If your written agreement terminates and you engage in extensive discussions to reestablish the agreement but essential terms are not agreed on, you don’t have a binding contract. So said a Texas court in 2001 Trinity Fund, L.L.C. v. Carrizo Oil & Gas, Inc. Trading a bunch of emails without agreeing on the essential terms doesn’t get it done.

The Agreement

Carrizo owned leases in the Barnett Shale. The leases would expire unless Carrizo began drilling a well. Trinity was interested in participating, so the parties entered into the “Barnett Shale Participation Agreement”. Trinity was to pay a specified portion of the costs by a certain date in exchange for the potential to earn a portion of Carrizo’s leasehold rights. Trinity failed to pay, and the Agreement automatically terminated.

The Emails

The parties began exchanging emails to revive the agreement. Carrizo’s landman sent an email offering to amend the Agreement. Trinity agreed in principle but said that internal issues would have to be resolved first. Later, Trinity said it would have to wait until its investors had executed unspecified documents. Thus, it could not commit to a time to make its first payment.

Alternative drafts of an amending agreement were circulated, with terms that were different than those previously discussed. Trinity never executed any draft and never paid the drilling costs.

Carrizo sued for breach-of-contract, promissory-estoppel, and quantum-meruit.

The Opinion

The appeals court reversed a verdict and judgment for Carrizo that Trinity breached the contract. Because the Agreement would terminate automatically if Trinity didn’t pay by a certain date, and Trinity didn‘t pay, a breach of contract claim could not be based on the Agreement. Instead, the claim was based on the email exchange.

There was no “meeting of the minds”. Because Trinity failed to make a timely payment, Carrizo was relieved of its obligation in the Agreement to allow Trinity to earn leasehold rights. The emails themselves raised many issues which were never resolved in later emails. The emails showed that the “agreement in principle” did not mean that the parties had reached agreement on all of the contract’s basic terms. Trinity was waiting to execute documents with its investors and payment for the costs would only come after those documents were executed.

The evidence did not support quantum-meruit. Carrizo had to prove that it rendered valuable services for Trinity. Because the Agreement had terminated, Trinity could not obtain an interest in the leases. By drilling wells Carrizo had only benefited itself.

There was no evidence to support promissory-estoppel because of a merger clause in the Agreement.

Another Way to Look At It 

One concurring opinion concluded that the breach-of-contract analysis went too far. The email exchange had no agreement on the time of Trinity’s first payment. This term was essential, because the Agreement automatically terminated if Trinity failed to timely pay. The emails indicate that it was still of paramount important to Carrizo. Trinity never made a commitment to pay on a certain day.

A Third Way to Look At It

A third justice agreed there was no contract but disagreed with how the issue was resolved, and invoked the Texas Uniform Electronic Transactions Act.

The parties did not intend to be bound by electronic communications, as required by the Act. The Agreement provided that it could only be amended by a signed writing. Nowhere in the email exchange did the parties agree to waive that provision of the Agreement. Furthermore, the parties’ multiple efforts to obtain signatures on a written amendment negated any inference that the parties agreed to be bound by their emails.”

Did the parties feel like this when their emails failed to result in a deal? I doubt it.

 Here is Something We Know

 A Texas mineral estate owner has an implied easement for reasonable use of the surface estate in developing and extracting the minerals below.

 And a Question

Can the mineral estate owner and his lessee use the easement to produce from a mineral estate that is pooled with the surface estate?

And the Answer

Don’t say yes just yet. Are you thinking that the primary legal consequence of pooling is that production from anywhere on the pooled unit is treated as if it has taken place on each tract in the unit?  And that the easement carries with it the right to use the surface of the tract to produce oil from beneath the surface of that tract regardless of whether oil is comingled with oil from other tracts? You are correct.

BUT, only (and this was the lessee’s/mineral owner’s undoing) if oil is being produced from the subject tract. In Key Operating and Equipment, Inc. v. Hegar, we are reminded that the mere pooling of one tract with another does not guarantee that there is actual production from both pooled tracts.

Contractually, as between a lessor and lessee production from one tract is treated as production from both. BUT, for the purpose of a surface easement there must be actual production from the tract burdened by the easement in order for the mineral owner’s easement to be valid.

The Facts

Hegar purchased the surface estate and 1/4th of the minerals in the Curbo tract, knowing that it was subject to oil and gas leases and that Key used a road on the tract to service wells on the adjoining Richardson tract.

Key had a lease on the Curbo tract, built a road across the tract (part of the larger Rosenbaum-Curbo tract) and in 1994 began using the road to operate wells on the Curbo and Richardson tracts.

The well on the Curbo tract ceased to produce in 2000 and the Rosenbaum-Curbo lease terminated.

The resourceful Key brothers then bought a 1/16th mineral interest in the Curbo tract and leased to Key Operating. They made 40-acre pooled unit—30 acres from the Richardson tract and 10 from Curbo, producing the pooled unit from wells on the Richardson tract, which it accessed using the road across the Curbo tract.

Hegar sued for trespass and for a permanent injunction against continued use of the road. Key argued it could use the road on Hegar’s Curbo tract to access wells on the Richardson tract by virtue of the pooling agreement.

Hegar became unhappy, saying that he couldn’t raise a family “… with a highway running through our property.” (which I recite only as an excuse to offer this musical interlude).

The Accommodation Doctrine

The court found that Key had the same implied easement for use of the Hegar surface estate that existed when it became a lessee of the Curbo tract minerals, and Hegar may not interfere with Key’s right to use the surface estate for the purposes of the easement. But the court invoked the accommodation doctrine to protect Hegar the surface owner from unreasonable use of the surface for Key’s operations.

How was this result accomplished?

It was the evidence. The court accepted testimony of Hegar’s expert that the oil produced from the well on the Richardson tract did not drain from an area beneath the Curbo tract. Incidentally, the expert testified “with reasonable certainty”. The law does not require an expert to testify emphatically that he is absolutely certain of his position.

There are certain cases that litigants and their lawyers find difficult to resolve: Lots of money on the line, two reasonable interpretations of a complicated agreement and, I suspect, parties who seek vindication for their actions. El Paso Field Services, L.P.  v. MasTec North America, Inc. is one of those cases.

The Question:

In a pipeline construction contract, which language prevails: Explicit risk-allocation provisions or due diligence specifications? See my January 25, 2012, blog for the court of appeal ruling on the case (This one is from the Texas Supreme Court).

The Takeaways:

  • A promise in your contract to perform a certain job for a fixed sum will not be excused because of unforeseen difficulties. If you want it any other way, be sure your contract says it.
  • A court’s role is not to redistribute risks and benefits of a contract, but to enforce the allocation that the parties agree upon.
  • If the plaintiffs’ bar were going to write a song to the Supreme Court, it might go like this.

The Facts

El Paso purchased a 1940s-era pipeline and made plans to remove the old pipeline and construct a new one. MasTec bid on the project. Tellingly, Mastec’s $3.6M bid was less than half of any other bid.

The only as-builts El Paso had were from the 1940’s and did not show crossings installed after the pipeline was constructed. MasTec understood the risk of underground surprises, assumed the risk of such surprises, and included a contingency markup in its bid. The problem was that MasTec underestimated the amount of that risk.

A survey found 280 “foreign crossings” along the right-of-way. In reality, there were at least 794 foreign crossings.

The Contract

Among other things, MasTec represented that it (1) had fully acquainted itself with the site, including topography accessibility, sub-surface conditions, and obstructions, (2) had an opportunity to examine the contract documents, scope of work, and existing facilities, (3) would perform all the work for the compensation stated in the contract, and (4) assumed full and complete responsibility for “all risks”.

El Paso represented that it will have exercised due diligence in locating foreign pipelines and utility line crossings, but Mastec was to confirm the location of all such crossings.

The Litigation History

The jury said El Paso breached the contract and awarded MasTec $4.7MM; the trial court took it away (finding that the contract allocated to MasTec the risk of additional costs for foreign pipeline crossings); the court of appeal (2 to 1) reinstated the jury award; the Supreme Court (6 to 3) said the risk of undiscovered foreign crossings was on MasTec. Result: MasTec’s claim was rejected.

The court observed that MasTec could have protected itself by having the contract contain a term that would imply the owners “guarantee of the sufficiency of the specifications”. El Paso did not guarantee the accuracy of the alignment sheets and as-builts.

The Dissent

Three dissenting justices believed that El Paso did not exercise due diligence because it found only 35% of the foreign crossings and not the industry standard 85 to 95%, and that El Paso’s specific duty of due diligence prevailed over the more general risk allocation requirements in other parts of the contract.

“It is better to stop a bad law than pass a good one.” Calvin Coolidge.

Is anybody in Washington listening to Silent Cal? 

What can the energy industry (oil and gas in particular) expect from the Administration in its second term?  Let’s gaze into the crystal ball:

Carbon Tax

The National Center for Policy Analysis predicts a carbon tax. In what is really a position statement on the perils of such a tax, Sterling Burnett acknowledges that there are some benefits that are a preferable to cap and trade. A carbon tax is transparent and that it would be clear to everyone that it is money paid directly to the government, whereas a cap and trade scheme would not.

He concludes that a carbon tax is a bad idea because “there is never a good time for a bad tax.” (There is a position we can believe in) In the sense that a tax on something as important as energy which he called the “foundation of modern society” would affect everyone in virtually every activity they undertake. Further, he considers carbon taxes to be highly regressive and hence a disportionate burden on the poor.

The good news, if it can be believed, is that President Obama says he would never propose such a tax.

NGL Exports

The Wall Street Journal reports that as the Department of Energy reviews the pros and cons of exporting US natural gas, large chemical companies who burn lots of natural gas oppose exporting energy. This would, of course, keep natural gas cheap.  Oil and gas producers argue that exports are positive for the economy, good for the balance of trade, and have other benefits.

Chemical companies are building new plants in the US to capitalize on our cheap energy which in itself is a job creator. They say no one knows what demand may eventually be and exports may hinder economic growth in that way.

Daniel Yergin for one, believes that there are shale fields yet to be tapped and those concludes that exports would be a good thing. The Wall Street Journal says let the market decide.

Keystone Pipeline

The Natural Resources Defense Council thinks the Keystone XL pipeline is a bad idea, arguing that the pipeline would kill more jobs than it creates by reducing investment in “the clean energy economy” and that the pipeline would transport dirty, low high sulfur tar sands oil, which itself uses large amounts of energy and water to produce and clean up. In short, they believe we need to do everything we can to avoid importing tar sands oil to the United States (The link to the NRDC offers more reports and analysis from theri point of view if you are interested, just so you know).

Business Insider believes that the pipeline will be approved, with a few tweaks in the route to avoid environmentally sensitive areas.

The Role of Fossil Fuels in the Obama Energy Policy

From Platts: Jack Gerard, president of the American Petroleum Institute professes to be encouraged that about President Obama’s commitment to oil and gas development in campaign statements leading up to the election.  Huh?

According to Inside Climate News, the congressional lineup has changed with the defeat of several congressmen characterized by this group as opposed to clean energy. This is an indicator of continued pressure to be placed on the president to favor alternative energy sources. (Notice how the Heritage Foundation is “Right Wing” while the environmental groups are not “left wing”).

Taxes

According to Reuters the IPAA and others expect a rough four years, from potential elimination of the intangible drilling cost deduction to increased regulation of carbon dioxide emissions, which will affect coal and oil and gas producers. And they don’t mention potential regulations on fracking, which is on the agenda.

Looking to 2016

I conclude with an exclusive look at the early front-runner for the 2016 Republican nomination .

Regardless of your point of view, here is some wise musical advice.

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