DEEPWATER GULF OF MEXICO

At the mouth of the Mississippi River, 90 miles south of New Orleans, the muddy color of this mighty, snaking, ship-laden waterway quickly yields to shades of aquamarine, then deep blue, as the helicopter roars southeast, out past the nearby edge of the continental shelf-into the deepwater Gulf of Mexico. Some 50 miles farther, where water depths are more than 5,600 feet, Noble Drilling's semisubmersible rig, Max Smith, emerges like a dot on the vast expanse of the Gulf horizon. A decade ago, this semi likely would have been drilling on behalf of BP, Royal Dutch/Shell or ExxonMobil. But today, it's drilling on behalf of much smaller hydrocarbon hunters: Dominion Exploration & Production and Pioneer Natural Resources. This is hardly an isolated event these days in what was once the sole province of the giant oils. According to Steve Enger, integrated-oil analyst for Petrie Parkman & Co. in Denver, the majority of the current top-20 leaseholders in the deepwater Gulf of Mexico-in 1,000 feet of water or more-are either independents or domestic integrateds. (See table page 34.) What's caused this population shift? During the past 15 years, offshore technology, in terms of exploration, drilling and production, has improved rapidly and become widely disseminated throughout the industry. "For smaller operators, this has meant greater access to deeper-water prospects-for less cost," says Enger. Also, because of the deepwater-production infrastructure largely put in place by the top integrateds during the past few decades, it's now possible for lesser-sized integrateds and independents to develop smaller deepwater fields nearby, then tie them back to existing platforms and pipelines. In addition, a lot of companies like Kerr-McGee, Devon Energy and Amerada Hess recently have become larger via acquisition. "This means that, for their exploration prospects to remain relevant, their targets now must also be larger-and the bigger ones in the Gulf of Mexico tend not to be on the shelf, but in deep water," explains Enger. Gene Gillespie, senior energy analyst for Howard Weil in New Orleans, observes that offshore technology has now evolved to the point where independents can exploit a discovery of 100 million barrels of oil equivalent (BOE) in 3,000 or 4,000 feet of water and, at current oil and gas prices, make that a very profitable venture. "And as more infrastructure is built in deep water, such as floating spar production platforms, 20- to 40-million-BOE satellite fields can be commercially tied back to those host systems." Even the ultradeep offshore isn't out of the reach of independents. Gillespie points out that Ocean Energy has a 12.5% stake in the Unocal-operated Trident discovery, which is in 9,000 feet of water in the Alaminos Canyon in the western Gulf of Mexico. "The predrill reserve estimates on Trident are 300- to 800 million equivalent barrels, and it's likely this field will be the first candidate for a floating production, storage and offloading (FPSO) facility." Nearby, some of the supermajors-Royal Dutch/Shell, BP and ChevronTexaco-have the Great White and Toledo prospects, each with reserve potential of 500 million to 1 billion BOE. "If a joint development of those fields can be done, the economics for Unocal and Ocean Energy of bringing Trident onstream are going to substantially improve." Frederick P. Leuffer, senior managing director and senior energy analyst for Bear Stearns & Co. in New York, cites three key drivers behind the influx of independents and domestic integrateds into the deepwater Gulf of Mexico: technology, cost reductions and experience. "With the wide availability of advanced 3-D seismic data, it's now possible for smaller operators to interpret formations in and around salt layers, which cover most of the Gulf of Mexico. Also, tying back smaller deepwater finds to existing production facilities has brought down costs and shortened development time." In addition, independents are simply getting better at doing their job right, says Leuffer. "Take Kerr-McGee. The company has been drilling in the Gulf of Mexico since 1947, and today this operator-the largest producer and leaseholder in the deepwater Gulf of Mexico among independents-is looking at production growth there of 6% this year and more than 20% in 2003." Overall, which offshore operators are likely to reap the greatest hydrocarbon harvests from the deepwater Gulf? Among international integrateds, the three analysts pick BP. Says Enger, "During the next three to five years, it should add 500,000 equivalent barrels per day of production from this region to a current companywide base of 3.3 million BOE per day." Among large independents and domestic integrateds, the top analyst choices are Kerr-McGee and Murphy Oil. Says Leuffer, "During the past four years, each company has discovered, net to them, in excess of 150 million equivalent barrels in the deepwater Gulf of Mexico, and they're both looking at double-digit annual production gains for the next several years." Dominion E&P To understand why Kerr-McGee and Murphy Oil are making such a splash in the deepwater Gulf is to understand not only their story, but that of one of their common partners-Dominion Exploration & Production, the Houston-based upstream arm of integrated energy and utility giant Dominion Resources. "As many producers have seen the opportunity base on the Gulf of Mexico shelf continue to shrink, their natural progression has been into deeper water," says Duane Radtke, president and chief executive officer of Dominion Exploration & Production. "And with the improvements in offshore technology, as it relates to 3-D seismic, subsea completions, and spar production platforms, the economics of the deep water have changed dramatically versus 20 years ago. From a cost standpoint, it is now not only possible, but attractive for smaller operators to develop on a stand-alone basis deepwater fields down into the 40- to 60-million-BOE range." Dominion E&P's own foray into the deepwater Gulf of Mexico began in 1996, when it partnered with Shell on the development of the 500-billion-cubic-feet-equivalent (Bcfe) Popeye Field in Green Canyon. The following year, it teamed up with Kerr-McGee on the development of the 84-million-BOE Neptune Field at Viosca Knoll 826 in Mississippi Canyon, and then began its own deepwater exploration program in earnest. "We started 1997 with less than 500 square miles of 3-D seismic data on the deepwater Gulf of Mexico; today, we have more than 13,000 square miles," says Tim Parker, New Orleans-based senior vice president and general manager of offshore operations. "During that time, our acreage in the deepwater Gulf has also grown, from leases on 12 blocks to 87 blocks [before OCS Lease Sale 182], covering just under 500,000 gross acres, or nearly 300,000 net acres." Kevin P. Guilbeau, vice president of offshore exploration in New Orleans, explains the company's deepwater strategy. "We've focused on the proven-play concept, staying in the shallower portions of the deep water-up to 5,000 to 6,000 feet-where production has already been established along known fairways. In those minibasin areas, we've been able to effectively use bright-spot seismic technology-a direct indicator of hydrocarbon accumulations. This approach has greatly lowered the play risk. From 1997 to 2001, we've drilled 16 exploratory wells and had nine discoveries-a better than 50% success rate." Dominion E&P also uses strategic partnerships-with Shell, Kerr-McGee, Murphy Oil, Spinnaker Exploration and Pioneer Natural Resources-not only to share risk, but to gain exposure to other explorationists' ideas. After a discovery is made, the company also likes acquiring additional working interests in a prospect. Says Guilbeau, "Increasing your interest in a known quantity is one more way to add shareholder value, if bought at the right price." At the development stage, the company further attempts to add value by drilling in turbidite reservoirs. "What's key about these reservoirs is that they have high porosity, high permeability, and they cover large areas," says Parker. "As such, you're able to get high-rate productivity and high ultimate recovery from wells drilled in those reservoirs-much greater than what you can typically get on the shelf." Again, with the aim of adding value while keeping costs down, the producer also tries to minimize the number of appraisal wells it drills. Says Guilbeau, "We drill appraisal wells in strategic locations, then complete them and use them as development wells. Then we try to optimize the number of development wells that's needed to get good drainage." How is that accomplished? With good seismic, the company starts out with a more complete understanding of a prospect's geometry, he explains. Then, through 3-D reservoir modeling and simulations, it's able to more accurately know where to place wells, as well as the number of wells needed, to optimally deplete a reservoir. "This not only winds up saving us money in expendable-well costs, but also maximizes our profitability on a field." No small part of the operator's focus on value-creation at the development stage is its planned truss-spar production facility for Devils Tower, a 70- to 150-million-BOE discovery in Mississippi Canyon Block 773. The prospect, now under development, is 75% owned by Dominion and 25% by Pioneer Natural Resources. Says Guilbeau, "The majors were out in the deep water first, but a lot of the innovation that's going on now in this region is coming out of the independents." Case in point: The first classic-spar production platform was installed by Kerr-McGee in 1996 at its Neptune Field in 1,930 feet of water. It proved that a large floating cylinder, moored in a vertical position, is exceptionally stable and can be used to support oil and gas production from much deeper water. Indeed, ChevronTexaco and ExxonMobil subsequently used similar spars in the Gulf for their respective Genesis and Diana projects, in corresponding water depths of 2,590 and 4,750 feet. This year, Kerr-Gee has installed new truss spars at its Nansen and Boomvang fields-in respective water depths of 3,675 feet and 3,450 feet-and is planning another for its nearby Gunnison project in 3,100 feet of water. "One advantage of the truss spar over the classic spar is that the truss system traps water, which provides better vertical stability to the spar," explains Darrell E. Hollek, Houston-based vice president of Gulf of Mexico operations for Kerr-McGee Oil & Gas. "Also, a truss spar can support bigger payloads, including production and drilling facilities, and is cheaper to build than the classic spar." James D. Abercrombie, New Orleans-based vice president of offshore production for Dominion E&P, cites yet another advantage of spar technology, classic or truss. "Because the production tubing comes up from the subsea wellheads through vertical risers to the deck of the spar platform, we have easy access to dry [Christmas] trees. That's going to be particularly important at Devils Tower, when our own truss spar comes online in mid-2003. That's because the field has eight stacked pay zones, and we know that during the life of the field, we're going to want to enter wellbores repeatedly. With a spar, we can do that at costs anywhere from $100,000 to a couple of million dollars per well. In the case of subsea, wet trees, a floater would have to be mobilized to do the same work, at costs that could reach $12 million per well." Besides using off-the-shelf technology for its Devils Tower dry-tree spar-which will be the world's deepest in 5,610 feet of water-Dominion E&P has entered into a financing arrangement with Williams Energy Services that enhances further the project's economics. Williams, which aims to get further into the deepwater infrastructure market-as does El Paso Energy Services-will spend $440 million to fund the spar and pipelines from the platform. In return, Dominion will pay Williams a monthly fee for transportation and use of the spar while the producer continues to operate the field. "It's a win-win situation," says Parker. "Williams gets a hub it can use to tie in future output from other deepwater operators, and we get to devote more of our capital to finding more Devils Towers." (See sidebar.) At peak capacity in 2003, Devils Tower, discovered in 1999, will produce daily through its spar 60,000 barrels of oil and 60 million cubic feet of gas from 11,300- to 14,500-foot lower Pliocene and upper Miocene sands. Stresses Parker, "We're focused on shortening cycle times-the period between discovery and first production-to three to four years. By dropping cycle times to that level, we improve our rate of return and allow our capital expenditures to be moved quickly to other projects." Bucking recent capex budget trends in the upstream, the company's E&P spending in the offshore Gulf of Mexico this year will hit $440 million, up from $422 million last year. How can it do that? For one thing, it doesn't hurt to have a parent with an enterprise value of $35 billion. For another, when the company has already grown its net deepwater production during the past seven years from zero to 125 million cubic feet equivalent per day, and two of its projects-Devils Tower and Front Runner in Green Canyon-are expected to more than triple that level of output by 2003-04, it's arguably not a bad idea to keep punching holes in deepwater prospects. Also, given the positive outlook for commodity prices, the fact that oilfield-service costs are about 60% of what they were a year ago, and the fact that budget pullbacks by other operators are causing lucrative offshore properties to become available, this is actually a pretty good time to be drilling and building prospect inventory in the deepwater Gulf, says Parker. The company has a spate of other exploration targets on its plate, apart from its banner projects at Devils Tower and Front Runner; its producing fields at Popeye, Neptune and nearby Einset; and its discoveries at Mighty Joe Young in Green Canyon and at Rigel and 17 Hands in Mississippi Canyon. Along the Front Runner corridor, this includes the 25- to 75-million-BOE Quatrain prospect and the 100-million-BOE Cool Papa prospect. Also, the company will be drilling the Triton prospect, similar in reserve potential to Quatrain and not far from Devils Tower. Additionally, it will be partnering with Shell on the 100- to 150-Bcfe Sweet Pea prospect near Popeye. While the company's targets in the deepwater Gulf of Mexico are big and flashy-with returns on capital employed well north of 15%-they are only a component of a balanced prospect portfolio, stresses Radtke. He notes that Dominion-whose total reserves are now 4.8 trillion cubic feet equivalent after its late 2001 acquisition of Louis Dreyfus Natural Gas Corp.-is also focused on lower-risk, 20- to 70-Bcfe targets on the Gulf shelf, steady-growth production from 7,000 development wells in the Sonora Field in West Texas, and factory-like output from shallow gas wells in Appalachia, the Midcontinent, the Rockies and Canada. Kerr-McGee For Oklahoma City-based Kerr-McGee, the Gulf of Mexico is a very familiar hydrocarbon province. Back in 1947, it drilled the first commercial offshore well out of sight of land, in 17 feet of water. Since then, this pioneering operator has extended its footprint into much deeper waters. Today, it is the largest producer and leaseholder among all independents operating in the deepwater Gulf-with daily output of around 75,000 equivalent barrels and 360 deepwater leases (before OCS Lease Sale 182) covering more than 2 million gross acres. "Our first step into the deepwater Gulf was in 1994, with the fixed-platform Pompano project in 1,300 feet of water," says Dave Hager, Houston-based vice president of Gulf of Mexico and worldwide E&P operations for Kerr-McGee Oil & Gas. "Two years later, in 1,930 feet of water, we installed the world's first classic-design, production spar for our Neptune Field, some 90 miles south of Mobile Bay, Alabama. Simple in concept, it was a moored, 705-foot-long vertical cylinder with ballast chambers in it to keep it floating, and a production deck atop it." The cost of the spar, the production-deck facilities it supported, and the six-point mooring system anchoring the spar to the sea floor was about $150 million. Its daily productive capacity: 32,000 barrels of oil and 72 million cubic feet of gas. Says Hager, "Because the spar's fabrication and installation costs are much lower than some other deepwater production alternatives, such as tension-leg-platforms (TLPs), it improves the economics of developing 50- to 350-million-BOE fields." Another economic advantage a spar has over alternative production systems, such as fixed platforms, is that it can be moved and reused at another location once the reserves in a field are depleted. As for the spar's safety and reliability, that's hardly an issue. Explains Hollek, "In 1998, after the eye of Hurricane George passed directly over the Neptune spar, all we had were a few electrical problems, some things turned over, and a few fish onboard." This year, some 140 miles south of Galveston, Texas, as Kerr-McGee moves ahead at East Breaks with the development of its much larger Nansen and Boomvang deepwater fields-with collective estimated gross reserves of 210- to 280 million BOE-the innovative operator is introducing a new truss-spar system. "The lower part of the classic-spar cylinder has been replaced with a truss mechanism that dampens the vertical movement of the spar by trapping water above three heavy, horizontal plates, thereby restricting the amount of upward force on the spar generated by waves and currents," explains Hager. "Also, at the base of the truss is additional weighting, designed to limit the spar's horizontal movement. The result of all this design change is increased stability. And with increased stability, as much as 35% to 40% more weight can be put on the topside, in the form of completion-rig and production-handling equipment." The twin Nansen and Boomvang truss spars-each 162 feet shorter than the Neptune spar-have the capacity of handling daily production of 40,000 barrels of oil and 200 million cubic feet of gas. And both share common export oil and gas pipelines, constructed by Williams Energy Services, that are tied into market-clearing points onshore Texas. Says Hollek, "With these structures only nine miles apart, we have the ability to capitalize on our inventory of equipment, personnel and training." He also notes the two spars need only a dozen or so people to operate them versus the 70- to 80-man crew that some TLPs require. Now in construction in Finland is yet another Kerr-McGee truss spar, this one for the company's Gunnison prospect at Garden Banks, where reserve potential is estimated at 120 million BOE. "This spar, which won't come online until 2004, will be slightly larger since we'll need to put a larger completion rig atop it, due to the 15,000- to 18,000-foot wells being drilled at Gunnison versus the 11,000- to 13,00-foot wells at Nansen and Boomvang," says Hager. "We'll also be tying into this spar subsea wells from a satellite discovery field, Durango." In the meantime, Kerr-McGee this year will be drilling 12 to 15 more deepwater Gulf of Mexico wells. Says Hager, "With 360 deepwater leases, we have a large inventory from which to choose the cream." Murphy Oil Around the same time that Kerr-McGee was kicking off its Pompano project in 1994, El Dorado, Arkansas-based Murphy Oil also began turning its attention to the deepwater Gulf of Mexico, starting out with just a handful of leases. Today, it has 132 deepwater Gulf leases (defined as leases in 600 to 7,500 feet of water) covering close to 700,000 gross acres. "Before 1994, we had been drilling 10 to 15 Shelf wells a year with good success, but never adding any significant amount of reserves," says Enoch L. Dawkins, president of Murphy Exploration & Production in New Orleans. "So we studied the deep water-mainly Garden Banks, Mississippi Canyon and Green Canyon-and saw that there was roughly a one-in-three chance of finding and commercially developing bigger reserve targets. But it wasn't until 1998 that we had enough deepwater leases to kick off a drilling program." The company's initial drilling in Garden Banks was disappointing. The first two wells were dry holes. Then it drilled a Ewing Bank prospect, Boomslang. "We found 187 feet of oil pay, with a reserve base of 15- to 25 million equivalent barrels," says John C. Higgins, senior vice president, U.S. exploration and production, for Murphy Exploration & Production in New Orleans. Murphy's return to Garden Banks was more successful in 1999 at Habanero, a 75- to 100-million BOE find in which the company has a 33.75% stake alongside Shell. The following year, in Mississippi Canyon, Murphy again hit pay dirt with a similar-size discovery at its 60%-owned Medusa prospect. "Then we drilled four dry holes in a row and our resolve was tested," says Higgins. But not for long. "In 2001, in Green Canyon, we made a very large discovery at Front Runner North and South-two distinct fields in 3,400 feet of water, with a combined reserve potential of 120- to 200 million equivalent barrels." Working interests in this Murphy-operated project are Murphy, 37.5%; Dominion E&P, 37.5%; and Spinnaker Exploration, 25%. Dawkins notes that the all-in costs at Medusa will be $440 million; at Front Runner, $550 million-plus. What makes the Medusa and Front Runner projects attractive is that both will produce from truss spars which will be in place by fourth-quarter 2002 and first-quarter 2004, respectively. Each will have the capacity to handle daily output of 40,000 to 60,000 barrels of oil and 100 million cubic feet of gas. "One of the advantages of these spars is that they allow the producer to easily reenter wells to perform workover operations," says Higgins. The use of these spars also allows an operator to get production on quickly, adds Dawkins. "The wells are already drilled and completed before the spar is moved into place. All that has to be done is to tie the wells back to the surface." There are, however, some cases where alternative deepwater production systems make economic sense. In the case of Habanero, Murphy has elected to tie that subsea discovery back to existing infrastructure at Shell's nearby Auger platform. Looking to further extend both the economics and the life of their Medusa and Front Runner discoveries, Murphy and its partners have put together a cluster of blocks surrounding these finds. Says Higgins, "Around Front Runner, we have four or five other prospects that cumulatively have a reserve potential of 300- to 500 million additional BOE-and any future discoveries from those prospects could be tied back to our Front Runner spar." With an approach like this, and to date a 40% exploration success rate in the deepwater Gulf of Mexico, Murphy expects to see output climb dramatically over the next several years. "By year-end, our daily production as a company should be around 120,000 BOE, bolstered by output from Medusa," says Higgins. "And in 2004, it'll be around 175,000 equivalent barrels, with the help of Front Runner and Habanero." A U.K. upstream analyst recently observed, "It's cheaper to buy existing production than to find new fields." Don't try telling that to Murphy Oil, or other like-minded deepwater Gulf of Mexico explorationists.