There are a whole lot of small fish swimming around the big pond known as the deepwater Gulf of Mexico, and it's easy to see why. For some independents, one exploration well has the potential to double a company's reserves. Of course, if that well costs tens of millions of dollars, a dry hole could seriously wound the balance sheet. More and more, independents of all sizes are taking on the risks of the deepwater, even outbidding the majors at recent Gulf of Mexico lease sales. In 1993, there were 56 leases in the deepwater Gulf of Mexico operated by independents. In the first quarter of 2000, that number jumped to 1,202, according to Convergent Energy Group Inc., a company formed to help independents finance deepwater developments. (See sidebar.) In 1998, independents spent three times as much as the majors on acquiring deepwater leases, according to Convergent. In total, it's been estimated that independents hold more than 40% of the active leases in the deepwater Gulf. Oil and Gas Investor visited with executives of four independents that are making the deepwater Gulf a core part of their exploration portfolios: Callon Petroleum Co., EEX Corp., Mariner Energy Inc. and Spinnaker Exploration Co. While they are all striving for big discoveries and big returns, their stories and strategies are quite different. Callon Petroleum Co. At the beginning of its deepwater career, Callon may have best been known as the partner of Murphy Oil Corp. The two companies worked together on a number of projects in the past, and when Murphy decided to go deep in 1996, Callon went too. Since then, however, Callon has expanded its list of partners, and executives have their sights set on one day becoming an operator. "Now that we have four discoveries, our plan is to selectively staff for deepwater development and operational experience," says John Weatherly, chief financial officer. "Our target is to be capable of operating three years from now." The company couldn't have asked for a better introduction to the deepwater Gulf. In September 1998, Callon announced that its first deepwater well hit oil-Boomslang on Ewing Bank Block 994 in 900 feet of water. That depth doesn't classify the field as "deep water" to most, but for Callon it was a big change from the onshore and supershallow properties in the portfolio. The Murphy-operated Boomslang has more than 30 million barrels of oil equivalent in reserve potential. Callon started out with a 35% interest, later boosting that to 55%. Just six months later, Callon, based in Natchez, Mississippi, was back in the news with another discovery. This one was in water more than twice as deep-and the reserves were more than twice as big. Habanero, in Garden Banks Block 341 in 2,000 feet of water, contains more than 80 million barrels in proved reserves. Callon owns an 11.25% interest in the field, Murphy owns 33.75% and Shell, operator, holds the rest. Callon completed the trifecta in September 1999 with Medusa, a Murphy-operated discovery in Mississippi Canyon Block 582 in 2,235 feet of water. Total proved reserves have been estimated between 80- and 100 million barrels of oil equivalent. Agip Petroleum Co. Inc. has 25% interest and Callon has 15%. Then, the company's luck changed. Callon participated in two dry holes, at the Vastar Resources-operated Anvil, Mississippi Canyon blocks 815 and 816 in 5,500 feet of water, and the Murphy-operated Chin Music, in Mississippi Canyon blocks 378 and 379 in 4,500 feet of water. The company's dry-hole exposure on the two wells totaled about $7.1 million. Callon got back on track with its most recent wildcat, a discovery at Vastar's Entrada prospect on Garden Banks Block 782 in 4,642 feet of water. Executives estimate the field holds 150 million barrels of oil equivalent. Callon owns a 20% working interest, and Vastar, now part of BP, holds 80%. Despite Callon's 4-for-6 batting average, its stock has remained dormant. "It's undervalued. The Street really hasn't given them credit for the deepwater discoveries they've had so far," says Larry Benedetto of Howard, Weil, Labouisse, Friedrichs Inc. in New Orleans. "I think it's primarily a factor of two things. One, it's not a very liquid stock. It's hard to buy and sell, which keeps investors away. Secondly, there's a question in many investors' minds as to the financing of the development of the deepwater discoveries. How will they finance it all?" That's a question Callon executives are now trying to answer. The stock market assumes that Callon will have to sell stock to finance these developments, Weatherly says. However, because of those assumptions, the company's stock is trading at a substantial discount to net asset value, which makes it less likely that executives would choose a share offering as a financing option. "It's a catch-22," he says. Conventional debt is not the No. 1 choice at this time, either. "We're not inclined to use conventional debt to finance these projects," Weatherly says. Currently, Callon has a debt-to-market-capitalization ratio of 35%. Historically, executives do not want to exceed 40%. That doesn't leave much breathing room. But there are other options. One is to develop one of its projects as a production hub, with some or all of the financing provided by a partner, and charge other companies for access to the processing equipment on the platform. "There are a lot of discoveries, in the 40- to 60-million-barrel range that have to be produced through hubs," he says. "You can make a nice profit in throughput charges." Another option may be to arrange an off-balance-sheet method such as a synthetic lease. These are structured as operating leases, so they are not carried as debt on the balance sheet. However, the lease terms and underlying obligations result in basically the same economics as debt financing. Whether Callon's deepwater development costs are financed through a lease transaction or otherwise, the company is reviewing alternatives for "credit enhancement." By sharing the benefits of ownership with a third party, which would have a vested interest in the property, Callon could benefit from that third party's stronger credit rating, executives say. The benefits to be shared could be the right to purchase the oil or gas produced, a residual interest in the property itself, or a portion of any throughput charges received from others using the facility. "Those are some of the options we're primarily looking at," Weatherly says. Once a financing method is chosen, however, it's still difficult to know exactly how much money is required because there is a lot of potential upside around each of Callon's discoveries. For example, the company's Sidewinder prospect, if successful, could totally change the magnitude of the requirements for a Boomslang development. The same goes for the Moccasin prospect, near the Habanero find; the Stonemaker prospect, near the Medusa discovery; and Conoco's Magnolia prospect, near the Entrada discovery. "You can't peg the financial requirements just yet," Weatherly says. Going into 2001, however, the picture should become much clearer. As these prospects are drilled, Callon will have a good idea of just how much oil it has in deep water. "The next six months are a big six months for us," Weatherly says. EEX Corp. In 1972, Tom Hamilton worked for Exxon Production Research, studying offshore sand deposits. The conventional wisdom at the time said that very deep sands-in excess of 22,000 feet below the surface of the earth-were under extreme pressure and too hot to produce hydrocarbons. But 25 years later, when Hamilton became chairman and chief executive of EEX, he and his staff set aside the concerns of the past. They set out to build their company on the idea that deep deposits in deep water were actually viable targets. It was an idea being pursued by Shell following its Auger find, but otherwise, no one else was pursuing prospects at the deeper drilling depths, Hamilton says. "When we drilled, we had to throw conventional wisdom out the window. We had very definite opinions; we would pursue a different play than other smaller companies interested in the deepwater...We wanted to make a deeper play in the Lower Pliocene and Miocene-aged sands, so we transitioned." This idea, however, was an extremely risky one, even for the deepwater arena. The cost of these wells-which can range from $20 million to as high as $100 million-posed a substantial financial risk for a company the size of EEX, a company with a $220-million market capitalization. So executives went looking for an industry partner. The Houston company, which had about 80 deepwater leases at the time, contacted five international companies that had no deepwater presence in the Gulf of Mexico. EEX set up a data room, and the five companies bid for partnership rights. The high bidder was the U.K.'s Enterprise Oil, which got half of EEX's interest in 78 deepwater blocks for a $65-million carry on exploration drilling and additional success payments. As a result, EEX was sheltered from substantial dry-hole risk on the front end of the deepwater exploration program. With the financing secure, EEX began drilling. The company found oil with its first target, Llano, which contains estimated reserves of 200 to 250 million barrels of oil equivalent. Three wells have been drilled there so far, the first of which set a depth record for the Gulf of Mexico at 27,864 feet. Llano was a hard-fought victory, however. Drilling difficulties, related to differential pressures encountered in the open hole, necessitated sidetracks in several wells. The total bill for the three wells has been estimated at close to $200 million. After initial success at Llano, EEX had a run of bad luck, drilling a series of dry holes: Sheba, Elvis, George, Gamera and Mackerel. "We're 1-6 in the deepwater," says Richard Langdon, executive vice president and chief financial officer. "We need to demonstrate a higher success rate." The lack of additional deepwater success hasn't helped EEX's stock performance. Its 52-week trading range has been as high as $6.875 and as low as $2.125. At press time EEX was trading around $4.50 per share. For the first nine months of the year, its revenues were approximately $190 million, and it reported a net loss of $17 million, or 40 cents per share. "A lot of money has been spent without significant additions of proved reserves," says Mark Fischer, a Banc of America Securities E&P analyst. "And E&P companies do trade principally on the present value of the projected cash flows of proved reserves." Executives plan to boost the company's reserves by going back to their crown jewel-Llano. It's been a steep learning curve there, but they believe they can find further success in this prolific area. "If you find a play that works, you stay in the basin for a while," Hamilton says. And this play does seem to work. In the Auger-Llano-Baldpate minibasin, for wells targeted to the Pliocene and Miocene, there have been 11 discoveries made out of 11 prospects drilled, including wells by Shell Exploration & Production Co., Kerr-McGee Oil & Gas Corp. and Amerada Hess Corp., Hamilton says. EEX has six untested prospects in this minibasin, and at press time the company was drilling one of them-the Jason prospect at Garden Banks Block 344. There's about $14 million left from the deal made with Enterprise, and Jason likely will consume a good portion of that. For the next round of development, EEX has a couple of options to consider. The public markets have not been welcoming during the last couple of years, but service companies have been interested in providing working capital for some operators. Also, EEX could try another equity financing such as the one executives arranged about 18 months ago with Warburg, Pincus Equity Partners LP. The New York equity fund purchased $150 million of newly issued EEX preferred shares and warrants to acquire a total of 21 million EEX common shares. It's important that EEX prove its theory about deep drilling, to regain confidence. "I don't think there's much value in our stock currently for deep water," Langdon says. "The dry holes put the market in a wait-and-see posture. We have to prove to the market that we have a viable strategy." Mariner Energy Inc. Houston-based Mariner Energy knows its niche: use subsea technology to develop midsize fields that are purchased from asset-shedding majors or discovered via low-cost exploration. It's a strategy that has served the company so well that management is targeting more than 90% of all new activity toward the deepwater Gulf. For a company of its size, Mariner was an early entrant into the deepwater, first examining the play in 1992. It began tackling projects two years later, acquiring and exploiting small discoveries that were below the threshold of the majors. Today, Mariner operates three such exploitation projects, and has recently added a fourth project named King Kong, in 3,900 feet of water, which Mariner bought from Shell this year and expects to bring online in early 2002. "As larger companies consolidate, their minimum thresholds rise in terms of reserve sizes," says Robert Henderson, president and chief executive. "When they shed assets, that means more opportunities for us to acquire their small discoveries. This represents a real win-win outcome because the larger companies can focus their deepwater technical teams on the larger fields but still share in the value of these small discoveries." The Pluto project is a great example. BP Plc, Chevron Corp. and BHP Petroleum (Americas) Inc. farmed out a discovery of 20 million barrels of oil equivalent in 2,900 feet of water to Mariner, which then developed the field with a 29-mile subsea tieback to a host platform on the shelf-the second longest in the Gulf today. Mariner, along with project partner Burlington Resources Inc., enhanced the economic-value-added by securing royalty relief on the field and by obtaining innovative infrastructure financing. Mariner made the leap from exploitation to exploration in 1996, determined to build reserves through the drillbit. In the early days, the company targeted fields in the range of 5- to 15 million barrels of oil equivalent. Slowly but surely, the company grew to pursue projects with up to 50- to 75 million barrels of reserves. Mariner has an impressive drilling success rate in the deepwater Gulf, hitting eight discoveries out of 15 exploration wells drilled. Though many of the projects could be considered low-risk by deepwater standards, the company is tackling some challenging developments. The best examples may be Aconcagua and Devils Tower. Mariner and its partners purchased these two prospects in 1998 at a U.S. Minerals Management Service lease sale. Mariner's portion of the bids was $18 million-big bucks for a small company, but management felt strongly about the potential of the blocks. They appear to be right. A successful exploration well was drilled on Aconcagua in early 1999, followed by a successful appraisal well in early 2000. The development will follow Mariner's subsea tieback strategy. However, the field is in 7,000 feet of water, which would make it the deepest tieback ever in the Gulf. "We identified the lead in 1997," remembers Mike Strickler, senior vice president of exploration and land. "There was a tremendous structure there, one that probably would have been drilled many years ago if it had been on the shelf." Mariner was hesitant about pursuing a project this deep. But when executives learned that Elf Exploration was also interested in the block, Mariner teamed up with the major and went after the prospect. "There were nine competing bids for the block," Strickler says. "Our group's $23.5-million bid barely won." The Devils Tower discovery, in Mississippi Canyon Block 773, was drilled in 5,700 feet of water in the fourth quarter of 1999, followed by a successful appraisal well and sidetrack in 2000. Mariner operated the initial two wells in Devils Tower with a 50% working interest, but transferred operations to Dominion Exploration & Production Inc. when it sold down to a 20% interest for an undisclosed amount of cash in July 2000. "We reduced our working interest from 50% to 20% to monetize a portion of our success and reach an appropriate interest level in what will likely be our first floating production system development," Henderson says. Additional appraisal drilling is planned for 2001. In the future, Mariner plans to extend its niche in the deepwater toward floating production systems. "Our goal is to develop an ultra-low-cost floating production facility using subsea technology that makes 15- to 50-million-barrel deepwater discoveries that are far from existing infrastructure commercially viable," Henderson says. "It needs to be lower cost than the current spar technology and be portable so that the production facilities and subsea equipment can be reused on multiple fields," adds Richard Clark, executive vice president. Mariner has recently led a successful effort, in conjunction with a major designer and builder of semisubmersibles, to develop this ultra-low-cost floating system. "Development of this technology, which is basically a semisubmersible barge, will allow us to greatly increase our access to many smaller opportunities in the deepwater Gulf, and bring them online quickly," says Clark. While Mariner operates more than 75% of its exploration projects, it attempts to keep its financial risk at acceptable levels. "We operate in deep water, but we try to manage our risk exposure by focusing on relatively lower cost exploratory wells with gross costs of $5- to $20 million," says Clark. Mariner also seeks to limit its exposure by keeping its interest in these types of projects to 25% to 50%. Privately held Mariner was formed in 1996 by a management-led buyout of Hardy Oil and Gas USA, a deal that was financed by Enron North America, an affiliate of Enron Corp. and presently Mariner's largest shareholder. The plan in 1996 was to take the company public in three to five years, and Mariner currently has an S-1 on file with the Securities and Exchange Commission. An initial public offering could be made as soon as the second or third quarter of next year, when the market should be able to value Mariner's production growth from new projects. Plans were to price the offering in the fall of 1999 but interest in E&P IPOs had waned, meanwhile. Henderson believes Mariner's story would be a compelling one on Wall Street. For the first six months of 2000, revenue was $58.3 million and net income was $11.5 million. "We have a strong track record in our deepwater Gulf niche, and we have the potential for truly superior returns. There should be room for that type of company in the marketplace," he says. Spinnaker Exploration Co. Executives here pride themselves on two features: an extensive 3-D seismic database in the Gulf of Mexico that rivals that of Shell and BP, and enough cash flow to fund significant projects without worrying about complex financing arrangements. "We're definitely set apart because of how we've chosen to sequence things," says Roger Jarvis, president and chief executive officer. "We built our portfolio and our balance sheet before we ventured out." Spinnaker was formed in 1997 through a $60-million private equity infusion from E.M. Warburg, Pincus & Co. LLC in New York, and an additional $15 million of capital from Spinnaker's management and from service company Petroleum Geo-Services (PGS). (For a detailed look, see "Setting Sail," Oil and Gas Investor, February 2000.) In addition to cash from PGS, Spinnaker received a permanent license to PGS' existing and future Gulf of Mexico seismic through March 2002, a prized possession in such an information-intensive industry. In total, the company has 9,200 blocks of seismic data from PGS and other seismic companies. Forty percent of that database involves deepwater blocks, and is rapidly expanding. In three years, Houston-based Spinnaker has made 31 discoveries, mostly in shallow water. The company produces about 125 million cubic feet of gas a day, and it has never purchased producing assets. "The cash flow from the shelf provides us a stable platform," Jarvis says. Three successes have come in the deepwater. Dulcimer, in Garden Banks 367 in 1,125 feet of water, is a Mariner-operated development that came online in April 1999 at a production rate of about 58 million cubic feet of gas per day. Zia, in Mississippi Canyon 496, is a Shell-operated discovery that is awaiting its second well. Sangria, in Green Canyon 177, is a Spinnaker-operated discovery that has not yet been sanctioned, but it may be commercial at today's commodity prices. In September 1999, Spinnaker took itself and its story public in an extremely difficult market. The 8-million-share IPO raised $116 million versus a targeted $130- to $140 million, pricing at $14.50 per share instead of $16 to $18. The stock is now trading at around $40. Net income for the first nine months of 2000 was $16.6 million, or 73 cents per diluted share. The company has no debt, and $300- to $400 million in total liquidity. Currently, Warburg Pincus owns 21% of the company; PGS, 19%; and management, 10%. The public owns the remaining 50% of the $1-billion-market-cap company. PGS plans to monetize its 5.4-million-share interest in Spinnaker during the next 24 months. While the Gulf shelf program is still vital for its additions to cash flow, Spinnaker is determined to grow its deepwater business. Four or five more deepwater wells are on the schedule for 2001, and 30% to 35% of the company's budget will be targeted there. Spinnaker tries to stay focused on prospects with condensed reservoirs-prospects that can be delineated with three wells rather than six or seven, as some deepwater fields require. "To spend three years drilling six or seven wells before you know whether you have a commercial discovery, for an independent, that can be potentially dangerous," Jarvis says. Analysts look forward to the growth of the company. "Spinnaker has one of the most visible growth profiles in the industry with cash flow per share expected to increase 33% in 2001 over 2000," says a Credit Suisse First Boston report published earlier this year. "The increase is driven by a 50% increase in production, all of which is internally generated...It is our expectation that Spinnaker will remain a growth leader for the next several years." With its extensive seismic portfolio, Spinnaker is an attractive partner for any deepwater player. Although the company operates some deepwater tieback projects in less than 2,000 feet of water, executives are content for now to play a supporting role in projects that lie in deeper waters or require a stand-alone development system. But that won't last for long. "In the longer-term we intend to be an operator in the deepwater," Jarvis says, referring to fields beyond 2,000 feet of water. "We're not ready to operate yet, but maybe in a year or 18 months." FINDING FINANCING Ask the CEO of an independent E&P company about the challenges of working in the deepwater, and you're more likely to hear about project financing than drilling. Traditionally, a small company will enlist a bigger independent or a major when it needs help developing its discoveries. But as deepwater activity expands and the number of majors shrinks, it may be difficult to attract outside interest in a project unless the reserves are huge. At least one new company sees a business opportunity here. Houston-based Convergent Energy Group Inc. was formed last year to help independents find ways to conceptualize, construct, finance and manage oil and gas production facilities in the deepwater Gulf of Mexico. Convergent's concept is this: a partnership of companies owns the production platform, processing equipment and pipelines to get the hydrocarbons to shore. The independent E&P company leases these facilities via an off-balance-sheet, volumetric lease that shares reservoir risk and reward. Partners in such an arrangement might include construction contractors that provide facilities on a turnkey basis, third-party financial investors and Convergent Energy, which develops the project and arranges capital funding. For example, say a producer wants to develop a 100-million-barrel discovery through a floating production platform. Assume a total cost of $450 million: $100 million for the development wells, $65 million for the subsea equipment, $125 million for the platform, $60 million for the processing facilities and $100 million for the export lines. If commodity prices average $18 per barrel and $2.25 per thousand cubic feet, the producer would get a 35% return on that $450-million investment, according to Convergent. But under the Convergent method, the producer would need to provide only $165 million-for the development wells and subsea equipment. Convergent would supply the remaining $285 million for the platform, processing facilities and export lines. If the producer pays $5 per barrel to lease the platform and the field produces 100 million barrels of oil equivalent, then this arrangement would provide the producer a 68% return. The producer would have less capital invested in the infrastructure, freeing more capital for exploration and appraisal. Under this structure the producers retain full ownership of the reserves and remain in complete control of their reservoir, making all decisions related to drilling, completing and maintaining the wells. Convergent and its partners would be sharing the reservoir risk, but by stepping in after the field has been delineated with at least two or possibly three wells, executives say the reservoir risk is significantly less than a pure exploration prospect. In this field example, the Convergent partnership would be in a position to earn returns ranging from the mid- to high teens. "There's a market out there that is comfortable with these returns at an appropriate level of risk," says John L. Haynes, president and chief executive officer of Convergent. "This helps independents get better use of their capital," says David A. Herasimchuk, vice president and chief financial officer. "They give up some net present value to pay us for the throughput, but they get a much better internal rate of return and a more efficient use of capital." Convergent had not yet finalized a deal by press time, but was in negotiations to apply its strategy on five deepwater projects worth a total of $1 billion.