Several recent M&A data points that involve significant blocks of undeveloped acreage in the Marcellus, Mississippian, Permian and other prolific resource plays bring in the spotlight the dispute regarding the valuation of so called "resource potential" - a somewhat vague metric that is often used in investor presentations as a selling point. Acreage transactions provide an important market test to the concept. In this note, I use M&A examples to illustrate economics and valuation dynamics related to undeveloped acreage.
Chesapeake's Marcellus Sales
Two significant undeveloped acreage divestitures by Chesapeake Energy (CHK) in the Marcellus area were announced last week. In the first transaction, Chesapeake (and its non-operating partner Statoil [STO]) agreed to sell 162,000 net acres in Northeast Pennsylvania, including 51,000 net acres in the prolific Susquehanna County, to Southwestern Energy (SWN) for $93 million in cash. In the second transaction, Chesapeake and Statoil agreed to sell 99,000 net acres in Southwest Pennsylvania, including 10 existing wells, to EQT Corporation (EQT) for $113 million in cash. (I estimate net proceeds from the two transactions to Chesapeake at below $135 million - hardly enough to move the needle for the company as it is facing a ~$3.5 billion budget shortfall in 2013 alone).
While the price per undeveloped acre implied by the headlines ($574/acre in the first transaction and estimated $650/acre in the second transaction) may appear surprisingly low at the first glance, particularly given that in both cases the properties provide exposure to the Marcellus' sweet spots, a closer examination suggests that the pricing was by no means irrational and is certainly not a result of a "fire sale" (both packages have been on the market for quite some time, were broadly marketed and went to the highest bidders). From the acquirer's perspective, cost of purchased acreage is not nearly as low as may appear from the headline figures. In fact, by the time the properties are fully developed, the "fully loaded" cost per acre to the acquirer may come out well above $10,000 per acre.
To explain the valuation math, I turn to the example of the first transaction in which Southwestern acquired 162,000 acres from Chesapeake. As a reminder, the acreage being acquired is located mostly in Susquehanna, Wyoming, Sullivan and Tioga Counties in Pennsylvania and in some areas is a direct offset to Southwestern's acreage, making SWN one of logical buyers.
According to a map from Chesapeake's most recent presentation (below), the acreage is located mostly on the fringes of Northeast Pennsylvania's dry gas sweet spot. It is important to note, however, that the acreage is largely untested and is situated in areas that lack gathering and takeaway infrastructure and therefore have seen very scant offset operator activity. Therefore, it would be incorrect to conclude that the acreage is of marginal quality. To the contrary, drilling results by Cabot Oil & Gas (COG) on its Zick Pad and Reilly Pad in eastern Susquehanna and many well results in northern Wyoming County and northern Sullivan County (in some cases less than five miles from portions of the leases being acquired by Southwestern) suggest that the acreage likely provides exposure not just to the play's Tier 1 areas but also to its Core (which I define as the most productive part of the play where 10+ Bcf EURs can be consistently achieved for ~4,000 laterals).
So why is the per acre price so low? To understand the valuation, let's look at the transaction from Southwestern's perspective. Lease expirations and infrastructure constraints provide the explanation.
The peak of leasing activity in the Marcellus took place in 2008-2009. That was the time when natural gas prices were high ($6-$10/MMBtu) and operators were willing to pay high price for prospective land. At that time, bonuses in the more competitive areas of Northeast Pennsylvania reached $3,000-$4,000 per acre (~15% royalties and 5-year primary term were not uncommon). A typical lease often provides an option to renew for another 4-5 years at a cost similar to the primary lease bonus. Many primary leases are scheduled to expire in 2013-2014 and operators face the dilemma: to give up the undrilled land or to exercise the expensive option.
Let's assume for a moment that after acquiring Chesapeake's acreage, Southwestern attempts to retain by production essentially all of the new acreage (key assumptions and calculations for this scenario are shown in the right-hand column in the spreadsheet below). Southwestern will begin drilling in earnest on the newly acquired acreage no earlier than in 2014. As a result, extension options on many leases will need to be exercised to provide additional time. Assuming $3,000/acre average option cost and additional 4-year term allowed, the total outlay for option exercise would be $450 million (based on 150,000 acres), on top of the $93 million already paid. In addition, Southwestern would need to initiate a 4-rig drilling program (which would double the company's rig count in the Marcellus) and drill ~60 wells/year to satisfy the HBP requirement in the four-year period (I assume here that one well can only hold 640 acres). As a result, incremental capital spending will amount to ~$200-$300 million in 2013 and ~$500-$600+ million in 2014, non insignificant amounts from Southwestern's perspective.
Perhaps the biggest issue is infrastructure availability to handle the ensuing production ramp up from the new acreage. Midstream service providers (the area is dominated by Williams Partners [WPZ, WMB]) have struggled to deploy gathering capacity to meet operators' existing plans: field gathering and compression have been a significant constraint; in addition, high-pressure gathering lines are close to full utilization and major capacity expansions have been typically subscribed few years in advance of in-service dates. Given that incremental production volumes from a four-rig program can translate to as much as ~400 MMcf/d already by the end of Year 2 of the program, gathering capacity, and even takeaway capacity, can be a major issue.
The validity of trying to retain the entire acreage position also comes in question from a cash flow timing perspective. 150,000 acres can yield 1,500+ incremental drilling locations. Given the natural limitations on production volumes, an incremental inventory of that size may require two decades or more to be fully developed. Effectively, the development of less productive areas will end up pushed out into very remote future, making economics of marginal acreage unattractive.
Given that the acquired acreage is almost inevitably a "mixed bag" in terms of its potential productivity and concentration, a more likely scenario is that Southwestern will "cherry pick" the most promising and contiguous parts of the acquired leasehold for option exercise (SWN may also be able to "high-grade" its existing drilling inventory). Assuming that Southwestern decides to keep only 50,000 acres (the "Select Core and Tier 1" column in the spreadsheet above), incremental drilling inventory can be fully developed in ten-fifteen years with a two-rig drilling program. The "fully loaded" cost per acre in this case, including the cost of "idle carry," is ~$12k per acre (at the time when the average well is being drilled). The economic effect of such cost is approximately equivalent to a 1-1.5 Bcf reduction in each drillsite's EUR and can be supported by wells in the Core and Tier 1 portions of the play.
EQT Corporation, the acquirer of Chesapeake's second acreage package, seems to be following such "cherry picking" strategy. EQT has announced that 42,000 acres of the 99,000 acres they are acquiring from Chesapeake will likely expire undrilled. EQT will attempt to hold approximately 50,000 undeveloped acres and, similar to Southwestern, will likely have to exercise expensive extension options on that portion of the acreage. Per acre economics in EQT's transaction are similar to Southwestern's acquisition.
Statoil's Marcellus Acreage Acquisition
In another notable acreage transaction in the Marcellus, in December 2012, Statoil announced acquisition of 70,000 net acres, the majority of which were located in liquids-rich part of the play in Ohio and West Virginia, for $590 million in cash. Statoil estimated the risked resource potential for the acquired acreage at 1.8-3.0 Tcfe net to Statoil. (It is almost ironic that Statoil appears to be a seller of acreage alongside Chesapeake in the two most recent transactions discussed above. It is also surprising that Statoil did not use the opportunity to negotiate a buyout of Chesapeake's interest in the Southwest Pennsylvania package which would be complementary to its September acquisition).
At the time of the acquisition, the properties were producing ~30 MMcfe/d. The acquisition also included a gathering line. Assuming ~$100 million value for the existing production and gathering assets, the transaction valued undeveloped acreage at ~$7,000 per acre.
While on the surface, the valuation is a striking contrast to the ~$650-per-acre valuation in EQT transaction, a closer look shows that the differential is not as wide as it may appear. According to Statoil, approximately half of the acreage it was acquiring was already held by production, while the remaining half had "attractive expiry profile," indicating that Statoil may be able to retain by production the entire acreage position within primary lease terms. As a result, the differential in per-acre valuation relative to the EQT transaction is effectively reduced to $2,000-$3,000 per acre. The remaining differential can be explained by the liquids-rich nature of the properties acquired by Statoil (acreage acquired by EQT appears to be, at least in part, within the dry gas window).
Other Acreage Sales By Chesapeake
The discussion above reminds that undeveloped acreage in "hot" plays, if not held by production, is often a short-shelf-life perishable good.
Building large acreage positions in promising plays, particularly at a time when the play is not sufficiently delineated and cost of land is relatively low, is a strategy that operators often pursue to be able to pick and choose the best blocks to drill upon. The remainder of the position is often relinquished. It would be incorrect, therefore, to extrapolate "drilling location math" - which would be a legitimate tool for limited tracts of land designated for full development - on to the entire lease positions that often include hundreds of thousands and even millions of acres.
From this perspective, some of the valuations that Chesapeake has received in its recent divestiture transactions should not be totally surprising. Particularly notable are the Mississippian Lime JV with Sinopec (SHI) and the 2012 divestiture of the Permian acreage to Chevron (CVX) and Royal Dutch Shell (RDS.A).
Chesapeake's Mississippian Lime JV Transaction with Sinopec
On February 25, Chesapeake announced that it has agreed to sell to Sinopec a 50% interest in its 850,000 net acres in northern Oklahoma, including existing production, for $1.02 billion in cash (no drilling carries). Existing production averaged ~34,000 Boe/d in the 2012 fourth quarter and associated net proved reserves were ~140 MMBoe. In my analysis, the implied valuation per undeveloped acre in this transaction was approximately $800-$1,400. (I assume that approximately half of the proved reserves being sold are PDPs and estimate the PV-10 value of existing production being purchased by Sinopec in the $490-$700 million range, or $7-$10/Boe, based on my decline curve analysis and certain assumptions.) Given that Chesapeake contributed to the Joint Venture its acreage in the core of the play in Oklahoma, the valuation per undeveloped acre in this oil play does not strike as particularly high. The very large size of the acreage position, with likely expiration issues, may explain the conundrum.
Chesapeake's Delaware Basin Acreage Sale To Chevron
On September 12, Chevron announced that it was acquiring from Chesapeake 246,000 net acres, including 7,000 Boe/d of existing net production, in the Delaware Basin in New Mexico. While the acquisition price was not disclosed, I estimate that the price paid by Chevron was in the $850-$1,050 million range (the combined consideration paid for two asset packages, the 246,000 net acres acquired by Chevron and the 166,000 net acres, including 3,000 Boe/d of production, in the Midland Basin acquired by EnerVest, was approximately $1,365 million). Using certain assumptions with regard to future production declines, oil-NGLs-gas mix, and operating economics, I estimate that the amount of proved developed reserves acquired by Chevron was in the 15-20 MMBoe range with an estimated PV-10% value of $300-$450 million, using the current commodity strip prices. The balance of the price paid in the transaction implies a valuation of $1,750-$2,750 per undeveloped acre.
The northern part of the Delaware Basin in New Mexico contains several oil and wet gas plays, both conventional and unconventional, stacked together within several thousand feet of hydrocarbon-bearing rock. The most significant horizontal oil and liquids plays, the Bone Spring Sands and the Avalon (Leonard) Shale, are located primarily in Eddy County and Lea County of New Mexico. Part of Eddy County is also prospective for the deeper Wolfcamp Shale play. In this context, the price paid by Chevron does not strike as particularly high. The implied undeveloped acreage valuation contrasted with several other transactions in the Permian, including Devon Energy's (DVN) $1.4 billion JV with Sumitomo Corp. which implied $7,200 per undeveloped acre and Concho Resources' (CXO) $1.0 billion acquisition of Three Rivers Operating which implied estimated $2,750-$3,500 per undeveloped acre.
Chesapeake's Delaware Basin Acreage Sale To Shell
On September 9, Royal Dutch Shell announced that it was acquiring from Chesapeake 618,000 net acres in the Permian Basin in West Texas for $1.935 billion in cash. The acquisition includes 26,000 Boe/d of existing production. Based on the acreage map provided in the press release, the transaction included acreage in the highly prospective core of the northern Delaware Basin.
(Source: Royal Dutch Shell's September 9, 2012 news release)
The acreage is located primarily in Reeves, Loving and Ward counties of Texas where significant parts of the acquired leasehold are prospective for the oil-bearing 3rd Bone Spring Sands (conventional depositions being developed with horizontal fracturing) as well as the Wolfcamp and Avalon (Leonard) shale "combo" plays. The acreage also includes what appears to be a sizeable exploration tract in the center of Brewster County. By the time of the acquisition, several operators have reported strong drilling results in this area. As an example, Cimarex Energy (XEC) estimates average EUR in its 3rd Bone Spring play in the Ward County at 730 MBoe (the 19 gross wells drilled during the first half of 2012 had average 30-day IP rate of 850 Boe/d, 79% oil) with well costs in the $7.5-$8.5 million range. This translates into very compelling drilling economics, comparable to the better parts of the Bakken and Eagle Ford. In the Wolfcamp, where Cimarex has drilled and completed 24 horizontal wells, the company's 30-day IPs have averaged 6.6 MMcfe/d (47% gas, 23% oil and 30% NGLs), a very impressive result given the very early stage of the play's development, which translates into a still very robust 20%-30% after-tax rates of return based on the $8.0-$8.5 million well cost.
Based on limited disclosed information and using certain assumptions, I estimate that proved developed reserves being acquired by Shell in this transaction are in the 60-80 MMBoe range with an estimated PV-10% value of $900-$1,250 million, using the then current commodity strip prices. The balance of the price paid in the transaction implies a valuation of $1,400-$2,100 per undeveloped acre, assuming the core leasehold position is approximately 500,000 net acres (being unable to better evaluate the Brewster County acreage, I attribute no value to it).
So what is undeveloped acreage worth?
All of the above examples have one characteristic in common: the market test has revealed that the values of, arguably, very high quality (large, often "blocked up" and reasonably well delineated) acreage positions in some of the most prolific resource plays in reality turned out to be not all that high. It is not even obvious if the seller was able to recover total cost of its investment in land (which would include leasing costs, geophysical work, cost of capital, and associated G&A expenses).
The trend appears to be fairly common for the North American E&P industry. Investors often face situations when they need to critically assess the value of undeveloped land positions in companies' asset portfolios. As all the examples above indicate, the analysis may not be straightforward.
In some situations, undeveloped acreage can be very valuable and marketable - some 2012 transactions registered values north of $30,000 per acre (as demonstrated by QEP's [QEP] 2012 acquisition of the South Antelope block in the Bakken or Marathon Oil's [MRO] 2012 purchase of Paloma properties in the Eagle Ford).
On the other hand, in many other situations, undeveloped acreage may we worth… nothing.
Several questions are particularly relevant:
- What percentage of total acreage will the operator be realistically able to hold and what percentage will expire worthless? What is the cost of "rolling" the leases?
- How many decades would it take to fully develop the entire drilling inventory and what is the value of such inventory's "tail"?
- What is the ratio of "resource potential" to proved reserves? (Proved reserves often reflect a five-year PUD conversion plan)
- Is a giant acreage position an accomplishment in capturing valuable land or a reflection of workflow mismanagement and chaotic leasing strategy?
Disclaimer: This article is not an investment recommendation. Any analysis presented herein is illustrative in nature, limited in scope, based on an incomplete set of information, and has limitations to its accuracy. This article is not meant to be relied upon for investment decisions. Please consult a qualified investment advisor. The information upon which this material is based was obtained from sources believed to be reliable, but has not been independently verified. Therefore, the author cannot guarantee its accuracy. Any opinions or estimates constitute the author's best judgment as of the date of publication, and are subject to change without notice.