Private capital, in both equity and debt form, is pouring into the E&P space at record levels. In fact, according to one estimate, the top 15 providers of private capital have between them right now some $15- to $20 billion available for investment in the energy sector, primarily targeting E&P start-ups. This robust availability of capital-more than double what the top 15 fund managers invested in the energy space last year-is rivaled only by the demand for that capital by a burgeoning number of newly formed private independents. Says the head of one start-up, "Private capital allows you to achieve growth very quickly for shareholders, without having to be worried about meeting next quarter's production targets, something the public markets force you to do." Still, private-capital providers are becoming more selective about where they park their dough in the upstream. It's not enough any longer for an operator to want equity backing simply to make acquisitions-not in the currently high-priced A&D market. Rather, they're seeking drillbit growth stories that have some unconventional wisdom attached to them. Says one Northeast fund manager, "Right now, our returns are coming from investments in private producers focused on unconventional resource plays like coalbed-methane and tight-sands gas, or on the application of new drilling and completion technologies to hundreds of prospect locations." The operators to which that fund manager is referring? He wouldn't say. But here's a close look at three private E&P companies that very closely fit those profiles and that represent the kind of upstream start-ups now drawing crowds on the private-capital block. Technology driven In 1995, with $100,000 of his own money and $600,000 from the wealthy Leavell family in West Texas, T. Scott Martin formed Ellora Energy, a private Boulder, Colorado-based independent that initially acquired natural gas properties in the Hugoton Embayment in southeastern Colorado and southwestern Kansas. "I was looking to start a debt-free company from the ground up," says Martin, who previously engineered the consolidations of two public Denver producers, Alta Energy and Tpex Energy, into Devon Energy and Kestrel Energy, respectively. Indeed, drilling upwards of five wells per year from 1997 to 2001, Martin grew Ellora's Colorado and Kansas reserves from 10 billion cubic feet (Bcf) to 18 Bcf; daily output, from 1.2 million cubic feet to 2 million. In 2001, he also bought out the Leavell family interest. But the opportunity for quantum growth didn't come until June 2002 when Ellora teamed with Yorktown Energy Partners to acquire a group of East Texas gas properties, including some 20 producing wells and 80 miles of pipeline infrastructure in Shelby County, southeast of Dallas. To make this purchase happen, Ellora contributed all of its Colorado and Kansas properties; Yorktown, an initial $20 million. "When I was with Denver-based BWAB in the late 1980s, I was a reservoir engineer and Jim Wallace, one of the heads of that company, turned me into a horizontal driller through the firm's focus on the Bakken play in North Dakota," says Martin. "What I saw in these East Texas properties was the opportunity to apply leading-edge, horizontal, underbalanced-drilling and underbalanced-completion technologies to a mature basin and develop formations previously passed over by other operators." Applying these technologies to the 6,000-foot James Lime formation and the 3,000-foot Fredricksburg formation in Shelby County, Ellora drilled 22 East Texas wells. In late 2003, it also expanded its footprint in the region-from 25,000 acres to 70,000 acres-through the acquisition of ConocoPhillips properties in Shelby County and across the Texas border in Louisiana. The results: its daily East Texas gas production has ramped up from 7- to 24 million cubic feet while reserves have skyrocketed from 18 Bcf to 160 Bcf. Meanwhile, companywide EBITDA (earnings before interest, taxes, depreciation and amortization) has ballooned from $1.1 million to a year-end 2004 level of $12.6 million. "The whole point of horizontal, underbalanced drilling is to contact as many of the productive zones within a reservoir as possible that contain natural fractures while mitigating reservoir damage and minimizing well-cleanup time prior to hookup," explains Martin. "With underbalanced completions, there are no multi-stage fracs. All of the wells are completed openholed. We therefore don't have to wait weeks on completion units and more weeks, still, for well cleanup. Our wells are hooked up in days. That means we can get our production online quicker and move our rigs more rapidly from one location to the next." With this efficiency, the operator has held finding and development (F&D) costs to 70 cents per thousand cubic feet (Mcf)-despite recent hikes in rig rates and drillpipe costs. Balancing its aggressive East Texas growth profile, Ellora this May acquired Presco Western LLC, a private Denver operator with 550,000 acres in the Hugoton Embayment in southwestern Kansas. "During the next seven to eight years, we'll be applying the nine-component, 3-D seismic we're now using in southeastern Colorado to develop these 550,000 acres in Kansas," says Martin. "In that time, we'll also spend $275 million to drill about 450 wells on our companywide acreage, which we now estimate has proved, probable and possible gas reserves of 600 Bcf." As for the dough to grow, much of it will come out of cash flow. Ellora's Colorado and Kansas gas output is currently selling for $5.50 per Mcf; its East Texas output, for $6.25. "Part will also come from our bank credit facilities with U.S. Bank in Denver, where Mark Thompson is our banker; the remainder, from the public markets." Does this mean an IPO might be in the offing? Says Martin, "We're seriously considering that option because the outlook for valuations appears to be a bit higher in the public markets than the private markets-and because of the upside we see with our drilling runway out through 2013." Tight-sand gas A 25-year veteran of upstream engineering and management positions with Amoco, Union Texas Petroleum, El Paso Energy and Coastal Oil & Gas, Rick Louden already had an impressive portfolio of E&P accomplishments when he and his former Coastal colleagues founded Houston-based Denali Oil & Gas in June 2003. The rationale for this private start-up? "We had generated great results at Coastal focusing on deep, tight-sand gas plays in South Texas in the 1990s and wanted to replicate that success within a private company," says Louden, Denali president and chief executive officer. With a 15-member team that collectively has more than 200 years of E&P experience, particularly in South Texas, Denali got the backing of Quantum Energy Partners and Energy Trust Partners-two private-equity providers-and Walter Oil & Gas, a private Houston-based offshore E&P company. Their total capital commitment: currently $75 million, half of that from Quantum. Denali's initial strategy was to make acquisitions in the $5- to $50-million range around Hidalgo, Starr and Webb counties in South Texas, then grow through workovers and development drilling on the acquired properties. However, with rising market valuations in mid-2003, the company had difficulty finding acquisitions in that price range that still had the potential for significant value enhancement. "So we shifted strategy slightly by making a few acquisitions in the $300,000 to $5-million range and by initiating an exploration and development-drilling program on those properties, targeting the Vicksburg, Wilcox and Lower Frio formations at depths typically between 12,000 to 17,000 feet," says Louden. After spending $5 million on acquisitions, Denali spudded its first well in the Edinburg South Field in Hidalgo County-a 15,500-foot exploratory test-in fourth-quarter 2003. Although the well wasn't successful, the operator drilled another nearby that was-plus three development wells. Overall, between late 2003 and year-end 2004, the company drilled 21 wells, six of them exploratory. As a result, Denali added through 2004 some 40 billion cubic feet equivalent (Bcfe) of reserves and 6.3 million equivalent per day of production at an average all-in F&D cost of $1 per thousand cubic feet equivalent. This includes 23 Bcfe of reserves and 4.6 million equivalent of production from 11 wells in the Edinburg South Field and the Rapture Field in Lavaca County that were sold for $44 million to Pogo Producing in November 2004. "Although that sale left us with daily production of less than 2 million cubic feet equivalent, we have since through additional drilling and acquisitions built daily output back up to a level of 11 million equivalent from 25 wells," Louden says. "With a 2005 capex budget of $30 million to drill 16 wells-about the same number we drilled in 2004-we would expect to add another 5- to 10 million equivalent to daily production this year." While the operator is currently receiving north of $6 for its gas and generating $1.8 million per month in positive cash flow, its South Texas play would be economic even at $4 gas, says Louden. "Part of the reason is that this play is less sensitive to gas prices and service costs than resource plays like the Barnett Shale or the Cotton Valley." Another reason: the company's use of cost-efficient drilling and completion technologies. For instance, oil-based mud systems, combined with PDC (polycrystalline diamond cutter) bits, allow the operator to build its wells 25% faster than many of its competitors, thereby saving it as much as 20% on well and rig-equipment costs. But there's more to the play's economic attractiveness. "The initial flow rates in South Texas tight-sand gas plays are very high," says Louden. "Because of that we can recoup our investment quickly and reinvest. In fact, even though a successful well may cost as much as $4- to $5 million to drill and complete, we're achieving well above our targeted internal return rate of 30%-plus on our wells. We believe there's still a lot of running room left in these plays." Denali plans, when it reaches 20 million cubic feet equivalent per day in output, to sell to a third party and start over again-as a private company. Dual CBM plays At the close of 2000, Darby Seré, former head of Bellwether Exploration Co. in Houston, and Bill Rankin, former Bellwether chief financial officer, put together a holding company, GeoMet Resources Inc., with Yorktown Energy Partners for the sole purpose of buying 80% of GeoMet Inc. in Birmingham, Alabama. GeoMet Inc. had very little capital at the time but 6.9 million cubic feet per day of coalbed-methane (CBM) gas production and 17 Bcf of proved CBM reserves in the White Oak Creek Field in Alabama's Warrior Basin. Seré, now GeoMet Inc. president and chief executive officer in Houston, says, "The five principals who wanted to sell us that 80% stake realized that in the higher gas-price environment they foresaw, the 20% of the company they retained could be worth more than the 80% they were giving up-if capital were applied to their ideas for coalbed-methane development in North America." Their ideas weren't the product of wishful thinking. These were former coal geologists with U.S. Steel who had evaluated CBM projects in 30 countries around the world. Accordingly, following its funding of the $14-million purchase of GeoMet Inc., Yorktown Energy Partners wasted no time committing another $40 million to the company in the form of a senior subordinated credit facility. The result of this capital infusion: GeoMet, today run financially out of Houston and operationally out of Birmingham, began CBM drilling in 2001 on 30,000 leased acres in the Pond Creek Field in McDowell County, West Virginia, just north of the largest CBM project in Appalachia which is controlled by Consol Energy. "Since then, we've drilled 132 coalbed-methane wells in that field-targeting coals at depths ranging from 700- to 2,000 feet-and have grown daily production to 10.5 million cubic feet and net reserves to 80 Bcf, " says Seré. Meanwhile, in 2002, the company began drilling the first of some 120 CBM wells on more than 40,000 leased acres in the Gurnee Field in Alabama's Cahaba Basin, just south of Birmingham. Current daily production from those wells, which target coals ranging in depth from 700- to 4,000 feet, is 4.5 million cubic feet; net reserves, around 126 Bcf. As in the case of the West Virginia wells, the company has a 100% working interest. GeoMet's growth in cash flow and earnings during this period has been no less impressive. Rankin, GeoMet chief financial officer, notes that with average gas-price realizations up from $3.16 per Mcf in 2002 to $6.40 in 2004, the company's EBITDA correspondingly jumped from $3.6 million to $10.3 million while net income shot up from $700,000 to $4.4 million. "The attraction of the CBM business for us is that we're developing significant, long-lived, 20- to 30-year gas reserves at an average all-in F&D cost of 80 cents per Mcf," says Seré. The play's economics are aided by the fact that the company is currently finding seven to 10 coal seams per well to hydraulically frac; that as its well count increases, its unit operating expenses are decreasing; and that unlike the case with conventional wells, gas output from CBM wells actually increases over time as water production from those wells declines. For 2005, GeoMet has a capex budget of $64.6 million, with which it plans to drill 85 net wells, 60 of them in the Cahaba Basin. Comparatively, the company spent $57.2 million in 2004 to drill 86 net wells. "By year-end 2006, we hope to be pushing more than 40 million cubic feet per day of production and 500 Bcf of reserves," says Seré. "At that point, we'll make a decision on the exit strategy for GeoMet, whether that's an IPO or a sale to a third party. A lot depends on the relative values in the A&D market then versus the cash-flow multiples being accorded E&P stocks in the public market."