Exxon Mobil's (XOM) acquisition of Denbury Resources' (DNR) Williston Basin assets announced last week appears to have caused confusion among analysts with regard to the valuation metrics. There appears to be an incorrect perception that the deal's price point falls far below other recent transactions in the play. The complex nature of the deal, which includes a swap of difficult to value assets, is partly to blame.
The M&A market plays a very significant role in validating value of public companies' assets. The in-depth due diligence by sophisticated, well-informed operators as well as the competitive nature of the process are an effective true-up mechanism which can not be matched by analyzing publicly available disclosure. Therefore it may be worthwhile to review the metrics of this transaction in some detail, to understand the implications for Exxon and Denbury, as well as for other Bakken-exposed stocks.
Summary of Valuation
In this transaction, Denbury will receive the following consideration:
- $1.6 billion in cash.
- Interests in two large mature oil fields that are candidates for tertiary oil recovery (CO2 floods), which I value at $570-$735 million (explained in detail below).
- Effectively, a reduction in tax liability, which I estimate at $330-$420 million, due to the like-kind treatment for the acquired assets (I include the likely purchase by Denbury of the CO2 reserves from Exxon).
- Therefore, total consideration paid by Exxon is $2.17-$2.34 billion, while total "cash equivalent" value to Denbury is potentially as high as $2.50-$2.755 billion. The non-cash component of this transaction is significant and seems to be often miscalculated.
Exxon will receive the following assets:
- Estimated 28 MMBoe proved developed reserves (currently producing approximately 15,000 Boe/d). I estimate the value at $750-$900 million.
- Estimated 100,000 net undeveloped acres (118 total net acres) in the highly productive "core" of the Bakken/TFS play.
- Estimated 75,000 net undeveloped acres (80 total net acres) in the less productive Tier II and unproven parts of the Bakken which represent relatively minor portion of the total value (I assign a $1,000 per acre value to this component of the acreage to reflect the "option" value associated with future improvements in recovery).
Therefore, the implied value of the "core" acreage is $12,000-$15,000 per undeveloped acre ($2.2-$2.8 million per location) as seen by Exxon and $15,000-$19,000 per undeveloped acre (or $2.8-$3.5 million per location) as seen by Denbury. This estimate is three to four times higher than what some Wall Street research reports have suggested. The valuation is comparable to other transactions once Denbury's well results and the significant non-operated component of the acreage are taken into consideration. Based on my analysis, if the $2.5-$2.75 billion estimated total transaction value is used, the implied return on future investment is in the low-twenty percent range (assuming future EURs per well in line with those demonstrated by Denbury, an accelerated development program, and no disappointment from the less proven Three Forks interval). The expected return is in line with what was implied by the recent QEP Resources (QEP) transaction (priced at over $40,000 per undeveloped acre for a high quality, contiguous, mostly operated block). The upside to Exxon is from the ability to improve well performance, potential drilling success in the deeper Three Forks benches, higher well densities in the most productive areas, and future secondary EOR (waterfloods).
With the exceptionally active and competitive M&A environment in the Bakken, it would be unreasonable to expect that a significant transaction covering acreage in the very heart of the basin would not be priced efficiently. In this specific case, Exxon is acquiring a very sizeable acreage position in the core of the play at a relatively low price. The company should be able to realize an attractive return once the acreage is fully developed. However, Exxon was able to secure this transaction by offering in exchange some of its legacy assets with a significant potential value.
On September 20, Exxon announced that it has entered into an agreement to purchase Denbury's Bakken assets in North Dakota and Montana. Denbury will receive $1.6 billion in cash and Exxon's interests in Webster Field on the Gulf Coast of Texas and Hartzog Draw Field in Wyoming, both of which are ideal candidates for CO2 flooding and close to Denbury's existing or planned CO2 pipelines. In addition, Exxon has agreed in principle to either sell to Denbury an interest in the CO2 reserves in its LaBarge Field in southwestern Wyoming (purchase price is expected to be in the $200-$250 million range and would reduce the amount of cash received by Denbury) or sell incremental CO2 from that field. If no additional assets are acquired with the cash proceeds in a manner that would qualify for like-kind exchange treatment, Denbury estimates that the tax obligation on the $1.6 billion cash proceeds will be approximately $500 million.
Webster and Hartzog Draw Fields Valuation Analysis
As the first step in this analysis, I estimate the value of the two mature oil fields that Denbury will be receiving as part of consideration for its Bakken assets. The economic value of these fields is very dependent on the availability of CO2 for the enhanced oil recovery. On the Gulf Coast, Denbury is perhaps the only owner of a significant source of relatively inexpensive CO2 (Jackson Dome field). Denbury also controls a private pipeline delivering CO2 to the fields it is flooding. Naturally, Denbury has been successful in acquiring mature fields at attractive valuations per future EOR barrel. The most comparable transaction is Denbury's acquisition of Thompson field on the Gulf Coast of Texas. Thompson is located about 25 miles away from Webster that Denbury is acquiring from Exxon and is similar geologically and economically.
In the Thompson transaction announced during the first quarter of this year, Denbury paid $366 million plus a 5% gross revenue interest (once average monthly oil production exceeds 3,000 Bbl/d after the initiation of CO2 injection). Denbury estimated the PV-10% value of the acquired proved reserves at $239 million based on the GAAP methodology (which requires the use of the market price for CO2). Using a number of assumptions, I estimate the M&A market value of conventional reserves acquired in Thomson field at $175-$210 million. This implies a range of $4.90-$6.25 per barrel of tertiary potential (based on the 45 MMBoe mid-point of the estimated tertiary range, and including the NPV of the 5% royalty). If the valuation per tertiary barrel sounds high, one should consider potential economic benefit to Denbury. In another comparable field, the Hastings, Denbury was able to book 43 MMBoe of reserves with a PV-10% value of approximately $1 billion just two and a half years after assuming the operation of the field. Significant additional reserves will likely be booked as the development progresses. The net present value per barrel booked is approximately $23. Clearly, even at $6 per EOR barrel, acquiring mature fields is highly accretive to Denbury, as long as CO2 reserves are sufficient to cover the development of the newly acquired fields.
In another similar Gulf Coast acquisition of Conroe field in 2009, Denbury paid a much lower price per EOR barrel estimated at $2.20-$2.45 per Boe. However the transaction took place in a very different commodity price environment (much lower oil price; much higher price of natural gas, which is a cost component). General investment sentiment in 2009 in the aftermath of the financial crisis also likely contributed to the lower valuation.
Using the Thompson transaction as a guide and making certain model assumptions for the acquired conventional reserves, I arrive at the following valuation for the two fields that Denbury is acquiring from Exxon:
Importantly, Webster is a very large field. With estimated 900 MMBbls OOIP, it is 50% larger than Thompson. Due to its size, Webster has greater EOR upside and potentially lower development costs per barrel. Hartzog Draw field is smaller than Webster, with estimated 370 MMbbls OOIP, and may have lower oil price realizations due to its inland location. However, given that Exxon is also selling, as part of the package, a significant CO2 resource to be used in the EOR program, the value per barrel that Exxon is giving up is effectively higher (since Exxon had the option of developing the field itself, and Denbury does not have the same bargaining power it enjoys in the Gulf Coast area).
Denbury is allocating "just under" $400 million in value to Webster and Hartzog. Based on the above analysis, this may be overly conservative. The company's valuation would be understandable if Denbury is using GAAP guidelines for Fair Value (which disallow project-specific valuation and would require use of market pricing for CO2).
Assets Being Acquired By Exxon
While Denbury's Bakken assets being acquired by Exxon include approximately 200,000 net acres, only about 60% can be considered "core." Those areas are shown on the map and include Charlson, Cherry, Bear Creek, Murphy Creek, and Lone Butte. I include Camp/Indian Hills in the low-value Tier II bucket given that well results in this area have been inconsistent and weak, and the Three Forks potential remains unproven.
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(Source: Denbury Resources September 20, 2012 Presentation)
The "core" acreage defines the value in this transaction. The economic value per drilling location has a non-linear dependence on the EUR of the well. In addition, the more productive "core" areas will receive priority capital allocation while the development of fringe areas will be delayed. The time value of money further decimates the relative contribution of the Tier II acreage to the total value.
At the end of 2011, Denbury estimated the SEC-10 value associated with the 94 MMBoe of its Bakken proved reserves at $1,512 million. Only 26% of the proved reserves were developed at year end 2011. The SEC-10 value essentially represents a five-year drilling program based on approximately 5 operated rigs and 600-700 MBoe EURs per well, in my assessment. I estimate that it includes approximately 30% of the identified undeveloped drilling locations within the core acreage. (The SEC-10 provides a valuable hint with regard to the potential value of the core acreage, which I derive to be approximately $2.5-$3.0 billion using 10% discount rate and assuming an accelerated drilling program).
Average production from the properties was about 15,200 Boe/d during Q2 2012, of which 88% was oil and natural gas liquids. I estimate proved developed producing reserves at June 30, 2012 at 28 MMBoe (26% of the total 107 MMBoe booked as proved at the end of Q2) and assume 84% oil and NGLs. I estimate the M&A market value of proved developed reserves at $750-$900 million (I use a $90 WTI price deck, 12% estimated M&A discount rate for PDP reserves, and assume 10% upside to the PDP estimate). The balance of the total transaction consideration represents the implied value of undeveloped acreage.
The well result summary presented below illustrates the high quality of the acreage being acquired by Exxon (the list includes operated well completions by Denbury over the past twelve months; only the wells with some production history are included). The two wells in the Charlson area are particularly strong. It should be noted that they were drilled on single-section (640-acre) units. These data imply EURs above 1 MMBoe for long-lateral wells (1,280-acre units).
The wells in the Cherry area show a high degree of consistency and relatively low declines from 30-day average to 90-day average. This may indicate "restricted" production technique which may be used to reduce bottom hole pressure drawdown and to preserve completion integrity. Without knowing longer production history, it is difficult to estimate the associated EURs. I use the 700-800 MMBoe for Cherry area based on this limited information.
Wells in the Camp area show weaker results and may be marginally economic, based on the five wells results in the table.
Implications for Exxon
Exxon's Bakken acquisition is not insignificant even by Exxon's standards. The company will spend over $5 billion to fully develop the acquired property, which will bring total capital deployment to over $7 billion. Without doubt, the quality of the acquired acreage is high and the opportunity is a rare occurrence in the Bakken given the very large size of the package. During the past twelve months Exxon has been working hard to rebalance its North American onshore portfolio that had been strongly biased towards natural gas following the XTO acquisition. The company has been particularly active pursuing leases in the liquids-rich Woodford Ardmore play where it now has over 300,000 net acres and in the Utica where its leasehold stood at 87,000 net acres at the end of the first quarter. In addition to the Bakken (now at 600,000 net acres), Exxon also holds core positions in the Permian (400,000 net acres), the Eagle Ford (90,000 net acres), and the Cardium (235,000 net acres). Exxon will likely continue on the active acquisition path to gain additional weight in unconventional oil that would be commensurate with its size.
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(Source: Exxon Mobil March 12 Presentation)