, spent a lot of new capital in the Barnett Shale play in North Texas in 2003, but it didn't book those reserves until the end of 2004-this will artificially lower its F&D costs for 2004 as more reserves get spread out over the costs. Small-cap Gasco Energy is getting started in the Uinta Basin, Beago adds. "For every well it drills, it can book as many as eight offset locations. So, they spend, say, $1 million to find 1 billion cubic feet equivalent (Bcfe), for a finding cost of a dollar an Mcfe. But then they book eight PUD locations, so now they have 9 Bcfe vs. $1 million of cost, for a finding cost of 15 cents an Mcfe." Managing costs The technical steps to take and products and services to use that minimize cycle times and reduce costs are fairly well known. But consultants say a company's people are what matter most, for it is people who must accept that there is a problem, accept change, implement the technology properly and watch for cost creep. So many people in the industry today are seasoned veterans who are likely to have the "not invented here" attitude, or they question why any change is necessary. "People are more comfortable talking about technology than about employee behaviors, and they have a bias to think technology is all that is needed for improving performance," says Charles Cable, a vice president in the energy practice for management consultant Celerant. Cable was on a team that helped Shell reduce its drilling and development costs in the Gulf of Mexico by a significant amount, starting from 2001. The firm studied best practices and developed team planning with the vendors and service providers in a cooperative, not adversarial, model. Record run times with less downtime were achieved, chemical costs were reduced 40% and other costs reductions occurred in maintenance and air logistics. Celerant targeted "flat time" or drilling delays when the bit isn't turning. "As companies work in increasingly challenging environments, the cost becomes more important, so any down time is expensive," Cable says. "An offshore rig will typically be down 15% to 30% with nonproductive things like tripping out of the hole, logistics delays or equipment failures. And part of the cost is the 'invisible lost time' when the rig is operating, but the progress is much slower than the optimum performance has been in the past. "You need to measure against that and understand why you aren't achieving your best performance. Nobody achieves perfection, but the more you understand, the better you get at deploying technology properly." Celerant measures variances to best practices and learns why they occur so they can be minimized. In one case, several drilling teams working in the same office had different results. One team leader new to the company was able to bring new ideas into the mix such that his team reduced the cycle time by about 20%, while the other teams had static performance. Celerant helped the other teams learn from the best and then, institutionalize the new processes so that better performance could be repeated. But industry also has to watch out for what Cable calls the hero syndrome: "People who tackle problems and symptoms and effect change get all the attention, and the people who prevent problems in the first place don't. We need to change that." Companies may not think it is as vital to look at costs during a time when high oil and gas prices create wider profit margins. But when the sun is shining is precisely the right time to inspect and repair the roof. That's why enterprise-wide cost reductions are important, says Omar Aguilar, a principal in strategy and operations consulting for Deloitte & Touche. "Some companies are addressing institutional or holistic, structural costs now, and looking for inefficiencies, especially from prior mergers, acquisitions or divestitures," he says. "Our view is that some of the overall cost reduction needs to be done for strategic purposes and not just to reduce costs in a targeted area, because otherwise, the impact of the reduction is minimal or not sustainable," Aguilar says. "Sometimes you need to rethink your objectives and paint this more strategically and not just tactically." Denver's Evergreen Resources, now a part of Pioneer Natural Resources, always ranked among the best of its peer group in having low F&D costs. Last year it drilled close to 200 wells in the Raton Basin coalbed-methane play, where costs tend to be lower and are spread out over a lot of long-life reserves. But Evergreen was unique in that it did things differently, controlling more than just the acreage in order to control costs. Says former chief financial officer Kevin Collins, "We did as much of the service work as we could, for quality control and to keep costs lower. We had our own frac trucks and completion rigs, and decent reserves per well. We owned the compression and gathering lines too." Many E&P companies control F&D costs if they are developing a good field with many wells to drill, where economies of scale are possible, as opposed to drilling a few wells here and a few there, each requiring various depths of drill pipe, types of drilling mud, fracs and so on. The more wells in a focused area, the better chance of negotiating favorable rig contracts and other discounted services. Kerley at Southwestern Energy says, "The industry expects costs in 2004 to come in about 20% higher than 2003 levels based on what we're hearing, but we feel we've done a good job in controlling our F&D costs." At the company's star asset, the gas-rich Overton Field in East Texas, it drilled 84 wells in 2004, up from 57 the year before. Kerley figures the average well costs about $1.5 million to drill and complete and grosses 1.8 Bcfe, for a finding cost of about $1 per Mcfe. If natural gas prices are $5 per Mcf, the company sees another 120 unbooked locations still to be drilled at Overton. These meet the company's standard goal of creating $1.30 of present value for every dollar invested. MAPLE LEAF F&D With 2004 nearly over, FirstEnergy Capital Corp. released a study of estimated Canadian finding and development costs. Looking at historical expenditures and reserve addition data, the Calgary investment-banking firm found that the trend is pointing up. "We see that F&D costs (excluding in the oil sands) in the Western Canadian Sedimentary Basin have been increasing, as every Canadian E&P company could easily confirm," analyst Steven Paget says. He calculates that 2004 capex will end up being C$23.3 billion, excluding acquisitions. From 2000 to 2003, reserve additions in the basin have been trending between 1.2- and 1.4 billion barrels of oil equivalent (BOE) per year, so for 2004, he assumed reserve adds of 1.45- to 1.5 billion BOE-a higher number because producers have drilled more wells in 2004 than they did in prior years. However, Paget also assumed E&P companies are finding fewer reserves per well than in previous years. On that basis, he assumed reserves found per well in 2004 dropped to 62,000 BOE from an average 73,000 recorded between 2001 and 2003. "We thus believe that 2004 F&D costs in the WCSB will be C$16.11 per BOE, a 20% increase from 2003. We also estimate that F&D costs will only slightly increase from 2004 to 2005, at C$17.01 per BOE. "There remains little room for companies to underperform on costs," he concludes. Meanwhile, last November, consultant Ziff Energy Group recognized Burlington Resources Canada, Devon Canada and Real Resources for having the lowest F&D costs in the basin. Ziff made its 5th annual Canadian Upstream Achievement Awards based on these three companies "effectively replacing ongoing reserves in a specific strategy area over a three-year period, at a cost below the competitor average and below the net present value target." Burlington was chosen based on its drilling for central Alberta gas, Devon was chosen for drilling Foothills Deep gas and Real was pursuing shallow gas in southern Alberta.

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