A multiple choice question: You’ve gotten to the trial you’ve waited two years for. You are presented with a “naked conjecture … “ followed shortly by an “ipsi dixit”. Your reaction:

a. “Finally, something interesting happened at the courthouse.”

b. “No thanks, I’m spoken for.”

c. Rejoice, you won.

Natural Gas Pipeline Company of America v. Justiss is a suit for nuisance brought by homeowners in the vicinity of a loud, stinky gas compressor station. In discussing the court of appeals decision on February 1, 2012 , I focused on the  extent of the continuous noise and noxious odors emanating from the station.  In this opinion the Texas Supreme Court decided that more than a homeowner’s unsupported opinion is required to establish the market value of his home.

The Property Owner Rule v. Speculative Testimony

Texas courts allow a homeowner to testify about the market value of his home without having to be accepted as an expert on land values. However, just as with an expert, the testimony must have a factual basis; it can’t be based on naked conjecture or solely speculative factors. Said another way, the testimony can’t be supported solely on the landowner’s ipse dixit (an arbitrary and unsupported assertion).

The Rules at Work

The jury found that the compressor station was a permanent nuisance and awarded nine plaintiffs a total of $1.2 million in damages for lost property values.

One landowner testified about that he thought the market value had been $650,000, based on sales of property in the area (without identifying specific sales), and that it had diminished to $400,000. Another testified that the noise and odor diminished the value but never referred to “market value”. Others gave a figure for their opinion on the market value of their property but gave no basis.

The fatal flaw in the testimony of each of these witnesses is twofold: They didn’t provide a factual basis for their opinions, and they didn’t testify about how the value had changed because of the compressor station.

The Suit Was Not Time-Barred.

The station opened in 1992. The plaintiffs started complaining soon thereafter about noise and odor (including one who spoke of his “total frustration and torment”).  They finally sued in 1998, more than two years after their first complaints. (Tort suits must be brought within two years of the injury.) NGPA denied for years that there was a problem, stating that the plaintiffs had exagerated or were overly senstive; but when the plaintiffs sued NGPA argued that they waited too long. The court didn’t buy it.  While there was no doubt that the compaints began more than two years before suit was file, the company wcould not be allowed to deny for years that a claim existed and when sued argue  that, for limitations purposes, a claim really did exist during all that time.

The answer is “c”.  NGPA “won” in the sense that the case was remanded for a new trial, not only on damages but on liability as well.

A musical interlude

. . . and I’m here to enforce the law and protect your natural resources . . . as long as it doesn’t  interfere with my other agenda. 

My October 10 post focused on criminal prosecutions and convictions of oil and gas operators in several states for violations of the Migratory Bird Treaty Act. It appears that enforcement of this and other federal wildlife protection statutes is quite selective.

Fox News reports that while oil and gas operators have been fined for causing the death of a few migratory birds (numbering in single and double digits), the wind industry has been exempted from prosecution under the Migratory Bird Treaty Act and the Eagle Protection Act for the destruction of tens of thousands of birds and bats.

Why? Because, proponents believe that such discrimination is necessary to allow the wind industry to compete with other fuel sources. Or maybe it’s because a homely poule d’eau drowned in a noxious pit of crude oil isn’t as tasty a dinner treat for other critters in the forest as a hamburgered golden eagle, ground up, as it were, to promote easy digestion.

For those of you who view Fox as the rightest of the right-wing conspirators, Voice of America reports generally the same news, and that conservation groups are suing wind developers in California and West Virginia.

And the American Bird Conservancy is concerned, as indicated by their Policy Statement on Wind Energy and Bird-Smart Wind Guidelines.

Sadly, as mentioned before in ths space this was to be the science-driven administration.

 By Jonathan Nowlin

The difference between a “draft” and a “check” is explained in Jackson v. Pride Oil & Gas Properties, Inc., a Louisiana case. To the lessor,they might look and feel the same, but in reality they aren’t. “Draft” is a general term for an instrument that directs one person or entity to pay another person or entity. It does not have to be a check; it can be any type of instrument directing payment. A “check” is a special type of draft that is payable on demand – that is, the bank pays the check without first consulting the person who wrote it. With the prevalence of drafts in the oil and gas industry, it was only a matter of time before more litigation on this topic arose.

Lonnie and Betty Lou Jackson gave an oil and gas lease to Pride Oil, with Pride giving the Jacksons a draft—not a check—payable no later than 10 days after the draft’s arrival at the collecting bank. The draft required Pride’s bank, Chase, to get Pride’s authorization before paying the instrument. The day after receiving the draft, the Jacksons took the draft to their bank, BancorpSouth, who in turn sent it to Chase for collection. Pride authorized Chase to make the payment, but Chase did not send the corresponding cashier’s check to BancorpSouth until well beyond the maximum 10-day lead time agreed by the parties.

In the time between the initial deposit to BancorpSouth and the receipt of Chase’s cashier’s check, the Jacksons demanded rescission of the lease for failure to timely pay the draft as promised. Pride refused and the Jacksons sued, claiming Pride violated the agreement because the Jacksons did not receive the money within 10 days of the draft’s arrival at the collecting bank.

According to the court, Pride paid the Jacksons when it authorized Chase to make the payment on the draft. The court explained that a depository bank is the first bank to which a draft is taken for payment, a payor bank is the bank which is the drawee of a draft, and a collecting bank handles the draft merely for purposes of collecting the amount due on the draft and is not responsible for drawing the amount stated on the draft.

Based on this framework the court reasoned, first, that Chase was a collecting bank because it had to receive prior authorization from Pride before issuing a cashier’s check drawn on Pride’s account. Second, a collecting bank is the agent for the owner of the draft. Thus, payment to the collecting bank – Chase – is the same as payment to the owner of the instrument – the Jacksons. As a result, when Pride authorized the payment by Chase, it was the same as paying the Jacksons on that day, which satisfied the 10-day lead time agreement. Thus, the difference between “check” and “draft” was important.

If you are involved in a royalty case, or plan to be, read Occidental Permian, Ltd. v. French et al. The appellate court decided there was no evidence to support the trial court’s findings that the lessors were underpaid. (See my too-long December 6 post for the underlying facts.)  In this case the plaintiffs were the losers.

Takeways (In a hurry? This all you need.)

  • Reliance by an expert on his ”previous experience” is no evidence. Result: Proponent loses.
  • Reliance by an expert on his “historical knowledge in dealings in the business in the industry”, and not on a specific contract, is no evidence. Result: Proponent loses.
  • Reliance by an expert on a hypothetical fact situation that varies from the facts of the case is no evidence. Result: Proponent loses.
  • If an expert doesn’t include every component of a calculation that must be made in order to arrive at a value, there is no evidence that allows the court to arrrive at the value. Result: Proponent loses.

(Before you say “That all obvious.Why didn’t counsel and the court get it?”,  know that in trial things move fast, very fast. Like the TV sports replay, it looks easy in slo mo).

This suit was different from most royalty suits in that it was not about the price paid, but whether the lessors were paid on the proper volume of gas produced. The essential question was whether the evidence showed that Occidental underpaid royalties by deducting an in-kind processing fee paid to Kinder Morgan (KM) from its royalty calculation. The lessors were paid royalties on the 70% of the NGLs retained by the lessee Occidental after paying the in-kind fee to KM, and nothing on residual gas.

No evidence supported the trial court’s finding of underpayment under the comparable-sales method, said the appellate court. The sale price is compared to other sales that are comparable in time, quality, quantity, and availability of marketing outlets. Kuss, the lessors’ expert, failed to support his opinion with an actual sale contract, but rather on his “historical knowledge in dealings in the business in the industry”, and he had no experience selling gas with similar high CO2 content. Thus, his opinion was meaningless. It was entirely based on a hypothetical native gas (with no impurities) rather than the actual CO2–laden casinghead gas that was actually produced from the well. Accordingly, there was no evidence.

The lessors’ attempt to use the net-back method was also unsuccessful. The testimony failed to allocate costs to all of the production and postproduction activities at the Cynara facility. “If any of the activities that took place at Cynara [were] postproduction activities, there is no evidence in the record to support the market value at the well under the net-back method because there are some postproduction costs that have not been deducted, and [it] could not ascertain those costs from the record.”

Under the Fuller lease (a proceeds lease), because the cost of removing the CO2 (a postproduction activity) was not calculated, there was no evidence of the cost of manufacturing, and thus the net proceeds on which the lessees would be paid.

The trial court found that Occidental breached its implied duty to market under the Codgell lease by deducting the in-kind fee paid to KM, thereby obtaining a financial benefit for itself that was not shared with royalty owners. Having found no underpayment of royalty, the court looked for other evidence to support the finding. Lessors’ expert Kuss testified that a reasonably prudent operator would not have accepted the 70/30 split with KM. Because that testimony was based on hypothetical “native gas”, free from impurities, and not the gas stream at issue, the assumed facts varied from the actual facts.  There was no evidence of a breach of the duty.

Here’s wishing you a merrier Christmas than this fellow:  http://www.youtube.com/watch?v=jGFnSqMFQFo

One impediment to the correct resolution of lessors’ claims for unpaid royalties is the complexity of the contractual arrangements between producers and purchasers of production. Occidental Permian, Ltd. v. French et al offers a good example.

It is also a refresher on the basic rules of royalty calculation in Texas and, for royalty owners in suits for unpaid royalties, a look at what the court did and didn’t consider as evidence from experts. This second topic will be the subject of my next post.

Rules of Royalty Calculation (unless the lease says otherwise)

Royalties may not be reduced by production costs; postproduction costs are deducted prior to calculating royalty.

Postproduction costs include taxes, treatment costs to render hydrocarbons marketable, and transportation costs.

In a “market value at the well” lease, the market value of production from a well may be proved by one of two ways: (1) the comparable sales method, or (2) the net-back method.

Under the comparable sales method the sale price is compared to other sales that are comparable in time, quality, quantity and availability of market outlets.

The net-back method involves subtracting the reasonable post-production marketing costs from the market value at the point of sale.

A market-value lease does not give rise to an implied duty to market.

In a proceeds lease the standard of care in testing the performance of the lessee’s implied covenant is that of a reasonably prudent operator under the same or similar facts and circumstances.

The Royalty Clauses

Royalties on the Fuller lease were due on “the market value at the well of one-eighth (1/8th) of the gas so sold or used.”

Under the Cogdell Lease the lessors would receive for gas sold, “1/4 of the market value at the field.” Royalties on “ . . . gasoline and other products manufactured and sold . . . 1/4 of the net proceeds of the sale thereof, after deducting cost of manufacturing the same.”

The leases were subject to unitization agreement establishing a field wide unit for tertiary recovery using CO2 injection.

The Contractual Arrangements

Occidental was the lessee under both leases and operator. The field produced oil and casinghead gas, which was 85% CO2.

Occidental contracted with Kinder Morgan (KM) to supply the CO2 injected into the formation. After production, KM took the casinghead gas stream to its Cynara facility, where it extracted a majority of the CO2 and two-thirds of the NGLs.

KM then sent the CO2 back to the unit for reinjection and sent the remaining gas stream and the separated NGLs to the Snyder Gas Plant, where the remaining CO2 was extracted, the NGLs stabilized, the stream processed for sale, and the remaining CO2 returned to the unit. KM paid a processing fee of 25 cents per mcf to the plant owner, Torch.

Occidental paid KM an in-kind processing fee of 30% of the NGLs and 100% of the residue gas. Occidental paid royalties on 70% of the NGLs and no royalties on the residue gas. The royalty owners sued to recover royalty payments.

The Court’s Analysis

The trial court held that the entire CO2 project – transportation of CO2-laden gas to Cynara and the SGP, extraction of CO2 at both places, and return of CO2 to be re-injected – was all a production activity. The “in-kind” fee was a cost of production improperly charged to French.

The court of appeals considered two issues: (1) Did Occidental underpay royalties under either lease; and (2) Did Occidental breach an implied duty to market under either lease?

Calculation of Royalties

For the Fuller lease the trial court used the comparable-sales method. It determined that market value was equal to the value received by KM under its contract with Torch, minus the in-kind processing fee.

The court then considered the net-back method. The lessors’ damage model only subtracted the 25¢ processing fee KM paid to Torch, assuming that all activities at Cynara were production costs. At least one of the activities performed at Cynara was a post-production activity that operators could charge against royalty: removal of hydrogen sulfide. The costs of H2S removal was not presented to the court. Because that component was missing, there was no evidence to support the market price.

The Cogdell Lease paid royalties based on the net proceeds from the sale of the gas after deducting the costs of manufacturing. As discussed, the removal of H2S was necessary to render the stream marketable. Consequently, it was a manufacturing cost that must be deducted to determine net proceeds. Because the trial court did not deduct this cost, there was no evidence that Occidental had underpaid.

The Implied Duty to Market

The next issue was whether Occidental breached an implied duty to market under either lease. Because the Fuller Lease was a “market-value” lease, there was no implied duty to market.

A duty to market was implied in the Cogdell lease because it was a “proceeds” lease. The trial court had found that Occidental breached its implied duty by deducting the “in-kind” fee paid to KM, thereby obtaining a financial benefit for itself that was not shared with royalty owners. The court of appeals disagreed, for reasons that will be discussed in the next post.

Thanks to Bill Drabble for his assistance on this post.

Merry Christmas again, literally.

By Travis Booher

History tells us that the young friends of Virginia O’Hanlon broke the news to her that there was no Santa Claus. When she quizzed her father about Santa’s existence, Dad’s fatherly advice was to ask the local newspaper.  “If you see it in The Sun, it’s so.” You know the rest of that story.

Another mysterious claus(e), the Maintenance of Uniform Interest provision (the “MUI”), exists in your Joint Operating Agreements. (VIII D of A.A.P.L. Form 610 – Model Form Operating Agreement 1989). The MUI has been referred to as “probably the most violated” and “least enforced” provision of the JOA.  (See Michael E. Curry, A Look at the Maintenance of Uniform Interest Provision in Joint Operating Agreements, State Bar of Tex., 24th Annual Advanced Oil, Gas and Energy Resources Law Course, 2006).  Although seldom discussed, and litigated even less, the MUI exists.

The purpose is to maintain “uniformity of ownership” over the Contract Area. In a nutshell, the MUI prohibits the transfer of an interest covered by a JOA unless such a conveyance includes (i) all of the parties’ interest (e.g., “all of my right, title and interest”) or (ii) a uniform, undivided interest in the Contract Area (e.g. “an undivided 1/2 of my interest in the entire Contract Area”)

The are several rationales for the MUI: (i) protection of the original JOA parties from unwanted third parties, (ii) the inability or cost associated with metering individual wells, and (iii) consistency in voting rights. A standard JOA provides no mechanism for counting votes when ownership is not uniform over the Contract Area. As a result, any breach of the MUI may not be discovered until a voting event arises under the JOA. If, however, a vote is required, a lack of uniformity in ownership will most definitely create an issue.

The scenario for a breach of the MUI is quite common. For example, assume you own a 12.5% working interest in lands covered by a JOA; producing wells are located in the Contract Area. In keeping with the holiday spirit, and in a moment of generosity (or pressure from your beloved), you convey a 5% interest in the #2 Well to your son as a Christmas gift. Although generous and thoughtful, such a conveyance would be a breach of the MUI clause, and it is unlikely the restriction ever crossed your mind as you were enjoying your egg nog. Imagine the same scenario if you sell only specific depths, or certain acreage, or only a couple of leases in the Contract Area.  What if the sale was an arms-length trade for which you were paid good money?

The next time you are considering trading an interest in your producing properties, careful review the MUI clause to avoid a breach (and a potential lawsuit). Similar to Virginia’s mysterious Claus, if the MUI clause is in your JOA, it should not be doubted or ignored. Yes, working interest owner, there is a MUI in your JOA.

A holiday greeting:  http://www.youtube.com/watch?v=rEyV8gnC4aQ

For the purposes of this conversation let’s agree that global warming exists, and let’s not argue about whether it is, as those who use big words say, “anthropomorphic”  “anthropogenic” or, as you and I might say, “man made”.

Bjorn Lomborg doesn’t focus so much on the causes of rising sea levels; he proposes alternative ways to address the effects. In his latest Newsletter he explains why he disagrees with the conventional reactions to the devastation caused by Hurricane Sandy and advises what should be done to avoid future catastrophes.

His points are, among others:

  • The goal of reducing carbon emissions is far too costly for future generations to afford and won’t make a timely difference anyway. The benefits don’t justify the costs.
  • Because of those costs and the delayed effect it is, in his words, “morally irresponsible” to go about protecting coastlines by CO2 reductions. 
  • Carbon cuts won’t be effective for 50 to 100 years, during which time there will be much human suffering that could be avoided.
  • There are better, more practical, and quicker acting ways to address rising sea levels that attempting to reduce CO2 levels.
  • Prominent “environmental experts” such as Robert Redford and New York Mayor Michael Bloomberg attract lots of attention but have it wrong.

Those who doubt Mr. Lomborg’s position will find comfort in several comments posted with the newsletter. 

A blog from Wendell Cox for the National Center for Policy Analysis on California’s Global Warming Solutions Act is an example of what Mr. Lonborg is worried about. The report questions whether cap and trade is a cost-effective way to reduce carbon emissions.   

An appropriate musical interlude ?

It’s deju vu all over again in Chesapeake Operating, Inc. v. Sanchez Oil & Gas Corp. More accurately, it is a variation of Reeder v. Wood County Energy, LLC, et al. applied to Louisiana operations. For the impact of the exculpatory clause protecting the operator from liability in the 1989 Model Form JOA, see my post (co-authored by Marty Averill), “Operator Not Liable for Breach of 1989 Model Form Operating-Agreement, Part Two”. 

This one is a bit different.  Chesapeake and Sanchez entered into a JOA to operate leases in Louisiana. Chesapeake sued Sanchez for failing to pay its proportionate share of drilling and completion costs. Sanchez asserted the defense that Chesapeake had breached the  JOA in, as the court put it, “several ways”,  and did not perform its work in a good and workmanlike manner.

The key issue was the scope of the exculpatory clause, and whether Sanchez was required to prove that Chesapeake acted with gross negligence when it breached the JOA. The clause mirrors Article V.A of the 1977 and 1982 Model Form JOA’s (I assume one of those forms was at issue, but the court didn’t say):

 Chesapeake  . . .  shall be the Operator  . . .  and shall conduct and direct and have full control of all operations on the Contract Area . . .  . It shall conduct all such operations in a good and workmanlike manner, but it shall have no liability as Operator to the other parties for losses sustained or liabilities incurred, except such as may result from gross negligence or willful misconduct.

Sanchez argued that the clause only applied to claims that Chesapeake had not conducted the operations in a good and workmanlike manner; Chesapeake responded that the exculpatory clause also applied to allegations that it breached the JOA.

The court noted that the Fifth Circuit construed an identical clause in Stine v. Marathon Oil Company, and held that protection of the exculpatory clause extended to breaches of the JOA and that the operator was not liable unless its actions were grossly negligent or willful. The court also noted that three Texas appellate courts had reached the opposite conclusion, holding that the clause only applied to claims that the operator failed to act as a reasonably prudent operator.

The court stated that clause would apply to Sanchez’s defenses if Stine controlled but would not apply if the Texas appellate decisions controlled. The court stated that it could only rely on the appellate decisions if they “comprised unanimous or near-unanimous holdings from several—preferably a majority—of the intermediate appellate courts of the state in question.”Here, although the appellate courts were unanimous, they were not a majority of the Texas appellate courts. Thus, the court deemed itself bound to follow Stine.

The clause applied to Sanchez’s affirmative defenses. Because Sanchez had not presented evidence that Chesapeake’s breaches resulted from gross negligence or intentional misconduct, the court dismissed Sanchez’s defenses.

Big and Important Caveat: Chesapeake is a Texas case ostensibly applying Louisiana law. It is not from a Louisiana court.  The parties agreed that Louisiana and Texas law would be identical, so the court looked to Texas cases. I’m sure there are Louisiana non-operators who would (and will) take issue with this result.

Head-scratchers: (1) Is a mineral reservation a fraction of royalty, or a fractional royalty? (2) Is there a difference? (3) Does it matter?

Answers: (1) It depends on how you phrase it. (2) Yes. (3) Yes, if you care about being paid on production, or you are the scrivener of deeds and assignments and want to avoid big trouble, or you pay people based on your interpretation of deeds and assignments and want to avoid big trouble. Otherwise, I guess not.

Moore v. Noble Energy is about the construction of a royalty reservation in a deed executed in 1955, and therefore about the answers to the three questions.

The Grantor reserved “a one-half non-participating royalty interest (one-half of one-eighth of production)”.

The Russells (grantee’s successors) entered into an oil and gas lease with Noble Energy that provided for the payment of a 3/16th royalty. Noble drilled four wells on the property. That’s about the  time everybody started paying attention.  

The Moores (grantor’s heirs) sued, asking the court to declare that they were entitled to one-half of the 3/16th royalty. The Russells argued that the Moores were only entitled to a fixed 1/16th royalty. The court agreed with the Russells.

The court contrasted a fraction of royalty with a fractional royalty:

“A fraction of royalty entitles the owner to a share of the mineral production equal to the stated fraction multiplied by the royalty retained in the lease.”

“A fractional royalty entitles the owner to the stated fraction of gross production, unaffected by the royalty reserved in the lease.”

The court then compared the language typically used to create these interests and concluded that the deed language was typical of that creating a fractional royalty. Given the absence any language indicating that the parties intended to create a fraction of royalty, the court held that the deed was unambiguous and the Moores were only entitled to a fixed 1/16 royalty.

The parenthetical was important in the construction of this reservation. The court observed that the “one-half non-participating royalty” without more would entitle the grantor to 50% of all production, thereby making it virtually impossible to lease in the future. The “(one-half of one-eighth of production)” cleared up any ambiguity, according to the court.

I compare this week’s  musical interlude to the passing game of this year’s LSU football Tigers. Progress is not always forward.  In 1955, the year of this deed, Bilboard’s No. 1 hit was Rock Around the Clock by Bill Haley and the Comets. My October 23rd post was about a 1963 deed. Bilboard’s chart-topper that year was Sugar Shack, by one-hit wonder Jimmy Gilmer and the Fireballs. You decide: Which has better field position?   

Thanks to Bill Drabble for his contribution to this post.

The ghosts of Clinton Manges and people like him continue to haunt executive right owners in Texas. In the 1980’s, Mr. Manges’ abuse of his non-participating royalty owner inspired the Texas Supreme Court to re-affirm the obligations of an executive right owner to the NPRI owner: “utmost fair dealing” and a fiduciary duty.

In Friddle v. Fisher an appellate court went further and imposed on the executive right owner the duty to hold funds belonging to the NPRI owner in a constructive trust for the benefit of the NPRI owner.  The court considered this result to be a remedy for the executive’s breaches and not a duty in and of itself.

Friddle owned a 3/4ths NPRI in the mineral estate in an 84.7 acre tract of land in Hopkins County. Fisher, the owner of the executive right, leased the property. Valence Operating Company drilled an off-site well and pooled the tract into a unit. For nine years, the lessee paid Fisher the entire one-eighth royalty called for in the lease.

Friddle sued, alleging breach of fiduciary duty, unjust enrichment, and conversion. The court ruled in favor of Friddle, holding that Texas law imposes a duty of “utmost fair dealing” on the owner of the executive rights.

But there’s more! The executive owner’s traditional duty to acquire the same benefits for the non-executive interest that he acquires for himself is not his only duty. If he receives royalties rightfully belonging to the NPRI owner, he will be deemed to be acting as a constructive trustee with a duty to hold the funds which would be payable to the NPRI holder for the use and benefit of the NPRI holder.

The court also held that if the executive owner knows the NPRI holder’s name and whereabouts, the executive owner has a duty to notify the NPRI holder of any lease or any other agreement that affects the NPRI holder’s rights. The court did not go so far as to impose a duty on the executive holder to take steps to find the NPRI owner.

Based on the record before it, the court did not impose this liability on Fisher. There was conflicting evidence about whether Fisher knew Friddle’s identity or how to contact him or his predecessors in title. Accordingly, the court ordered a trial so that a jury could make that determination.

What about the NPRI owner’s duty to use reasonable diligence in protecting his interests, as expressed by the Supreme Court in 1998 in HECI v. Neel and its wicked spawn?  That duty was trumped by the executive-right owner’s fiduciary duty. (It’s not the concept in Neel that is odious; rather its application to the royalty owners under those facts was seen by many as unduly harsh). 

Based only on what the court said in this decision, at trial Fisher should be worried about the extent of his obligations, and Fiddle should be concerned about the statute of limitations.