Denbury Resources: The Misunderstood E&P?

Is  Denbury Resources  the most misunderstood oil producer on Wall Street? It sure seems that way, as the Street seems to have missed (or ignored) the real rationale behind September's sale of the company's Bakken acreage to ExxonMobil. The transaction gave Denbury access to two new carbon dioxide flood assets--which we think are immensely valuable--and also opened the door to acquire an additional CO2 source in the near future. We're excited by the exploration and production firm's broader opportunity set in the Rockies, since increased control over CO2 reserves and transportation in the region could lead to opportunities to take advantage of scale and increase returns. Aside from the recent deal with Exxon, we believe other misconceptions related to Denbury's assets merit discussion.

Misunderstanding 1: Selling the Bakken Was a Cash-Out
A casual observer could reasonably surmise that the sale of Denbury's Bakken assets to Exxon was driven by Exxon's desire to bolt on to its existing Bakken position, and that Denbury cashed out while the getting was good. (Within two years of the Encore Acquisition deal in which it acquired its Bakken acreage, Denbury had taken a nascent position and expanded it to 15 thousand barrels of oil equivalent per day of production, at a time when Bakken acreage continues to command attractive prices). We are more inclined to believe the opposite, that Denbury used its Bakken acreage as a bargaining chip to enhance its strategic position with new enhanced oil recovery opportunities and CO2 reserves. In addition to $1.6 billion in cash, Denbury will take control of the Webster and Hartzog Draw fields and gain access to (and potentially ownership of) CO2 reserves from Exxon's LaBarge field in Wyoming.

Hartzog Draw and Webster are attractive assets on their own. In fact, Webster was one of the top 10 fields on Denbury's acquisition wish list. We think, however, that owning additional CO2 reserves at LaBarge could help enhance the firm's strategic advantage in the Rockies--if Denbury can complete the acquisition (the terms of the deal are still under negotiation).

Denbury already owns 2 trillion cubic feet of CO2 reserves in the LaBarge field (out of an estimated 100 Tcf total) through its Riley Ridge and Horseshoe units, but will need to spend $300 million for additional processing and pipeline construction in order to bring volumes on stream and make them available for an EOR project. Acquiring a portion of Exxon's LaBarge reserves, however, would provide immediate access to processing though Exxon's Shute Creek facility and transportation on an existing pipeline, allowing Denbury to defer construction at Riley Ridge. This would free up capital for Denbury to direct toward accelerating other EOR projects or acquisitions of oil fields.

Denbury still will have a sales contract in place for the CO2 if the parties cannot come to terms on an outright sale, but would still need to pursue construction efforts at Riley Ridge, which would limit the capital available to pursue additional oil field acquisitions over the near term.

Misunderstanding 2: Denbury's Strategy Is a Leap of Faith
We think Denbury's strategy is more than a leap of faith on future acquisitions or higher oil prices, as it lends itself to increasing returns to scale. The company already has demonstrable proof of this--it's how it built up its Gulf Coast production base after it acquired the Jackson Dome CO2 field in 2001.

Denbury's approach is straightforward: Acquire a large anchor field that is a prime candidate for CO2 flood, gain access to the source of the CO2, and control transportation of the CO2 by constructing a long (hundreds of miles) pipeline between the two. Then, purchase oil fields along the route of the pipeline to increase production and reserves.

Given the current EOR projects in Denbury's portfolio, along with our best estimates for project scheduling, additional pipeline construction, and reserve recognition, there is a falloff of development projects after 2017, which the company will need to address through acquiring new EOR opportunities. Even though production will grow well beyond 2017, the majority of reserve recognition occurs at the first production response to CO2 injection, and without new projects, reserves will begin to decline. There is no shortage of candidates, but new fields will need to be acquired opportunistically, ideally when oil prices are on the decline and current owners are pinched by the prospect of declining cash flows and flat or increasing lifting costs. Management has demonstrated its acumen in pursuing and executing deals, and we have confidence in its ability to do so in the future, given the large number of maturing oil fields along the path of its Greencore pipeline.

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Consequently, we think returns will grow as the company continues to acquire and exploit additional oil fields along the path of the Greencore pipeline, as it has done with the Hartzog Draw field. These supplementary fields will not bear the cost burden of the main CO2 pipeline (only short extensions or offshoots). Denbury's current finding and development costs are roughly $15 a barrel including pipeline costs and $10 a barrel before pipeline costs. We believe F&D costs of $10 a barrel are a reasonable proxy for bolt-on acquisitions, which should exhibit more favorable economics as a result.

A competitor could arguably duplicate Denbury's efforts in Wyoming; there are plenty of CO2 reserves and EOR candidates. However, the company has said it would probably cost as much as $1 billion for someone to acquire similar levels of CO2 reserves and construct transportation infrastructure. What's more, constructing pipeline in Wyoming is time-consuming. The 230-mile Greencore pipeline took two years to build because of environmental regulations and shortened construction windows to accommodate migratory patterns of wildlife. The time to construct the hundreds of miles of requisite pipeline would leave a competitor several years behind Denbury.

Misunderstanding 3: Denbury's Barrels Aren't as Profitable
Denbury's strategy leaves it in a lonely position on Wall Street, with few comparable companies and less of a following than similar-size firms. The most appropriate comparison for Denbury could be oil sands producers, given the low exploration risk, considerable up-front investment, and long production life, but there are very few pure steam-assisted gravity drainage operators for this type of comparison. Denbury's reserves and production growth numbers (8.7% and 11.6%, respectively, for 2013-16) don't measure up to peers, and the firm's future development and production cost per barrel of $43 stands out as one of the higher in its peer group. However, we think that comparison is short-sighted, as Denbury remains one of the most profitable per-barrel producers in its peer group.

Source: Company filings, Morningstar.

The higher cost structure is driven by two key items. First, Denbury's proved reserves were 87% crude oil in 2011, versus an average across firms of 56.5%, which explains the higher costs (oil has higher lifting costs than natural gas). The second factor is related to the production and transportation of CO2 to be injected into reservoirs, which adds about $5 per barrel in production costs.

Selling prices counteract these higher production and development costs, however. Much of Denbury's reserves are in the Gulf Coast and sell at Light Louisiana Sweet prices, currently on par with Brent Crude at a hefty premium of more than $20 per barrel versus West Texas Intermediate. The combination of higher oil weighting and better selling prices results in Denbury's future revenue per barrel of proved reserves leading the pack, at $82.60 per barrel of oil equivalent, versus an average of $61.10 per boe for the group.

Source: Company filings, Morningstar.

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We note that these figures are based on the firm's 2011 reported numbers, which included the recently sold Bakken acreage. On the whole, we believe the Bakken divesture should improve Denbury's costs levels and profitability. Development costs associated with reserves are higher for unconventional plays since converting undeveloped reserves to developed reserves requires drilling additional wells; this is not the case with EOR. Also, Bakken oil volumes currently sell at a discount to WTI, and as a result, we expect the firm's average realized price for total volumes produced to increase. Production costs will be higher, which is to be expected with EOR production, but we do not believe the increase will exceed the improvement in average realized selling prices.

Misunderstanding 4: Costly EOR Will Cause Below-Average Returns
We expect returns on invested capital to grow to the midteens by 2016, well above our assumed weighted average cost of capital of about 10%. This is a function of increasing production levels on projects that are already under CO2 flood, implementation of new EOR projects already in place (there are no hypothetical field acquisitions baked into our forecast), and a stable oil price above $90 per barrel for the duration of our forecast.

Source: Morningstar estimates.

We do not necessarily think ROICs will level off after 2016. In fact, we see greater opportunity for Denbury to increase returns beyond our forecast period. We are bullish on the firm's prospects as the reach of its CO2 pipeline infrastructure expands, and we reiterate that bolt-on acquisitions along the path of the Green and Greencore pipelines in the Gulf Coast and Wyoming will accelerate production and reserve growth, further improving ROICs.

Misunderstanding 5: Denbury's Strategy Is Overexposed to an Oil Price Collapse
With such a bullish outlook, it is appropriate to ask how Denbury would fare if there were a substantial drop in oil prices. In the latest price collapse, WTI bottomed in the first quarter of 2009 with an average price for the period of roughly $43 per barrel (the actual low in daily prices was in the prior December, at just under $34 per barrel). In a disaster scenario where history repeats itself and oil prices are halved from current levels, we think Denbury would be reasonably insulated against a long-term negative impact to its operations.

The company's hedging program in place would maintain profitable selling prices for a prolonged period. Based on our current long-term assumption for operating costs at $24 per barrel and F&D costs (including pipelines) of $15 per barrel, we estimate Denbury's break-even cost at just under $55 per barrel. With only current hedges in place, the company can remain above break-even. In addition, we think costs themselves would moderately improve under this downside scenario. Denbury's CO2 costs are correlated to oil prices; a falloff in prices would result in lower CO2 costs and would provide additional cushion to a decline in cash flows.

Finally, we note that a transitory drop in prices could yield additional opportunity for Denbury. Such a scenario would lower the value of the very mature oil fields that Denbury seeks to acquire, probably spur current owners to sell their interests in an effort to raise cash in the immediate term, and ultimately help build Denbury's EOR project portfolio for the remainder of the decade.