This Doesn't Sound Good
The article below was sent to me. I am somewhat bothered by the "10-year, 100 percent fixed-fee gathering agreement." That seems to eliminate any competition or motivation to keep gathering costs down. Given the concerns we already have about CHK's higher-than-average deductions for their royalty owners, this does not sound good to me. Does anyone else have a better interpretation of what this means?
Midstream paying $500 mln cash
* Involves 220 miles of pipeline in Louisiana
HOUSTON, Dec 16 (Reuters) - Chesapeake Midstream Partners L.P. CHKM.N> said on Thursday it plans to buy a natural gas gathering system and related assets in the Haynesville Shale from a subsidiary of
Chesapeake Energy Corp (CHK.N: Quote, Profile, Research, Stock Buzz) for $500 million cash.
The acquisition will be financed with a draw on the partnership's revolving credit facility of about $250 million plus $250 million of cash on hand.
The partnership will acquire Chesapeake's 100 percent ownership interest in the Springridge system which consists of 220 miles of gathering pipeline in Caddo and De Soto Parishes in Louisiana .
At closing, the partnership will also enter into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake Energy.
After the deal, Chesapeake Midstream will have about $500 million of additional borrowing capacity on its credit facility.
The deal is expected to close before the end of this year. (Reporting by Anna Driver in Houston; Editing by Tim Dobbyn)
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Replies to This Discussion
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Permalink Reply by buckmaster on
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Henry any dealings involving Chk doesnt sound good.
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Permalink Reply by Frank on
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Let me look for my Enron Annual Reports. That deal seems familiar? Gas trading is getting us.
Enforce your lease payment terms.
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Permalink Reply by Les Bamburg on -
Frank, I am not sure the relevance of Enron Annual Reports since this is not a gas trading transaction and Enron Annual Reports do not include any details on specific transactions.
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Permalink Reply by Les Bamburg on
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Henry, most gathering agreements are done for long term (ie 10 yrs) on a fixed fee basis.
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Permalink Reply by Henry on
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Les,
If this is the case, what is to keep Company A's (let's take Chesapeake out of this for now) subsidiary (who is doing the gathering) from overcharging Company A, and then letting company A pass these higher prices back to the landowner?
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Permalink Reply by Les Bamburg on
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Henry, this is another reason for royalty owners to insure they have sufficient cost detail to evaluate the reasonableness of gathering fees. This is similar to the marketing of the gas sales by an affiliated entity which is a common practice. Most gathering contracts are arms length between non-affiliated parties (ie CenterPoint Energy Field Services with EnCana & Shell).
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Permalink Reply by Henry on
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Les,
The lessee is obligated by RS 31:122 to "operate the property leased as a reasonably prudent operator for the mutual benefit of himself and his lessor." So if he is overcharging for gathering, this is obviously not for the mutual benefit of himself and the lessor. However, as we all know, the problem is that everyone with 5 acres cannot take the lessee to court over something like this. So even if the lessor has sufficient cost detail to know he is being overcharged, what can he do about it?
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Permalink Reply by Les Bamburg on
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Henry, at minimum he can request the operator to demonstrate the basis for the fee is fair and reasonable and consistent with an arm's length transaction.
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Permalink Reply by JD on
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Les B,
I believe the operator in question has already indicated they take a "weighted average" approach when calculating post production costs. That sounds like pulling a number out of the air.
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Permalink Reply by JD on
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Les B,
I suspect an operator would incurr higher post production costs on the initial HS well. The pipeline laid to access the larger pipes down stream might justify higher gathering and transportation costs than say well #2, 3, 4, 5, 6, 7, 8. That doesn't even include the Bossier shale wells which would use the same pipelines.
If by chance the initial post production costs ran in the 22-23% range for the first well, wouldn't it seem logical that the lessor "should" be able to expect that subsuquent wells would have much lower post production costs? Wouldn't it seem reasonable that the so called "weighted average" would and should go down as wells are added to the same section?
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Permalink Reply by JD on
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In case my last comment was confusing, I envision a pipe that goes horizontially along the top edge or bottom edge of a section. All of the HS wells would feed into that same pipe. The BS wells would feed into that pipe as well. I can't help but think the "weighted average" is weighted on the high end on that first well to help the lessee recover the costs of that pipe. I can't help but think the lessor should expect the "weighted average" to go down by the time the second well is drilled.
Any of the experts care to offer an opinion?
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