Two companies consolidating assets around core properties sounds like a simple-enough recipe for success. The transaction can, to apply an over-used meta - phor, be a win-win for both parties.

But what if the negotiations involve a third party and a desire to transact using a like-kind exchange, to keep Uncle Sam away from the table? Then things get really interesting.

Within a four-month window, starting in Sep - tember 2012, Denbury Resources Inc. negotiated with two major oil companies in bringing to a close two transactions, each totaling more than $1 billion. One involved selling prized assets in the Bakken shale to ExxonMobil, receiving in exchange a combination of cash and operating interests in two top oilfields that are candidates for COflooding. The second deal—using proceeds from Exxon that were held in qualified trust accounts—was a purchase from ConocoPhillips of producing properties in an area where Denbury has existing operated fields, the Cedar Creek Anticline (CCA).

This innovative transaction between Denbury and Exxon, which allowed both parties to consolidate assets while keeping the door open for Denbury to complete a tax-efficient like-kind exchange, is Oil and Gas Investor's A&D Deal of the Year.

Signatories to the “exchange agreement” were both Exxon and its resource play-oriented subsidiary, XTO Energy, which will operate the Bakken properties. The agreement provides for the acquisition of 100% of Denbury's Bakken shale assets, consisting of approximately 196,000 net acres in North Dakota and Montana. This expands Exxon's holdings in the region by about 50% to nearly 600,000 net acres. Output from the Bakken properties in the second half of 2012 was expected to be more than 15,000 barrel of oil equivalent per day.

“This agreement provides a strategic addition to ExxonMobil's North American unconventional resource base,” said Andrew Swiger, Exxon senior vice president. Exxon's financial and operating review for 2012 describes the acquisition as giving Exxon a “more significant presence in one of the major US growth areas for onshore oil production.”

Additionally, the acreage is close to existing XTO holdings, enhancing the company's ability “to improve value by use of existing infrastructure and reduced operating costs.”

For Denbury, the collective transactions had multifaceted implications. But the result is a focus on “what we do best,” according to Phil Rykhoek, president and chief executive of Plano, Texas-based Denbury.

“It's turned us into a pure-play enhanced oil recovery (EOR) player using CO,” he says. “Everything that we own is now either a current COflood or a future flood, or a property associated with providing CO.”

Denbury's ownership of significant Bakken properties was a consequence of its earlier acquisition of Encore Acquisition Co. in March 2010. Even though Denbury believed it had obtained the Bakken assets at a good price as part of the larger acquisition, in essence it viewed them as a chip with which to bargain for other properties.

“We never perceived the Bakken would be in our portfolio for an extended period of time, because that wasn't our core strategy,” Rykhoek says. “We've operated assets in numerous shale plays, including the Bakken, Barnett and Haynes ville, but have always found we generate our best rates of return in the COEOR. As a result, we're not a long-term shale player.”

Identifying buyers

As a specialist EOR producer operating in just two regions, Denbury keeps a list of fields that are likely candidates for future COfloods. Preferred are larger fields in proximity to COsources and, ideally, Denbury's COpipeline infrastructure. While it was significantly increasing the value of the Bakken assets through a successful horizontal-drilling program, Denbury began to reach out to potential counterparties who might be interested in the properties

“We contacted about a half-dozen companies that had assets that we would like to obtain for COfloods,” recalls Rykhoek. “The approach we used was that they would have an incentive to do a deal with us because they might want our Bakken properties. And maybe they would therefore let go of fields that they might otherwise not have sold to us.”

The plan worked. Interestingly, both Exxon and ConocoPhillips were among bidders for the Bakken assets, with Exxon the winner. Initial terms called for Denbury to receive $1.6 billion in cash, subject to closing adjustments, plus Exxon's operating interests in its Webster Field in Texas and Hartzog Draw Field in Wyoming. In a second closing, the cash component was reduced to $1.3 billion, with Denbury instead acquiring a one-third interest in Exxon's COreserves backing its Shute Creek plant in Wyoming. This allows Denbury to receive up to 115 million cubic feet per day of COfrom the plant.

Ascribing a value of $350- to $400 million to Webster and Hartzog Draw fields, Denbury realized a value for its Bakken assets that had risen from “very little” as of the 2009 purchase of Encore Acquisition to a “current value of nearly $2 billion,” Rykhoek says.

But it also faced an issue of tax liability on the transaction. If the $1.3 billion in cash proceeds were not used to acquire additional properties in a manner qualifying for like-kind exchange treatment for federal income tax purposes, $500 million in taxes would be due—an outcome that Denbury had to recognize might become reality. “When we did the Exxon trade, we had to make ourselves comfortable with the fact that that may be all we do,” Rykhoek says. ConocoPhillips, however, was in the market again, this time as a seller. “It was really fortunate for us,” Rykhoek says. “Conoco was in the mode of selling assets, and we were able to cut a deal with them for the CCA assets and use up most of the cash proceeds on a tax-efficient basis.”

Having had talks on a possible transaction earlier, Denbury was able to acquire the CCA assets using $1.05 billion of the $1.3 billion in cash proceeds from the Exxon trade that had been deposited in qualified trust accounts.The use of federal rules on like-kind exchanges for the CCA properties, as well as the COreserves acquired from Exxon, allowed Denbury to defer more than $400 million of its potential $500-million cash tax liability.

Would Denbury have predicted such an outcome when it first began negotiations in the oil and gas property market?

“I didn't think it was really a high probabil-

ity,” Rykhoek says. “We were always hopeful that we could take those proceeds and acquire additional assets. But at the time, we didn't know for sure. It worked out very well—better than we probably dreamed.”

A new asset base

In terms of production, Denbury comes away modestly lighter—down less than 2% on a base of approximately 70,000 barrels of oil equivalent per day—as lost Bakken output of just over 15,800 barrels equivalent per day is not quite offset by the 14,600 per day of combined production gained from the Webster, Hartzog Draw and CCA assets. On a 3P basis (proved, probable and possible), reserves net out to a loss of 86 million barrels, as 300 million of 3P barrels lost in the Bakken exceed the 214 million 3P barrels added.

But that math explains only a piece of the puzzle. With only 30% of the proved reserves in the Bakken falling into the proved developed producing (PDP) category, the future development costs associated just with the proved component of the Bakken assets are significant—approximately $1.7 billion. By contrast, the mature properties being acquired by Denbury have relatively small capital requirements. For example, the CCA assets, producing 11,000 barrels of oil equivalent per day, generate sizeable free cash flow.

“The Bakken was a net user of cash, while the CCA assets we acquired require very little cash,” notes Rykhoek. “That trade in and of itself had a pretty dramatic impact in terms of our goal of obtaining free cash flow.”

Rykhoek favors looking at the transactions from a PV-10 (present value discounted at 10%) viewpoint, which points to the combined trades being “slightly accretive to net asset value.” In exchange for the Bakken assets with a PV-10 value of $1.5 billion, Denbury received CCA assets with a PV-10 value of $1.1 billion, plus Webster and Hartzog fields with a PV-10 value of $0.2 billion, as well as after-tax cash proceeds of $0.1 billion. In addition—assuming the transaction represents fair market value—DNR received COreserves with a value of $0.3 billion. “On a PV-10 equivalent basis, we received $1.7 billion for the $1.5 billion we sold.”

Strategically, the acquired properties are a good fit with existing assets. This is perhaps best illustrated in the Rocky Mountain region, where the former ConocoPhillips assets add to Denbury's existing working interest in two CCA fields, Cabin Creek and Pennel, and give Denbury further interests in the nearby East Lookout Butte and Cedar Hill South Unit. With the new properties, Denbury raised its estimates of oil to be recovered from the CCA properties using COfloods to 270 million barrels, up from 200 million barrels previously.

Also in the Rockies, the earlier availability of COsupplies acquired from Exxon makes strategic sense with regard to Denbury's fields slated for COfloods. After initially being used to flood Denbury's Grieve and Bell Creek fields, the COwill be applied to the newly acquired Hartzog Draw Field. This will enable Denbury to defer part of its Riley Ridge COdevelopment.

“It helps us flood Hartzog Draw probably a little bit quicker than if we had to rely on Riley Ridge. It's also another COsource, and we think it's at a reasonable price,” observes Rykhoek.

“We are only just getting started in the Rockies,” he says, noting that the company has built only about 25% of the pipeline infrastructure it will ultimately build in the region.

Economics

It is in the Rockies that the economics of incremental acquisitions are most needed, driving unit costs for infrastructure lower by spreading COpipeline costs over growing volumes. For example, if pipeline costs are about $1 billion, unit costs are just under $4.25 per barrel if COfloods can recover Denbury's recent estimate of 236 million barrels.

But if recovery jumps to 335 million barrels—due to an incremental 70 million barrels in the CCA area and another 25 million barrels at Hartzog Draw as a result of acquiring the ConocoPhillips properties—then the per-unit cost drops to almost $3 per barrel. In the Gulf Coast, per-unit costs similarly fell by almost $1 per barrel with the Webster acquisition from Exxon.

“It is very accretive for us to pick up these additional fields,” Rykhoek notes.

Not surprisingly, economics are further along in the Gulf Coast region, where Denbury started its first COflood project in 1999. The company has about 1,000 miles of COpipeline in place, and “there isn't a lot of additional buildout expected for pipelines in the Gulf Coast,” says Rykhoek. Estimated oil to be recovered using COis 587 million barrels in the Gulf Coast versus 331 million barrels in the Rockies.

In the wake of its asset transactions, says Rykhoek, the company “can now focus on what Denbury does best, COenhanced oil recovery, which we believe offers one of the most compelling rates of return in the oil and gas industry today.”

How good are the returns? Denbury calculates that for every $1 invested in a COEOR project it runs in the Gulf Coast the return is 4.4 times, versus, for example, 2.7 times for an investment in the Bakken.

If he is right, Denbury is the only way to go in terms of pure-play EOR producers using CO. The strategy is “repeatable and sustainable,” says Rykhoek. Visibility is for low-teens compound annual growth in EOR production “for the next decade.”

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