The deal that Chesapeake Energy Corp. made on Monday to sell half its leasehold in the Mississippian Lime was calculated at around $2,500/acre gross, or less than $1,000/acre net, not necessarily the price that the market had been expecting. The lower expected price may be attributed to several things, said analysts: foreign firms getting more savvy about undeveloped leaseholds, the value of the formation, or Chesapeake's hurry to fix its balance sheet.
Chesapeake is selling Sinopec International Petroleum Exploration and Production Corp. about 425,000 net acres, half of its leasehold, in the Oklahoma portion of the play for about $1.02 billion in cash (see Shale Daily, Feb. 26). The purchase, once complete later this year, would lift Sinopec into the Top 10 among Mississippian acreage holders, according to NGI's Shale Daily.
Operators that have developed some of the acreage say that the Mississippian is a hit-or-miss formation, with 450-600 feet of low pressure. It means that drilling costs are low; less horsepower is needed. From spud to release, wells cost about $2.5 million, considerably less than some of the other onshore plays. However, Petro River Oil Ltd. Co-CEO Daniel Smith said last November there was a lot to learn about the play. Probably not all of its 20 million acres extending across southern Kansas and northern Oklahoma are going to be productive, he said (see Shale Daily, Nov. 29, 2012).
That uncertainty, and the knowledge that Sinopec has gained through other onshore ventures, may have led to the less costly price for Chesapeake's acreage, said Wells Fargo analyst David Tameron. "It seems that foreign investors have been less willing over the last few years to come in and pay a large amount for unproven acreage."
SandRidge Energy Inc. in late December 2011 secured a $1 billion joint venture (JV) in about 363,000 net acres -- around $2,750/acre -- in the carbonate formation with Spain's Repsol YPF SA (see Shale Daily, Dec. 27, 2011). A few months earlier SandRidge (SD) secured a JV with Korea's Atinum Partners Co., which gave it a 13.2% interest in about 113,000 net acres for $500 million, or around $4,425/acre.
Analysts with Global Hunter Securities (GHS) and Tudor, Pickering, Holt & Co. Inc. (TPH) said the Chesapeake (CHK) JV is lower than expectations.
"CHK essentially did this deal at the value of current production and reserves ($60,000/flowing and $14.57/boe proved), receiving little to no credit for the 425,000 undeveloped acres it gave up to Sinopec as well," said GHS analysts. "The last two SD JVs were done at much more attractive terms, netting $2,750/acre and $4,425/acre and excluding associated production. CHK was counting on the Miss Lime sale to be one of its big ticket sale items in order to hit its divestiture goal of $5-7 billion in 2013...This deal highlights that CHK still has a long road ahead."
TPH analysts noted that Chesapeake's shares fell 7% on the news "as investors adjust expectations for value of the core Mississippian acreage." The net asset value (NAV) was cut about $3.00 to about $18.00/share "as we fine-tune type curves, shift acreage between Kansas and Oklahoma and reduce prospectivity." TPH's estimate for 2013 liquids was slashed by 3,000 boe/d, versus a midpoint of 170,000 boe/d, "as the transaction included more production than expected..."
How the sale will impact Chesapeake's finances also was on the minds of analysts.
Chesapeake's net production from the leasehold in 4Q2012 averaged 34,000 boe/d, which was 208% higher year/year and 30% more than in 3Q2012 (see Shale Daily, Feb. 22). About 45% of total output in the final period was oil, and 46% was natural gas. Estimated proved reserves at the end of 2012 totaled 140 million boe net.
Chesapeake had 273 producing wells in the Mississippian at the end of December, including 55 that reached first production in the final quarter, compared with 73 in 3Q2012 and 49 in 2Q2012. Forty-six wells have been drilled but are not yet producing; they are awaiting completion and/or are waiting on infrastructure. Eight rigs now are running, a level that is expected to be the same through the year.
The impact is a negative, said Stifel Nicolaus & Co. Inc. analysts, who in January had said they expected Chesapeake to become more aggressive in its asset sales with CEO Aubrey McClendon's retirement, which is set for April 1.
The announcement firmed up Stifel's view that "with the new management team, the company will be hitting the bids on asset sales rather than holding on to assets if the bids are not close to the underlying value." The "transaction metrics are a slight negative if current production from the assets is not included and a clear negative if 50% of existing production is included in the sales price."
Stifel's team said the sale helps Chesapeake move closer to a one-year risked NAV of about $29.00/share; it was trading just above $20/share on Monday. As asset sales progress this year, with up to $7 billion in property sales planned, "the company should be able to close its gap toward its one-year NAV, and we maintain our $25 target price."
Although the price Chesapeake received for the acreage was panned by many analysts, the play hasn't been knocked by exploration chiefs in several of the most recent conference calls to discuss last year's performance.
Last week SM Energy CEO Tony Best said the Mississippian "continues to be encouraging to us, and we're evaluating a number of shale intervals that are on our 120,000 net acres that we believe are prospective for new and significant shale development." SM has about 66,000 net acres in the play.
"The company's currently operating two drilling rigs," Best told analysts. "Excluding the results from two wells that had drilling or completion problems, the average 30-day rate for wells with sufficient data is 475 boe/d. We are making progress on our drilling costs and drilling some longer lateral wells, which we hope will be even more successful."
The problems that Best referred to go back to the formation itself, said COO Javan Ottoson. He explained that one of the wells being drilled in the final three months "actually ran into a karst. We were drilling along the top of the lime and drilled into a shale-filled karst.
"If you're familiar with limestone geology, in a lot of cases, you get a Carlsbad Cavern kind of effect some time along the top of these formations as water moves. And we drilled into a karst that was full of shale and got stuck, and we couldn't get unstuck, and we ended up having to terminate the lateral short."
The other well apparently was hydraulically fractured on the "heel stage into some water-bearing interval, and the well is making a bunch of water," Ottoson explained. "So a couple of drilling problems. What did we learn from that? Well, we're drilling deeper in sections to get away from the karsts. We've also changed to oil-based drilling fluids, which we think helps keep those shales off us. But if you look at the last couple of wells we drilled -- I'm knocking on wood here as I say this -- we drilled some longer lateral wells very successfully with no problems. And I think we've learned a lot from our experience, and we continue to get better."
SM's drilling team "knew" that there were karsts in the formation that it had targeted.
"It's kind of hard to tell on the seismic how bad it is. You can see kind of some wiggles there and think, 'Well, okay, I'm not sure exactly what that is, but it could be a karst.' We really thought we could drill through it, and we need to be able to drill through some of these. And that's why we went to oil-based, to develop all the acreage...
"So we had to drill through one at some point to see how it went. We really think moving to oil-based here is going to help us a lot in terms of dealing with the shales that are in those karsts, and I hope we'll be able to develop most of the acreage with that technique."
It's still early days to project initial returns on investments (IRR) in the play, said Ottoson. Is it better than another onshore formation?
"It's still too early," said the COO. "I will tell you that we're not going to drill anything that's not competitive on our portfolio over the long -- over a period of time. It's still really early in the program. Right now, I would say it's not competitive with the Eagle Ford, the best parts of Eagle Ford, but I hope it will be as we get on with longer laterals and improvements in our drilling costs."
But the Eagle Ford Shale's success won't last forever, said Ottoson.
At this point, SM "may not go whole hog drilling in the Mississippian, we're not going to throw five rigs in there, but that doesn't mean we're going to let all the acreage expire and then have nothing in the pot...once we're done drilling the Eagle Ford either. So you have to maintain the program over the long haul...but certainly, we are looking for projects that will fit in our portfolio rates of return over the long term."'
TPH's team said it was taking a "more conservative view" on the Mississippian's valuation and prospectivity, and it plans to follow the trend of datapoints on well variability. Analysts believe there is "more limited" merger and acquisition interest based on recent transaction values.
"NAV adjustments" are being made for TPH-covered companies in the Mississippian, which include Chesapeake, SandRidge, Devon Energy Corp., Range Resources Inc. and Midstates Petroleum Co. Inc. For Chesapeake, that means a cut of around $3.00 to $18, while SandRidge's is cut "$2/ish to $6" on an adjusted type curve, prospectivity and slower development." For Devon, it's a drop of about $1 on an adjusted type curve, and for Range it's down by about $3.00 to $68 "with more conservative risking" in the play. Midstates was cut by $1.00 on "type curve and prospectivity adjustments."