Independents have always been more optimistic than any other breed of American business owner. The $1-million roll of the dice at year-end, when time, investor patience and the drilling budget have run out, is a classic ploy. The oil patch is full of stories of gamblers who bet the farm. Many came up empty, but enough have come out on top to keep the drilling dream alive. The independents that we canvassed for this month's features agree unanimously on two things. First, as a critical class of companies within the larger upstream world, they are not going away any time soon. There will always be a place for them in domestic exploration and production, even if the way they do business changes. And second, there are still plenty of untapped reserves in North America waiting for the drill bit, especially in natural gas zones. Beyond these assumptions, nothing else is sure. No one's crystal ball can foretell what volatile oil and gas prices will do or how supply and demand may change over the next 20 years. Success will depend on how well companies respond to trends such as the coming personnel shortage, technological advances and the search for new plays in mature areas. No one doubts the need for independents to keep doing what they do best-explore and produce in areas the majors do not go. In December, the U.S. Energy Information Administration projected that U.S. petroleum demand will reach 25.8 million barrels a day by 2020, up from about 19.5 million a day currently. That's a modest annual increase of 1.3%. On the other side of the coin, the EIA forecasts U.S. oil production will decline during that period at an average annual rate of 0.7%, to just 5.1 million barrels a day. The resulting supply shortfall-some 20.7 million barrels per day-will have to come increasingly from OPEC members and other countries. But these numbers leave a lot of wiggle room for U.S. independents to step up their activity, as the price of oil and gas permit. No one doubts that U.S. potential remains, often right under our noses. The booming Bossier gas play in East Texas, the emerging gas giant in the San Joaquin Valley of California, and the prolific gas plays making headlines in the Rockies, are great examples of how new technologies and business practices have revived areas that have been producing for many decades. "There is room for independents of all sizes, from very small shops to the mega-independents," says Jerry Jordan, chairman of the Independent Petroleum Association of America. "I see growth at all levels, from continued consolidation...to lots of new companies being hatched. The world economy will rely on our product for the foreseeable future. That mandates that we have to have a strong domestic industry. "It's just critical. Independents are the ones doing exploration in this country now and will do so in the future." The day we spoke, Jordan was doing his part. Knox Energy Inc., the Clinton, Ohio, company owned by Jordan and his son, Mark, had just fractured a gas well in 18 inches of snow, east of Cleveland. As the number of indies dwindles, each one becomes that much more important, Jordan says. He cites IPAA statistics showing that the number of registered operators of record has fallen from 13,000 in 1984 to about 2,000 today (not counting non-working-interest owners and investors in wells). Are those numbers ominous? No, indies say. "The one thing that has been constant in my 30 years in the industry has been the need for creative people who can make something out of nothing-that is, find oil and gas," says Mark Papa, chairman and president of EOG Resources Inc. Once a roustabout in his college years, Papa says he disagrees with the pundits who predict another decade of strong consolidation. "I think this consolidation idea has about run its course. I am not one who thinks that 10 years from now, all we'll have is four mega-independents left in the U.S. We'll still be very fractured and have a mix of companies of all sizes. There is a place in the food chain for everybody." Like Jordan, Papa thinks the role of the independent has becoming more important than ever. Ten years ago, the U.S. suffered from the infamous gas bubble "and it didn't make a hill of beans if a company found 100 Bcf or not," he says. "Today, with no supply cushion for gas, it's critical that companies like EOG find more gas, so the relative importance of the independents helping the U.S. economy continue to grow, is greater than ever." Long-time natural gas explorer Robert A. Hefner III agrees. The chairman of Seven Seas Petroleum and The GHK Cos. says indies can be quick, nimble and act fast. Now that they have access to most of the same technology as the majors, independents can do their jobs even better. "The nature of the independent has changed significantly in the last 10 years, so I don't see it changing as much in the next 10. The surviving and strong companies have already laid the foundation to be successful. Most of the discoveries are going to be made by them. Most of the large companies you see now started as independents-big discoveries made them what they are today." The risks, the challenges While independents of whatever size are optimistic, they are not naïve. All said they realize commodity price volatility is here to stay and must be taken into account. They know environmental protection matters and will be increasingly enforced at the state and federal level. Most cited a belief that industry consolidations will continue to spawn super-independents and small companies with new ideas. "One man's crumbs are another man's cake," says E&P analyst Bob Morris at Salomon Smith Barney in New York. His first job in the industry was in 1984, as an engineer for Mobil Oil in New Orleans. "You'll continue to see lots of niche players in North America and lots of new companies formed as the integrated companies pursue opportunities around the world. I think independents will also continue to develop their own opportunities. Anadarko Petroleum's Bossier gas play in East Texas is a perfect example-that was not something spun off from a major. "The majority of companies that exist today did not exist 10 years ago, and 10 years from now, we'll be saying the same thing." One key problem Morris sees ahead? Companies flush with cash flow report they are having a hard time spending it. They are not finding enough new drilling prospects that will enable them to keep growing their production. "The treadmill has gotten faster. In the past what they spent on E&P achieved double-digit growth but now, it may not. They may have to step into new areas to create another platform for growth." Easier said than done. Jordan cites the difficulty for smaller companies of raising capital and for larger companies, the lack of adequate access to federal and offshore areas. Papa cites the fact that there aren't enough young people entering the industry to learn from, and eventually replace, the veterans who will retire in the next decade. "One trend you'll see is that employers will have to be more flexible. They will retain their senior employees beyond the traditional retirement age, or those people will work longer for them as consultants." Allen Mesch, the recently retired director of the Maguire Energy Institute at Southern Methodist University in Dallas, has observed the industry for more than 30 years. He thinks education at all levels, from high-school classes to in-house training sessions at oil companies, must increase. He laments the fact that in the last decade, most oil companies have abandoned intense training programs. He suggests two solutions to the talent shortage could be the growing use of para-professionals trained at community colleges rather than in traditional four-year programs, and the hiring of talent from other nonenergy industries that use technology. What is the right size? As the barriers to entering this business continue to fall, change accelerates and competition for good deals intensifies. Luckily, the gap between the supermajor and the small independent is narrowing as all have access to the same technology and even international E&P opportunities, other than those on a massive scale. The only real barriers left are access to capital, and deciding what scale a company should attain to survive. "It could be argued that if your market cap is below $1 billion, you have all the disadvantages of being small and none of the advantages of being large," claims John Walker, president of EnerVest Management Co. , a private Houston independent. "Independents can focus, react, take risks, grow," he says. "The supermajors have been built and I think the super-independents are being built. But I question whether any of those can grow in the future as much as they have in the last few years. The problem becomes those caught in the middle. They don't have enough capital to take on the really big projects, and some of them have started to lose their focus as they enter new regions or plays, in order to keep growing. They have pretty much drilled up their area of expertise, such as the Raton Basin or the Shelf, and they can't replace production or grow anymore, so they enter a new area where they don't have the same expertise. "It's the Peter Principle for the oil industry." It seems this question of relevant size has occupied many in this industry. "All the talk of needing to be bigger misses the point," maintains Chuck Davidson, newly appointed president and chief executive officer of Noble Affiliates , Houston. "It's that your size should match your appetite for risk, your opportunity set, and your ability to fund that. That way it doesn't matter whether you are a big independent or a niche player." Three types of companies Although executives are optimistic about natural gas demand and technology applications, and all agree they have to play to their strengths in some niche, they seem to be grappling with the way to proceed. Alliances? Outsourcing? Joint ventures? A hub-and-spoke system of prospect generators? SMU's Mesch sees three classes of independent emerging. The first will be the small, family-owned company well below most radar screens, that will eke out a living and be buffeted by price fluctuations. "It's like the small general store that survives in a town too small to have a Wal-Mart," he says. The second will be what he calls "opportunistic scavengers." These firms buy assets to exploit from majors or larger independents. They jump from opportunity to opportunity without much of a strategy. "They survive by sheer will and probably don't use sophisticated risk-management tools because their investors want all the price upside. They tend to be gas-prone and domestically focused." Finally, the third group is made up of companies with a coherent strategy to really build something larger, as opposed to just paying the bills. They know what they do well, they know what they want to achieve, and they know how to go about it. They develop a suite of exploration and acquisition opportunities and are fairly sophisticated. "The problem here is that they will be competing for talent with the majors, and their plans may be severely impeded by their ability to get and retain good people. The majors will outbid them," Mesch says. "We see the majors just off the board as far as domestic onshore and Gulf of Mexico Shelf work go," says Bill Silk, president of start-up independent DoubleStar Energy in Houston. "Then we see niche players who seem dysfunctional. Acquisition companies are trying to dress up as explorationists, and companies known for exploration are trying to be acquirers because the market perceives exploration as risky." Regardless of strategy, a company's strength resides in its people. Silk quotes Texaco chairman Peter Bijur, who has often said an oil company's true value has shifted away from oil and gas reserves in favor of its knowledge and experience. With that in mind, Silk is crafting a new kind of independent that gathers capital and expertise, then funnels it out to entrepreneurial, smaller companies working in various basins. Shared ownership of his company is a key component. The idea is that DoubleStar will assemble the capital, the databases and the huge investment in computing power, so that its partners can be fleet-footed and get to work sooner, without themselves investing in time and dollars to create the infrastructure they need. He figures that will cut out a year and a half of time. "Instead of bringing on an exploration manager, why don't we fund him and let him start his own company and let him go for it? The three- to five-man shop is very efficient. We can make them stronger and more efficient. We may 'fund' a guy through access to our seismic database, our expertise in exploration project management, or money. "But, we have no interest in seeing how many barrels a day we can get. We are after returns." Indeed, that goal was mentioned by many. Oil companies of all sizes now focus on the bottom line more than ever before, and that takes management skills and enhanced decision-making, not seat-of-the pants decisions. The competitive edge goes not to the company with certain resources, but to the company that has the smartest people, Mesch says. To that end, he'd like to see more in-house training at oil companies of every size, and more training consortiums formed by independents. "This will be a good business for those people who put themselves into the right niches," says Earl Swift, chairman of Swift Energy Co. "It's not about doing what you'd like to do, but doing what you're good at and what needs to be done. The whole industry is moving toward developing more natural gas to fill that growing appetite. That means it will have to be doing more horizontal drilling, coiled tubing, better fracing. The industry is moving to deeper onshore gas drilling, tight sands. We've gone from being a wildcatter who puts some money together and throws it at something hoping to hit, to being much more focused and sophisticated." Concludes Mesch, oil and gas will be a good industry to work in if you like challenges, change and dealing with complex issues. Says Hefner: "The independent sector can do a lot of work during the next decade." U.S. Exploration-a vibrant future Now that commodity prices have maintained a high level for a decent period of time, E&P companies are feeling brave. Thoughts have turned to exploration, and rigs are in strong demand. For many, growth through the drillbit is more attractive than buying reserves from sellers harboring inflated expectations. Although the United States hosts far more wells than any other nation, an astounding number of exploration plays still exist. "Today, companies are interested in plays with substantial reserves that have a high-technology twist," says G. Warfield (Skip) Hobbs, managing partner of New Canaan, Connecticut-based consulting firm Ammonite Resources , and president of the American Association of Petroleum Geologists' professional affairs division. "The majors have lost interest in domestic exploration and moved into the deep offshore and international arenas. But, we have highly skilled, technologically astute, entrepreneurial independents that are developing new and exciting plays in old areas. The opportunities are here for the smaller firms." Onshore deep exploration will feature prominently in the next decade, says Hobbs. California's San Joaquin play in the Temblor is a leading example of the potential that can lay undiscovered in a basin that has been heavily drilled for the past century. (For more on this play, see "The Deep San Joaquin," Oil and Gas Investor, December 1999.) Other timeworn areas that hold promise for fresh rounds of exploration include onshore South Louisiana and the deep Appalachian Basin. "In South Louisiana, new play concepts are being applied to the deep Miocene sediments," he says. "The geology looks very promising. And, when you look at a map of well penetrations below 20,000 feet, South Louisiana exploration is still wide open." Early Paleozoic sediments in the deep Appalachian Basin will be another focus. "Every formation in the Appalachian Basin is productive, and it shares characteristics with other great petroleum basins such as an abundance of reservoirs and structural styles," he says. Interest has been sparked by a number of high-volume Ordovician Trenton-Black River discoveries in a structure known as the Rome Trough, which extends from New York through Pennsylvania, West Virginia and Kentucky. "The entire Anadarko Basin fits into just the Rome Trough portion of the Appalachian Basin," he says. "The key to the deep zones will be finding places where porosity has developed, either from diagenesis or from fracturing." Enigmatic plays such as the Rocky Mountain Overthrust are also getting a going-over with the latest technology. Today's seismic tools offer far superior images of the complex subsurface structures than were available in the heyday of thrust-belt drilling, says Hobbs. Technologies such as prestack depth migration enable geoscientists to find untested ideas in these areas. Aside from companies revisiting familiar areas, Hobbs also expects a major exploration push in the eastern Gulf of Mexico. A large federal lease sale is slated for December 2001, and recent salt-feature discoveries immediately to the west of the Sale 181 acreage include the billion-barrel Crazy Horse Field in Mississippi Canyon Block 778, and Mickey Field in MC 211. "Other salt-related structures and stratigraphic trap discoveries adjacent to Sale 181-primarily in Miocene slope-fan deposits-are Mensa, Columbe and Ram Powell fields," says Norm Ross, senior geophysical consultant for Ammonite Resources. "In addition to a Tertiary-age clastic play, the eastern Gulf also offers promise of a Mesozoic carbonate play." Other presently accessible U.S. areas that could still yield significant new hydrocarbon finds are portions of Alaska and the deepwater Gulf of Mexico. These areas are physically challenging, but steadily advancing technology is constantly reworking what can be done. Alaska's 430-million-barrel Alpine Field is productive from the Jurassic, the first find from sediments of that age on the North Slope. Hopes are strong that Jurassic production will extend onto the National Petroleum Reserve-Alaska acreage immediately to the west. While enticing opportunities certainly exist in extensions and broad applications of traditional plays, perhaps the most striking potential lies in plays defined by new exploration concepts. The "continuous accumulation" concept is one example of a wave of thinking that is regenerating exploration efforts around the country. "In the onshore Lower 48, the future lies in the development of continuous accumulations and in reserve growth in already discovered fields," says James Schmoker, Denver-based geologist with the United States Geological Survey. Basin-center accumulations, coalbed methane, and oil and gas in shales and chalks all fall into the continuous basket. Widely recognized basin-center accumulations are the Lance Formation in the Green River Basin, the Barnett Shale in the Fort Worth Basin and the Mesaverde Formation in the San Juan Basin. Recently, the USGS examined 33 potential basin-center or continuous-gas accumulations throughout the country. Conventional accumulations feature downdip water; continuous accumulations do not have this characteristic, says Schmoker, a co-author of the screening report. Continuous accumulations are pervasively gas- or oil-charged reservoirs that cover a very large area. The hydrocarbons are not trapped stratigraphically or structurally in the traditional sense; accumulations can even cut across multiple stratigraphic horizons. "It's a very different way to think about accumulations," he says. "There are a great many basins that have potential for continuous accumulations, and the volumes of gas-in-place are stupendous." Basins that hold such promise range from the Puget Sound Trough in western Washington, through the deep Los Angeles Basin, the Denver Basin, the Arkoma Basin, and even to certain of the eastern U.S. Triassic rift basins. The trick with these accumulations is to find the sweet spots, or localized areas where the production characteristics are relatively favorable. These auspicious areas are geologically controlled by local permutations in source rock, generation and fracturing. Explorationists use everything from aeromagnetic data to shear-wave seismic data to try to predict the better targets. Often, certain trends and directions prove to be more desirable than others, as the sweet spots themselves can be quite heterogeneous. Coalbed methane is another type of continuous accumulation that is receiving strong exploration attention. (See "Coalbed Methane," November 1998.) Charles Nelson, manager of the coalbed methane research program for the Chicago-based Gas Technology Institute, notes that the Rocky Mountain region alone is estimated to contain 595.7 trillion cubic feet (Tcf) of coalbed methane resources. To date, exploration has focused on the Fruitland coals in the San Juan Basin, the Raton and Vermejo coals in the Raton Basin, the Ferron coals in the Uinta Basin, and the shallow Fort Union coals in the Powder River Basin. These four plays, all developed within the last 15 years, contain reserves of more than 11 Tcf. Notably, the latter three were discovered and developed by relatively small operators. Future potential lies both in expanding shallow coalbed methane plays to new basins, and by exploring deeper plays, says Nelson. In the Rocky Mountain region alone, programs targeting shallow coalbed reservoirs are ongoing in the Hanna, Wind River, Denver and Green River basins. "We see a great deal of interest in a lot of areas. Companies have been announcing a steady stream of acreage acquisitions and plans for pilot programs." The biggest prize, however, lies deep. About 75% of the 467 Tcf of resources in the Upper Cretaceous coals in the San Juan, Piceance, Raton, Uinta and Greater Green River basins are at depths greater than 4,500 feet. Due to their higher cost and higher risk, very few coalbed methane wells have been drilled for deeper zones. Further, there is a general industry belief that deeper wells will not find sufficient permeability for commercial gas production. "The example of White River Field refutes the arguments against deeper potential," says Nelson. Through 1999, the Tom Brown Inc. field, located in Rio Blanco County, Colorado, has produced 8.76 billion cubic feet of gas from 14 wells completed in Williams Fork coals at 5,090 to 7,547 feet. Evolving recovery technology also is a key to coalbed exploration and exploitation on a grander scale. Stunning results have been recorded from two San Juan Basin pilot projects that have injected nitrogen and carbon dioxide, respectively, into Fruitland coals. These technologies have the potential to increase gas production rates as much as sixfold, and producible gas reserves as much as twofold, notes Nelson. "There's an enormous coalbed methane resource that is only lightly exploited, and some very large frontier play opportunities that have not been tested at all. The enhanced recovery technology could also play a key role in making the frontier areas more attractive for development," he says. "We have an exiting future ahead." Despite the bright outlook, some gray clouds nevertheless clutter the horizon. Clearly, the United States has no shortage of natural gas potential, says Hobbs. "But, the immense challenge facing the domestic industry is public lands policy. Presently, we cannot explore in the Florida shelf area, or along the Atlantic margin of the country, or in enormous portions of the Rocky Mountain regions." Add in large swaths of Alaska's North Slope and the entire Pacific coastline, and the challenge becomes even more daunting. "We have to address the environmental concerns of the public," he says. "Just like the Canadians, British, Brazilians, Norwegians, Qataris, Thais, Australians and many other petroleum producing populations, Americans can develop their energy resources in environmentally sensitive areas in a safe and rational manner. "We have to get that message across." NORTH AMERICAN FINANCE OUTLOOK Here's a reasonable hypothesis: with oil prices soaring above $34 per barrel and natural gas prices eclipsing $6 per million Btu, the capital markets in 2000 should have been wide open to North American producers and service companies. Right? Wrong. Put kindly, a skeptical buy side during 2000 was selective in its nibbling at oil and gas-related stocks. Meanwhile, energy issuers themselves weren't that psyched up about parading equity offerings to Wall Street-all this amid the best annual run-up in commodity prices during the past 10 years. Against such a puzzling backdrop, Oil and Gas Investor asked some of North America's top energy financiers to venture their best estimates about investor appetite and capital markets access for the energy industry in 2001. Their collective wisdom: there'll be plenty of dough to grow-both in the public and private markets. Kevin McCarthy, managing director and head of the global energy group for UBS Warburg LLC in New York, notes that 2000 was an ironic year for E&P companies. "Oil and gas prices were very good, but institutional investors didn't believe prices were going to remain that way for long-thus they didn't buy equity. At the same time, upstream companies weren't issuing equity because they felt their stock prices should have been much higher, given where commodity prices were trading." In 2001, as commodity prices retreat to levels that appear more sustainable ($25 oil and $3.80 gas, according to UBS Warburg estimates), both those problems will disappear and the equity markets will come back for producers, says McCarthy. "We're starting to see that not only in secondary offerings for the higher-quality names in the sector such as Evergreen Resources , but also in the recent initial public offerings for Westport Resources and Energy Partners Ltd. , as well as the filing of another for Encore Acquisition Partners ." McCarthy points out that, as upstream companies reset their capex budgets for 2001, those budgets will start to reflect today's healthy commodity price environment. "Last year, a lot of producers were quite properly cautious in their E&P spending and used a lot of their extraordinary cash flow to pay down debt and buy back stock," he says. "Going forward, we believe they're going to use today's strong oil and gas prices as an opportunity to more aggressively drill up and acquire reserves. As that happens, and operators show growth in production and cash flow, investors will become more comfortable and the equity and equity-related markets will turn more positive pretty quickly." Ron Ormand, managing director and head of the U.S. oil and gas group for CIBC World Markets in Houston, also is upbeat. "The fundamentals of the industry have never looked better and we think commodity prices are going to surprise investors on the upside going forward. As a result, there'll be significant opportunity for operators with quality management teams and track records to finance-more so than last year." Ormand also sees increased activity in the M&A market. "Improved commodity prices have strengthened the balance sheets of many producers, and that will allow them to do more acquisitions, particularly of smaller operators that have not participated in the recent upswing in the stock market." The banker also expects an uptick this year in bought deals. "These are transactions where the underwriter purchases stock from an issuer and essentially remarkets that stock overnight," says Ormand. "That's a trend that has been increasing in the U.S. market for several reasons: there's lower execution risk, less time and cost involved versus doing road shows, and it allows the issuer to be more opportunistic about market timing-when the wind is at its back." This past fall, CIBC lead-managed a $100-million bought deal for land driller Patterson Energy of Snyder, Texas. There will also be some improvement in transaction levels in the high-yield market, he says. "The spreads [over comparable Treasuries] have narrowed during the past six months, making the cost of high-yield paper less expensive to the issuer, plus the investor appetite for oil and gas paper has improved during the same time." John W. Sinders Jr., managing director and head of the U.S. energy group for RBC Dominion Securities in Houston, observes that, while oil and gas prices have been high now for a year, a lot of leveraged producers didn't get the full benefit of that commodity-price uptick because they were hedged at lower prices. Also, some of the oilfield service companies haven't had the huge pickup in cash flows one would expect because the anticipated increase in capex spending by the E&P sector has lagged and is only now starting to happen. "For those companies, you'll see a lot of plain equity financing this year aimed at revitalizing their balance sheets," he says. "Then you'll see another group of industry players that are facing a lot of capital spending, as the result of recent discoveries or a pickup in the need for their services. Those companies will do a combination of equity and term debt-generally high-yield and bank debt-because they're not going to want to dilute their future earnings too much." There's also another class of energy companies that are acquisitive, and they're going to require all forms of financing. Says Sinders, "The industry is continuing to consolidate, in the oilfield service, E&P and refining sectors. And as this happens, there's a wide mix of financings being employed-from structured and project financing to bank debt, to public debt and equity issuance-aimed at minimizing the average cost of capital and its impact on the balance sheet." Finally, he says, there's a group of larger-cap energy companies that will use more innovative or opportunistic types of financing structures, such as zero-coupon convertibles, to take advantage of preferential swings in the capital markets and low-cost capital when it's available. Warren G. Holmes, managing director, corporate finance, for FirstEnergy Capital Corp. in Calgary, says that the anticipated high cash flows for Canadian producers in 2001 (as the result of higher commodity prices) mean that very few companies will need incremental external financing, whether that's public equity or bank debt. "So the demand for financing this year in the Canadian energy sector will be relatively low compared with what we've seen in previous years." Explains Holmes, "Right now, producers are aggressively paying down their bank debt, which is prudent, because no one wants to have a huge level of financial leverage at a perceived peak in the commodity price cycle." The banker notes, however, there will be public equity financings this year for Canadian royalty and income trusts, as these investment vehicles try to raise money to pay for acquisitions. "On the debt side, the principal form of activity in the upstream will be the refinancing of existing bank debt at a lower cost of capital." While the public markets may be relatively dormant, Holmes expects the private equity market to heat up this year. "There's a high degree of interest by patient, private investors in financing the Canadian oil and gas industry. Right now, valuations in this industry are relatively low versus where commodity prices are, and those investors see the opportunity for very attractive returns in the long term."