Working with private equity brings its own unique rewards and challenges. The narratives of Ursa Resources LLC and Primary Resources, which both just completed investment cycles and are beginning new ones, offer a guide for others considering the PE-backed model.

The story of Ursa Resources Group LLC is the tale of a team of big-company people who chose to migrate into sequentially smaller E&P companies over time. Despite its small size, Ursa monetized its first iteration as a PE-backed company this past summer, and has announced a new, $200-million commitment. It is the group’s second partnership with Denham Capital Management LP.

By 2008, president Matthew Steele had assembled the team’s nucleus, which set out to explore with its own money. Combining subsurface and land talent from Shell, and operational talent from Southwestern Energy Co., Ursa put together prospects and deals and drilled them. Steele had spent time with both Shell and Southwestern working South Texas, offshore and international plays, and he was with Southwestern just as the Fayetteville shale play was taking off.

Years later, this circumstance gave Ursa an advantage when it landed in the Bakken shale.

Ursa Resources’ Unit 106 rig drilled the Borseth 15-22 #1H in McKenzie County, North Dakota, completing it in March 2011. The well was subsequently sold to Kodiak Oil & Gas Corp. as part of Ursa’s 25,000-netmineral-acre transaction of leasehold in the county. PHOTO COURTESY URSA RESOURCES

“Fundamental to getting into the Bakken was our comfort with the petroleum system. The question is not can I make oil; it’s will I make one barrel a day or 1,000. The answer to that question lies in completion technology,” says Steele.

“There were operators really getting behind single-stage fracture stimulation in a long lateral, even when we started operating,” he says.

When Ursa entered the play, it was assembling and selling acreage packages. In doing so, it grew envious of the opportunities it was seeing. But to really play in the Bakken, Steele knew he needed more capital. He began talks with private-equity firms, including Denham, in early 2009.

Laying the groundwork

“We thought we had found a bird’s nest on the ground,” Steele says of the Bakken at the time. Brigham Exploration had done some horizontal multistage stimulations, and Ursa saw an opportunity to deploy the technology used in the Fayetteville, but the cost was not practical for a company its size. The Denham commitment could not have come at a better time.

When Steele and his team began searching for external capital, oil was $36 per barrel, and despite a number of productive meetings and conversations, the market was slowing. Then, in late 2009, Denham renewed the conversation with Ursa.

“They asked us if we were still working the Bakken,” says Steele. “We still had acreage, and thought we could get more. We thought that Denham would be a strong capital partner and started working with them in earnest.”

Unlike many a newly formed PE-backed company, Ursa was able to sidestep some hurdles.

“It’s weird for a geologist and an engineer to negotiate a commercial lease, but as a small team we had done that previously. You don’t think about all of the background minutia it takes to start a business, but between our experience and the guidance and support Denham provided us, we were able to get started quickly and efficiently,” notes Steele.

He can run off a list of Ursa executives having multiple unofficial titles, such as the chief operating officer who is also the de-facto vice president of HR, handling benefits and the company 401K. The group keeps overhead low and works as a grassroots company.

Bear gets bullish

“When you are on your own, you get good at being ‘efficient,’” quips Steele, who by first-quarter 2010 had the deal with Denham closed and the office running, with the majority of staff in place. Ursa’s original agreed-upon target was to acquire and exploit 50,000 acres, but it was able to hit that target before midyear. Steele and Denham decided to capitalize on Ursa’s momentum and expand the acreage position. In tandem with the effort to gain leasehold, they launched operations.

“It takes an immense amount of work, and there are a lot of moving parts in becoming operational. We put together close to 100 master service agreements prior to commencing drilling,” reflects Steele.

Although the company was running just one rig full time, it had to have BJ Services manage its fracing, and there were numerous small service providers for the array of equipment needed. Drilling in McKenzie County, North Dakota, commenced in late 2010, and the first well was completed on schedule, on plan and within budget tolerance. But costs for everything seemed to be rising nearly as fast as Steele could obtain commitments.

In early 2010, when Ursa finalized its operational budget, it was confident it could execute 30-stage stimulations on a 10,000-foot-deep, 9,000-foot horizontal well for an estimated $7 million—up from more than $6 million six months earlier. By the time the company had secured capital and was drilling in September, costs had risen to $8- to $8.5 million per well for the same program.

In fact, the service-cost increases drove Ursa out of its nonoperating positions in the play, which it had held from its early days in the basin as a way to gain experience.

“Bigger guys were hitting us with AFEs (authorizations for expenditures) for $9- to $10 million. With our investment strategy, we just couldn’t participate in a $9- to $10-million Bakken well, but we were happy drilling for $8 million,” Steele says. During 2010 the company saw an increase of 15% to 20% across its services. At this point, says Steele, scale was needed to keep costs down.

When Denham and Ursa agreed to double the acreage target, the company laid plans to acquire additional acreage and implement a three- to five-rig plan. By fourth-quarter 2010, Ursa had increased its position to 120,000 net mineral acres in the Bakken.

The company put a new-build rig under contract in early 2011 for third-quarter delivery, and had a third rig under negotiation. It was starting to hit its stride, but the basin began tightening up as it went from 90 rigs running in early 2010 to nearly 200 rigs by mid-2011. Services—in particular, fracture-stimulation services—became difficult to obtain.

“When you are on your own, you get good at being ‘efficient,’” says Matthew Steele, president of Ursa Resources Group II LLC.

Timely departure

“We couldn’t get commitments for enough frac fleet to service our drilling plan,” Steele says. That put Ursa in a bind. Steele says some tough debates were had about whether to forge ahead to hold acreage, or concentrate on an operational model with development of a smaller subset of Ursa’s acreage. The choice came down to service availability, and Steele and his team talked with their capital partners about the narrowing window for frac dates. With acreage and a plan in place for up to five rigs, Ursa was staring at support for only two.

“Someone high up in a major service company told us very frankly that he could get us services for two rigs, but after that we were on our own. To develop the our acreage position, we needed more,” Steele says. The company elected to scale back its acreage and began packaging up assets into units for discussions with buyers.

After sales, the company expected to end up with roughly half its former 120,000-acre position. But by midyear 2011, offers had come in on all 120,000 acres. After considering the services situation in the basin, Ursa decided to exit entirely.

“We ended up with more transactions than we planned, which included substantially all of our assets, and rig contracts as well.”

With a new slate, Ursa went back to Denham to discuss the next potential partnership. The result was a commitment for Ursa II. This time the target is a bit different: conventional dry gas. Given the held-by-production-driven drilling in the shales, Steele believes companies will be divesting conventional assets.

Liquids-rich unconventional shale will still be a part of Ursa’s portfolio, however. The company looked at six or seven other plays, including the Eagle Ford, before deciding to focus once more on the Bakken. Steele plans to go back to the team’s research and work on some of the alternatives, in a two-pronged strategy of core, proved developed producing (PDP) conventional gas coupled with liquids-rich new ventures.

“We see an opportunity in gas, which we believe is at or near a floor,” Steele says. Conventional gas assets, in his view—a view Denham shares—are underexploited, and many are economic at current prices.

“That cannot be said of a lot of shale.”

Around the block

In another basin, a veteran E&P team is up to speed on its third business, returning to a familiar area after a stint away. G.R. (Rich) Talley is the chief executive of the company, Tulsa-based Primary Natural Resources. Now in its third iteration, Primary I was founded in 1999 with roughly $15 million in equity as an E&P based on the acquire, exploit and exit model. Focused on the Anadarko Basin, the company did a handful of deals, culminating in the acquisition of the Midcontinent assets of Cox Resources Corp. Talley achieved an exit in 2003 by selling to Newfield Exploration Co. for over $90 million.

Talley followed a similar model for Primary II, chasing the 30% oil-to-gas discount to eastern Wyoming from the Anadarko Basin, which he thought was overplayed at the time. An acquisition from Continental Industries eventually led to an entry into the Powder River Basin, but the company’s core asset ended up being Highlight Field, which it bought from Rim Operating Inc. Drilling and exploiting again led to an exit, this time to Resolute Energy Corp. in 2008.

“I thought there should be good opportunities, and properties should have been hitting the market,” says Talley of market conditions at the time of his third iteration. He discussed his concept with Quantum Energy Partners’ David Bole, who he had come to know over the years. Quantum signed a deal with Primary III in December 2008. With the team in place and a commitment of $100 million in hand, Talley found it easy to get right to searching for assets.

The company hit the ground running and had its first deal by mid-2009. The properties Talley acquired were back in the Anadarko—in Ellis County. The seller was Citrus Energy Corp.

“Those properties are now right in the middle of where Chesapeake and EOG Resources are drilling horizontal Cleveland Sand,” says Talley, who always believed the sands held potential. The 35-year veteran of the play admits, however, that the upside exceeded even his expectations.

When Primary made the acquisition, the company was pursuing a pure producing-property-acquisition strategy, but was having difficulty securing deals at attractive prices. Talley and his team saw horizontal activity under way in the Citrus asset areas, however, and with the strong support of Quantum, expanded out from that acreage using geological analysis.

Over the past year Primary has grown its holdings to more than 30,000 net acres, primarily in Ellis and Custer counties. The company plans to develop and further prove up the acreage, which is already fairly well-defined by offset production.

Currently, Primary is spudding its first well. Talley intends to run one brand new rig—which took a few months to obtain—and, depending on early results, could run more.

G.R. (Rich) Talley, chief executive of Tulsa-based Primary Natural Resources, obtained a $100-million commitment from Quantum Energy Partners, and is back in the Anadarko Basin.

Transition zone

“Once you have an agreement, it’s up to the management team to find ways to invest the equity commitment. We work to come up with ideas and then work with our capital partner on how to best execute around these ideas, ” says Talley. For Primary, this has manifested in an interesting way.

Primary and Quantum have jointly agreed to pursue pure gas deals in addition to developing their liquids-rich plays in Western Oklahoma. To support this effort, Quantum upsized its commitment to Primary. Talley foresees this two-pronged approach becoming a dry-gas-only play following monetization of the horizontal Cleveland assets in a year to 18 months.

The timetable is flexible, as there is no perfect time to monetize. A company exploits to a point, leaving upside for an acquirer.

Even with an existing team, Talley says the first time that operators work with private equity, they may be surprised by the work needed to start up and run the company.

“If someone hasn’t done PE before, they are probably going to be surprised at the things that they have to handle that they wouldn’t have had to do if they were with a big independent before,” he says. Management is responsible for all operations, from finance to HR and IT. Companies need to have the right people to cover the right areas, and Talley suggests hiring a good CFO if the background isn’t already there. Working with PE requires a change in mindset.

“There’s always an adjustment period. No matter who you talk to, they (PE) are going to look at the business more financially, and the management team will be operationally focused,” Talley says. He compares the experience to showing a large project or acquisition to the board or owner of a large independent.

“You are going to have to justify what you want to do. But you do that no matter if it’s your company or you are working at a larger company for someone else.” Overall, the changes have been positive, he notes.

“You want to have the best working relationship you can with your PE group. If you lose that, it’s not near as fun. With Quantum Energy, we’re having fun and building a great company together.”