Replies to This Discussion

Permalink Reply by Les Bamburg on April 3, 2012 at 8:26

Larry, the non-operator in a unit can either be taking their share of gas produced in kind and marketing or letting the operator market their share of gas production and receive proceeds from the sale.  

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Permalink Reply by nick waters on April 3, 2012 at 15:32

Larry,

I would like to try to answer your questions, but you won't like the answers. I have been a member here since Spring of 2008 and have read a lot and asked a few questions, but it seems difficult to get a straight answer sometimes, to the simpilest question. Yours however is very complex, so here goes.

 

 I own minerals in Texas only. I work through the TRC website for information about well, transport, etc. So that being said, first I have looked at the "spot prices" you refer to above and found that your price quoted for July 2011 matches the Tenn Gas Pipeline Index published price in Platt's "Inside FERC Monthly Report" . Since I do not know where your lease is, I may be completely off. December 2011 does not coincide with any index I can find in IF or Natural Gas Intellegence report, which are the most widely used published and quoted reports.  So if you can give a little more detailed explanation of these prices you might get closer.

 

Going from 35,000' to 1,000' lets look at the well head price you refer to above. In Lousisana there are about 12+ published index prices that get quoted everyday, for month ahead, gas daily and then cash prices. There are at least 6 major Hubs, that get quoted daily and monthly. This may or may not be interstate pipeline specific. Remember not  all Producers/Traders/Utilities provides the publishers with these prices, so again this leaves a big piece of the pie that cannot be determined. Reporting is not required by any law, but a few years it sure did send a bunch of people to jail for falsifying these prices. Therefore, IMO no one will accurately find out the true "spot market" you are looking for, just what is published.

 

Next you have the gathering systems. These are not requlated by FERC and in Texas let's say they are the "tail that wags the dog" in Austin. You may view their Tariffs, as they are made public a lot of the time, but they do not tell who the other party is. Therefore, you have to be a regulatory wizard just to find what you may be looking for but you will never know who the producer party is. As each tariff is negotiated between parties, ther e are a lot of "Index Prices less a fixed discount mulitplied by a % plus fuel (% or Fixed adder). That is one reason no on can actually nail down the actual price and there may be a published monthly or daily index price assicuated with this or not. This sounds crazy, but those are the facts!

 

Ditto above for the Texas Intrastate Pipelines.

 

Interstate Pipelines are requlated by FERC as I am sure you are aware. They publish Tariff, Rate Schedules, etc. that are approved or disapproved by the FERC. For instance one Interstate Pipeline has 16 diffferent Rate Schedules, which are priced according to the need of specific types of customers (ie Producer, Utiities, Direct Connect Customers, etc.). Components of these Rate Schedules  include pricing for Capacity, Transportation, Commodities, as well as fuel, most of which may or may not be based on Zones or Mileage to or from Hubs or Fields. Lastly, there are still some negotiated rates that are not cover in what we will call "Reqular Rate Schedules". So again, this will probally not help you much either. .

 

I have simply tried to give you bread crumb trail, yet your questions may not have been answered to your satisfaction but I tried. Texas and Lousisana may not have the same legal system, but both have politicians and producers trying to line there pocket first.  Lastly, for those who have "cost free royalties" they are in a better postition than alot of those without the clauses, but due to the numerous index's that might be available I would not bet my last dime they are actually getting a true cost free price. Good Luck and I hope this sheds some light.

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Permalink Reply by Mattie on April 4, 2012 at 7:01

Nick, 

 

Only one correction that I have to your statement - all mid-size to large buyers/sellers ARE required by FERC to report on their fixed price sales, along with daily average volume, to the reporting agencies...in order to more fairly develop/confirm proper daily/monthly index postings for the major publishing companies, such as Platt's, NGI, etc.  It is a requirement, not a choice - and, only the smallest of companies are exempt (based on volume of sales/purchases) after the scandals of the recent past with index-price manipulation by a few bad players within the larger trading organizations. 

Aside from that, you are correct - many moving parts, many different pipeline index postings (including daily, monthly postings), different negotiated gathering rates upstream of a mainline interstate or intrastate delivery point, fuel rates, etc.....that can change the netback price between various parties......

The key issue here is not only the specifics within each owner's lease/contract, but in my mind, also the "fairness" issue of "what is reasonable" versus "what is an unfair attempt to extract incremental profit from midstream infrastructure build-out at the royalty owner's expense".  Having had a career on all sides of the table (royalty owner, ORRI owner, midstream asset owner, marketer/trader), I can see all sides to this - to me, it really comes down to the fairness issue, and to some degree, precedence from historical gas purchases by companies in this area of O&G business.  I know lots of lawyers who take the simple, hard and fast "legalistic, what does your contract specify" approach, and I can agree to some extent....but, I do believe that there is some "raping and pillaging" that IS going on here - otherwise, CHK and others wouldn't be "gloating" about their $7 billion+ midstream asset base they've developed over the past few years.  The difficult question to be answered here is whether a strong court ruling against these subsidiary companies would deter development, which ultimately would harm the royalty owner.  My general rule of thumb is that "if you're a producer, you really don't want to be in the gathering game unless you're forced to".......in some cases, you cannot avoid it because of non-existent or non-competitive cost estimates and/or guarantees (i.e. demand fees/required producer volumetric commitments over a fixed timeframe) required by 3rd party midstream companies....many times based on high-risk assessment on cost recovery in new O&G plays.  So, the producer is somewhat "forced" to build their own systems and market their own product.

It's a risky game, but for me, it still boils down as a point of "fairness" - no absolutes, but fairness.  Allow the producer/gatherers some fair, risk-adjusted ROR on their gathering assets, if allowed under the lease/sublease, and return a portion of any profits to the royalty owners if/when the assets are sold to another 3rd party.   I know, that's recreating "commerce" as we've known it in the O&G industry, but the "fairness" issue somehow needs to be addressed without wrecking the incentives of producers to drill wells.  My guess is that any major ruling against the midstream companies will result in a possible slowdown of activity and the risk assessment in developing these new territories/plays will have a "trickle-down" effect on the net "bonus" or "royalty" that is offered by the producer during lease negotiations.....if so, so be it!!  Everyone wants transparency and fairness, but just like the politics of the day.....trying to police "fairness" and "transparency" has it's own set of problems (logistically) and costs!            

 

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Permalink Reply by DrWAVeSport Cd1 on April 4, 2012 at 7:19

Mattie,

Why do I have two statements from CHK stating sales/price of Dec. 2011 nat gas where $2.38 on their CHK 4th Quarter Dec. 2011 Production Detail Report, and $2.90 on their CHK Operating Inc. document/revenue check?????

Which number is CHK Reporting to FERC ?

Thanks in advance.

 

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Permalink Reply by w.r. frank on April 5, 2012 at 9:26

Dr. Wave,

I have questions and a couple of comments and some data. First, are the volumes and prices based on NG at 15.025 psi (Sonris and royalty statements of HK and PXP) or at 14.65 psi (CHK royalty statements and Owner Relations website)? As a royalty owner, I am not familiar with the reports you mentioned, but would love to see them. Of course, I know from previous posts by you that you are aware that as a UMO you will bear costs of drilling and completing and "post-production" expenses.

I do have some data that will help you evaluate the $2.90 (I assume it is per mcf, but don't know what pressure the volume is calculated-which will affect the $/mcf). Henry has data also, but this may help you:

I have in my possession royalty statements from three lessees for six wells for December 2011 in north DeSoto and south Caddo and I have adjusted the CHK prices to reflect volume at Sonris 15.025 psi so it is apples to apples with HK and PXP volumes and pricing.

Here goes: NYMEX December (based on expiration third business day before end of November)-$3.36/mmbtu; HK--$3.27/mcf; CHK-$3.31/mcf; CHK-$3.30/mcf; PXP-$3.13/mcf; CHK-$2.52/mcf; CHK-$2.51/mcf. Note that the NYMEX is per mmbtu and all well prices  are per mcf. I don't have btu on non-CHK wells so I left all prices per mcf.

What is evident is that most of the prices range from $3.13/mcf to $3.31/mcf so your $2.90 looks low relative to NYMEX, HK, PXP and two CHK wells.

The other two CHK wells at $2.52 and $2.51 are after deducting "post-production expenses." From other data obtained from CHK, the post production expenses on these two wells  range from 60¢ to 66¢/mcf. Add 63¢ average  and you get a adjusted probable NG sales prices on those two wells of $3.14 to $3.15/mcf. Again, your $2.90 looks low, but as an UMO, you are probably getting a CEMI marketing fee of 3%, so .97 of $3.15 is $3.05.

Whether CHK can deduct "post-production" expenses will be decided in another forum.

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Permalink Reply by DrWAVeSport Cd1 on April 5, 2012 at 12:44

wrf,

Thank you for your detailed information.  I am looking for any info I can get per CHK's "accounting" for HS wells.  The more information I gather together, the more "ammo" I have to make a "case" for or against suing. 

Yes.  I too believe $2.90 is low for Dec. 2011.  CHK Operating Inc. Revenue check shows Dec. 2011 Btu 988.  It looks like CHK is charging me 18% of Gross Revenues for Compression and Gathering and Fuel charges...And, another 5.45% to 5% for "Netting Expenses," aka lease operating costs/mo. (However, Dec. 2011 "Netting Expenses" however are a much lower percentage than for previous months...when CHK was saying well had not reached "payout status" yet, and I was not receiving any Revenue checks. ???

Again, CHK has publicly stated that they were cutting "cap ex" costs by 30% , and I have seen an adjustment in those charges beginning with 4th Quarter 2011.  Magic...Isn't It?  LOL

Post production costs for Dec. 2011 look to be $.522/mcf (to me). 

CHK Total deducts for the month of Dec. 2011... 23.47%   A pretty good chunk o' change, plus CHK's low-balled $/mcf price of $2.90 shows me why/how CEMI and CHKM/CMD are making their "profit margins."  

CHK is low-balling all its UMOs and Royalty Owners in the HShale. IMO

That's why GHS "Henry's" numbers are so valuable for me and others to look at and compare to those numbers of other O&G Company Lessors.  Invaluable Information!

Thank you again for your numbers.  I am forwarding your info to legal ears. 

CHK's slight of hand is quicker than the eye...  LOL

DrWAVeSport Cd1 4/5/2012

 

 

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Permalink Reply by w.r. frank on April 5, 2012 at 15:51

Dr Wave,

With all due respect, the percentages are irrelevant. You are a UMO. Let's say (only for discussion purposes) that CHK's actual costs (we can't deal with CHK Midstream now) is 60¢ per mcf for "post-production" costs. If NG revenue is $2.40/mcf, then post production expenses are 25%. If NG revenue is $3/mcf, then it is 20%. If it is $3.60, then it is 16.67%. Since most G&T contracts are based on volume ($/mcf, with guarantees), I see no relevance to %. Price drives the %. Contract G&T per mcf drives the actual cost.

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Permalink Reply by w.r. frank on April 5, 2012 at 16:09

Ok, a new perspective since as a royalty owner I never think about lease operating costs (CHK does not appear to have figured out a way to do this, but any number from CHK is likely to be wrong).

Assume revenue=          $3.15

     Post Production=           .52 (your number)

     LOI                   =           .35 (I have no idea, but could be lower for HA Shale)

Net to UMO            =       $2.28/mcf

We are now within 10¢ of your $2.38/mcf. CHK for a UMO is like having the "back end" of a movie deal. After the sales and marketing costs, you make no money, but everybody enjoyed the premier but you! Your position is worse than mine, but we all are in bed with a snake!                     

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Permalink Reply by DrWAVeSport Cd1 on April 6, 2012 at 4:55

Agreed.

Percentages are just a snapshot of a moment in time for CHK numbers, and just a reference per one month's production/revenues per my minerals.  Life/Numbers/Percentage changes/change daily with CHK. 

At $2/mcf... Revenues just started the "trickling down effect."  At $3, $4, $5, UMOs will see some $$, and so will royalty owners...  But my neighbors that signed CHK leases signed "Company" lease, and they haven't seen any $$ for months.  Of course CHK well is into 21 months of production and production decline is significant.

Last year on GHS, I likened CHK's "numbers game" to the Movie Industry's "Hollywood Accounting game."   It's most well known name:  "Monkey Points."

Yes...  CHK "enjoyed the Premier" and still is EVERYWHERE.  LOL

Not so funny.

What is strange...  CHK Energy Corp. "Accounting" documents show
Sept. 30, 2011 as well payout date with $13K in the green.  But CHK Operating Inc. "back" paid me (in March 2012) on Sept. 2011's Total Production of well. Why?  (Background info... CHK filed severance relief documents with LA for well payout date of Feb. 2011. It sure is a long $1+ million dollar haul to Sept. 30, 2011. ) 

I haven't a clue...  The same way I haven't a clue as to CHK's $2.90 and your $numbers, Mr. Frank, being substantially higher.

What really gets me (in addition to CHK's $/mcf and "cap ex" charges, etc., etc., etc.) is CHK documents stating on One CHK document - the Dec. 2011 CHK Statement of Well Costs And Revenues:  "The costs of drilling, completing and equipping the Mayo 13-16-14 H-1 well where $8,254,389.48 through Dec. 2011."

And on the Second CHK document - the Dec. 2011 CHK Payout Statement:  Expenses Through December 2011: "Drilling and Completion Costs and Equipment Costs total $7,878,442.32." 

What's the difference?  $375,947.37.  The Lease Operating Costs.  Which are added to the Total Expenses to get to the $8,254.389.48 number.

Why do the two CHK documents' "Drilling, Completion and Equipment" costs total differently?   I have asked and asked and asked in writing.  I finally got a CHK Lawyer's response letter from CHK's Mr. Benjamin E. Russ, Divison Counsel, Southern Division, that essentially obfuscates and says nothing except that CHK is  ..."in compliance with said law.  We will continue to provide quarterly reports; however no additional reporting is required."  Signed...Benjamin E. Russ

I hate cliches, but "Where There's A Will, There's A Way... 

And, I still have the WILL.  LOL

DrWAVeSport Cd1 4/6/2012

 

 

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Permalink Reply by w.r. frank on April 5, 2012 at 9:28

Mattie,

Have you read the glowing CHK Midstream reports to shareholders of its exclusive rights to CHK acreage, its 10 year contracts with annual escalations, its guaranteed volumes and its fee based pricing without commodity pricing risk and its industry leading profitability.

With CHK having 49% of the CHKM economic ownership and AMc sitting on the CHKM BoD to assure he can continue to monetize midstream drop down assets while punishing royalty owners with sham sales to CEMI, I doubt that this arrangement will stand up in court.

Also, another strange coincidence. The G&T expenses on a HK operated well jumped approximately 27¢/mcf the month after HK concluded its sale of the remaining 50% ownership to Kinder Morgan. Could this increase in revenue to Kinder have had an impact on the cash price received by HK as it monetized the remainder of its Haynesville midstream assets?

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Permalink Reply by Mattie on May 9, 2012 at 5:43

W.R. Frank,

 

Sorry for the late reply - just saw your post/question of April 5th - short answer is a strong, probable "yes".  Once these E&P companies "monetize" the midstream assets via sale to a 3rd party, the "incestuous" relationship between producer/midstream subsidiaries is severed....unfortunately, the patients (WI owners & royalty owners) are left "pregnant" (i.e. holding the empty bag).  Going forward, the Operator/Seller will then be in the identical position as the royalty owner (cost-wise) on net-back pricing.....only difference is that the Operator has likely recovered ALL, if not substantially more, of its midstream "expenses" while the royalty owner ends up paying the premium....not always the case IF the production/reserves don't hold up longer term and/or other competition comes in and takes the business away.....but, usually the Operator (as part of his deal with the would-be midstream asset purchaser) will lock-in a long term deal at a high gathering rate.....which, to your point, means the royalty owner and all other connected players (aside from the Operator/seller) pay for that "premium" sale price and higher gathering rate.       

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Permalink Reply by Mattie on April 4, 2012 at 10:25

Dr Wave,

Without seeing the documents and knowing exactly what they represent, it would be difficult for me to answer properly - it is possible that the higher-valued price represents the price, prior to gathering & treating deductions while the lower amount represents "after deductions"......not sure.

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