The Energy Law Blog

The Energy Law Blog

Oil & gas exploration, developmnet, & marketing in the gulf coast

Legal Update: U.S. Department of Justice Gets MARPOL Conviction

Posted in Criminal, Environmental

Last week, a federal jury in Mobile, Alabama, convicted a Norwegian-based shipping company of one count of conspiracy, three counts of violating the Act to Prevent Pollution from Ships (“APPS”), three counts of obstruction of justice and one count of witness tampering.  Three vessel crewmembers were convicted for obstructing justice, violating APPS, witness tampering and conspiracy.  Notably, a fourth crewmember pleaded guilty in October.

According to the Department of Justice, the evidence presented during the two-week trial demonstrated that in January 2010, the shipping company knew that the oily-water separator aboard its vessel was inoperable.  That argument was based in part on an internal corporate memorandum noting that the device could not properly filter oil-contaminated waste water and stating that individuals “could get caught for polluting” if the problem was not addressed.  The government thus argued to the jury that, rather than repair or replace the oily-water separator, the shipping company and crew bypassed the device and discharged 20,000 gallons of oil-contaminated waste water to the sea prior to the vessel’s arrival in the Port of Mobile.

The obstruction of justice convictions were based on the government’s accusation the shipping company and its crew attempted to hide these discharges from the U.S. Coast Guard by making false and fictitious entries in the vessel’s oil record book and garbage record book.  The government also claimed two crewmembers lied to the U.S. Coast Guard about the discharge of sludge and ordered lower ranking crewmembers to do the same.

Based on these convictions, the company could be fined up to $500,000 per count, in addition to other possible penalties.  The crewmembers face a maximum penalty of 20 years in prison for the obstruction of justice charges.  Sentencing is scheduled in Mobile, Alabama, for February 11, 2016. Click here for the Department of Justice press release.

One important take-away from this case is that the investigation, commitment of resources and prosecution of MARPOL criminal cases remains a high priority with the United States Coast Guard and the United States Department of Justice.  As a federal environmental crime prosecutor for twenty-one years in New Orleans, my docket was comprised of many such cases.  Now, in private practice with Liskow & Lewis, I see the trend continuing. If anything, regulations and enforcement actions are increasing. Take for instance, the recent addition of MARPOL Annex VI involving air emissions.

I have learned as a criminal defense attorney that ship owners and operators charged with MARPOL violations are not “bad corporate citizens.”  Indeed, it is clear from my industry talks and discussions with shipping professionals, that companies go to great effort and expense to train their personnel to comply with the regulations.  They do this because it is the right thing to do.  They also know that the cost of non-compliance is worse than any arguable benefit of by-passing the regulations. This is especially true for ship owners who are “vetted” by charterers and cargo interests and a criminal conviction could prohibit a ship owner from doing business with a vital trading partner.

Unfortunately, there is no easy answer for a company to avoid government enforcement actions, even when the company is practicing good corporate responsibility.  Therefore, companies need to prepare for government inspections and prosecutions as they would for a man overboard or any other marine casualty. While preparation alone cannot prevent a criminal prosecution, having a plan in place will help a company minimize its exposure, and the costs of responding to government scrutiny.

A Rose by Any Other Name: Texas Court of Appeals Says Nuisance “Symptoms of Discomfort” Require the Same Proof of Causation as “Disease”

Posted in Environmental, Oil and Gas, Texas

In what may appropriately be called a “swing and a miss”, the Fourth Court of Appeals in San Antonio has rejected plaintiffs’ attempt to avoid the need for medical expert testimony in a toxic tort case by pleading damages for “symptoms of discomfort” instead of disease.  Cerny v. Marathon Oil Corp, et al., No. 04-14-00650-CV,  2015 Tex. App. LEXIS 10364 (Oct. 7, 2015).  The Fourth Court of Appeals confirmed that a strict causation standard applies to claims seeking relief for injuries of any nature allegedly caused by exposure to or migration of toxic substances from oil and gas operations.

Apparently trying to mimic the result in Parr v. Aruba Petroleum Inc., No. 11-01650 (County Ct. at Law No. 5, Dallas County, Tex.), where the jury awarded a nuisance verdict of $2.9 million to plaintiffs living in the vicinity of oil and gas operations, the plaintiffs in Cerny alleged “symptoms typical of discomfort rather than disease,” disclaiming that they were seeking recovery for “personal injury damages.”  The plaintiffs attempted to circumvent the causation requirements for toxic tort cases established in Merrell Dow Pharms. v. Havner, 953 S.W.2d 706 (Tex. 1997) and its progeny requiring plaintiffs to offer expert testimony showing (1) general causation through epidemiological studies, (2) specific causation, and (3) exclusion of other plausible causes with reasonable certainty when there is an absence of direct and scientifically reliable proof of actual causation.

In affirming a trial court’s dismissal of the nuisance and negligence action, the Fourth Court of Appeals concluded that the claim alleged a medical condition (whether it be described as discomfort or disease) caused by exposure to toxic substances and thus was in the nature of a toxic tort claim, thus requiring expert testimony as to causation.  Plaintiff offered only lay witness and non-medical expert testimony, which did not meet the Havner strict causation standard.

The Parr verdict was rendered a few months before the plaintiffs in Cerny amended their petition to include the same “symptoms” language used in Parr.  The Parr case is on appeal at the Fifth Court of Appeals, so it will be interesting to see if the panel follows the Cerny court’s lead and overturns the Parr judgment.  As it stands, the Cerny case will almost certainly have a chilling effect on plaintiffs’ attorneys looking to bring nuisance and negligence claims based on alleged exposure to emissions from nearby oil and gas operations without garnering the necessary expert testimony.

Texas Appeals Court Rules Assignee Retains All Acreage Covered by Assignment Under Retained-Acreage Clause

Posted in Arbitration, Exploration and Production, Industry News, Litigation, Oil & Gas Contracts, Texas

In yet another “retained-acreage” dispute, the Amarillo Court of Appeals recently ruled that an assignee was entitled to retain all acreage covered by the assignment of four leases, where the assignment’s retained-acreage clause invoked the maximum acreage prescribed by the applicable field rules governing proration units, and, in the absence of any such field rules, deemed proration units to be 320 acres.

In XOG Operating, LLC v. Chesapeake Exploration Limited Partnership, XOG sought an interpretation of the retained acreage clause contained in an assignment to Chesapeake of XOG’s lease interests in four oil and gas leases collectively covering 1,625 acres. The assignment provided that:

Upon expiration of the Primary Term of this Assignment . . . [s]aid lease shall revert to [XOG], save and except that portion of said lease included within the proration or pooled unit of each well drilled under this Assignment and producing or capable of producing oil and/or gas in paying quantities. The term “proration unit” as used herein, shall mean the area within the surface boundaries of the proration unit then established by field rules or special order of the appropriate regulatory authority for the reservoir in which each well is completed. In the absence of such field rules or special order, each proration unit shall be deemed to be 320 acres of land in the form of a square as near as practicable surroundings [sic] a well completed as a gas well producing or capable of production in paying quantities. . . .

During the primary term of the assignment, six wells were drilled—five in the Allison-Britt Field and one in the Stiles Ranch (Granite Wash) Field. Field Rule 2 for the Allison-Britt Field provided that, for purposes of a production allowable assignment, the maximum area of a “prescribed proration unit” was 320 acres, and that any unit containing less than 320 acres was, by definition, a “fractional proration unit.” There were no field rules or special orders applicable to the Stiles Ranch Field.

As no pools were formed, the issue regarding how much acreage Chesapeake was entitled to retain under the retained-acreage clause turned on how the parties intended to define a “proration unit” with respect to each well.

XOG argued that the retained-acreage clause was tied to the regulatory framework of the Texas Railroad Commission (“RRC”), this being the common practice in the oil and gas industry according to XOG. Specifically, XOG contended that the amount of acreage designated by Chesapeake in the Statement of Productivity of Acreage Assigned to Proration Units (“Form P-15”) filed with the RRC was controlling for purposes of the retained-acreage clause. In filing a Form P-15, which is used to obtain a production allowable for a given well, the operator must include a certified plat setting out the size and location of the acreage constituting a prescribed proration unit, or fractional proration unit, assigned to the well.

In this case, Chesapeake had chosen not to designate a full proration unit (i.e., 320 acres for the five wells in the Allison-Britt Field) but instead designated fractional proration units for each of the six wells. Because Chesapeake had designated a total of only 802 acres in its Form P-15 filings for the six wells, XOG urged the court to hold that Chesapeake was limited to retaining 802 acres under the retained-acreage clause.

In response, Chesapeake contended that the plain language of the retained-acreage clause showed the parties’ intent that Chesapeake retain the acreage prescribed by the applicable field rules or, in the absence of any field rules, 320 acres per well. Thus, Chesapeake argued it was entitled to retain the full 1,625 acres covered by the assignment because the field rules applicable to the five wells in the Allison-Britt Field established a proration unit of 320 acres per well, and the proration unit of the well in the Stiles Ranch Field, which had no field rules, was 320 acres by express agreement, resulting in Chesapeake being entitled to retain up to 1,920 acres (6 wells x 320 acres), more than that covered by the assignment.

The trial court granted Chesapeake’s motion for summary judgment, holding that Chesapeake was entitled to retain the full 1,625 acres covered by the assignment, and the court of appeals affirmed. Noting that the retained-acreage clause unambiguously defined a “proration unit” to be the area within the surface boundaries of a proration unit prescribed by the applicable field rules, the court of appeals declined to read into the clause an intent to retain only the acreage “designated in the Form P-15 filing as to each well.” Thus, the acreage designated by Chesapeake in its Form P-15 filings for purposes of obtaining a production allowable for a fractional proration unit was immaterial, and Chesapeake was entitled to retain the entire 1,625 acres based on the field rules for the Allison-Britt Field and the deemed proration unit size prescribed by the retained-acreage clause.

Fifth Circuit Rejects EPA’s Overreaching on CAA and MBTA

Posted in Criminal, Environmental, Litigation, Regulatory


The U.S. Fifth Circuit Court of Appeals recently issued an opinion regarding criminal liability under environmental statutes.  United States v. Citgo Petroleum Corp., et al., No. 14-40128, 2015 U.S. App. LEXIS 15865 (5th Cir. Sept. 4, 2015).  In what may be considered a warning shot to overzealous federal prosecutors looking to obtain criminal convictions under the Clean Air Act (“CAA”) or the Migratory Bird Treaty Act (“MBTA”), the Court of Appeals reversed criminal convictions against Citgo related to violations of both Acts at its Corpus Christi refinery.

Citgo’s Corpus Christi refinery operates a wastewater treatment system that sends all oily wastewater to several Corrugated Plate Interceptor (“CPI”) separators.  The water phase (with residual oil) is separated and sent to two equalization tanks, followed by flotation and biological treatment.  The CPI separators have roofs that prevent the release of air emissions, but the equalization tanks (as well as the other downstream equipment) do not.  Following a surprise inspection of its Corpus Christi refinery, Citgo was indicted for violations related to the two open-top equalization tanks.  The district court found Citgo guilty of two counts of knowingly operating two tanks as oil-water separators without CAA emission controls, and three counts of “taking” migratory birds in violation of the MBTA.  Citgo appealed the convictions.

Clean Air Act

The CAA gives the Environmental Protection Agency (“EPA”) authority to issue emission control standards for new sources of pollution that fall within certain source categories.  42 U.S.C. §7411.  EPA exercised this authority to issue regulations controlling volatile organic carbon (“VOC”) emissions from oil refinery wastewater treatment systems.  See Standards of Performance for VOC Emissions from Petroleum Refinery Wastewater Systems, 40 C.F.R. §§ 60.690 to 699 (“NSPS Subpart QQQ”).  Under NSPS Subpart QQQ, refinery operators are required to put roofs on “oil-water separators.”  The regulations define “oil-water separators” in part as wastewater treatment equipment “used to separate oil from water consisting of a separation tank, which also includes the forebay and other separator basins, skimmers, weirs, grit chambers, and sludge hoppers.”  40 C.F.R. §60.691.  The CPI separators used by Citgo contained all the ancillary equipment mentioned in the definition.  While the equalization tanks do have skimmers, they do not contain any of the other ancillary equipment, and oil could only be removed using vacuum trucks.

The Court of Appeals had to determine if the two equalization tanks were “oil-water separators” under Subpart QQQ, therefore requiring that a roof be placed on top to control emissions.  The government argued that any equipment used to separate oil should be considered an “oil-water separator” regardless of whether it contained all the ancillary equipment described in the definition.  However, the Court of Appeals read the phrase “which also includes the forebay and other separator basins” as only modifying the term “separation tank.”  Read that way, the definition requires an oil-water separator to have (1) one or more separation basins, (2) skimmers, (3) weirs, (4) grit chambers, and (5) sludge hoppers.  The Court of Appeals found further support for this reading in the promulgation history of Subpart QQQ, which exempted equipment that would now fall under Subpart QQQ under the government’s reasoning.  Finally, the Court of Appeals noted that the government’s interpretation would be in conflict with NSPS Subpart Kb, which already regulates storage vessels used in wastewater treatment systems.

The Court of Appeals concluded that the equalization tanks were not “oil-water separators” under Subpart QQQ.  Therefore, the Court of Appeals reversed Citgo’s CAA convictions.

Migratory Bird Treaty Act

The MBTA makes it a misdemeanor to unlawfully kill a federally protected, migratory bird.  16 U.S.C. § 703(a); 16 U.S.C. § 707(a).  A violation of the MBTA results in a fine up to $15,000 and six-months imprisonment.  The MBTA protects 1,026 species of birds.  78 Fed. Reg. 65844 (Nov. 1, 2013).

There is a circuit split on whether a person or entity is liable under the MBTA if the person or entity unintentionally, or even accidently, kills a migratory bird.  While the 2nd and 10th Circuits have held defendants liable based on unintentional killing,[1] the 8th and 9th Circuit have required the type of physical conduct typically engaged in by hunters and poachers that is actually directed against wild birds.[2]

In the Citgo case, the Fifth Circuit dove into these uncertain regulatory waters head on.  The district court had held the refinery owner criminally liable under the MBTA after it was discovered that several migratory birds died in the equalization tanks; the two open-top wastewater tanks containing a floating oil layer.  The district court had concluded that an illegal taking under the MBTA can occur even if there is no intentional act directed at migratory birds, and that strict liability only required the actor to have proximately caused the taking.

In reversing the district court, the Court of Appeals concluded that a “taking” under the MBTA is limited to deliberate acts done directly and intentionally to migratory birds.[3]  The government had argued that since the MBTA was a strict liability offense, it necessarily meant that “take” includes acts or omissions that indirectly or accidentally kill migratory birds.  While seemingly agreeing that it is a strict liability offense, the Court of Appeals differentiated between mens rea (the criminal intent) and actus reus (the physical act).  As a strict liability offense, the government does not need to prove that the defendant had a criminal intent.  However, the actus reus must still be proven; in other words, the defendant must still voluntarily commit the physical act of the crime in order to be liable.  According to the Court of Appeals, the criminal act here is to “take”, which based on its common law definition (i.e., “to reduce those animals, by killing or capturing, to human control”), requires an affirmative act directed at the migratory birds.

The Court of Appeals also found support in its analysis of similar wildlife statutes.  Specifically, the Court of Appeals concluded that the use of the words “harass” and “harm” in the Endangered Species Act and Marine Mammal Protection Act results in those statutes including negligent and unintentional acts within the definition of “take,” and found it persuasive that the MBTA does not include those words among the prohibited acts.

The Court of Appeals concluded that “the MBTA’s ban on “takings” only prohibits intentional acts (not omissions) that directly (not indirectly or accidentally) kill migratory birds.”  As a result, the 5th Circuit joins the 8th and 9th Circuit in effectively limiting MBTA takings to deliberate acts done directly and intentionally to migratory birds.


In the final analysis, it appears that the government simply overreached in its charging decisions on both the CAA and the MBTA counts.  On the CAA Subpart QQQ count, the Court of Appeals rejected the government’s “functional interpretation” in favor of a textual reading that was not in conflict with the regulatory history and other regulations.  The take-away there is that the government cannot parse the wording of a regulation to fit the facts of a case when the new interpretation is not supported by the regulatory language.  Regarding the MBTA, the Court in Citgo made clear that in the Fifth Circuit there must be more than simply a dead bird to convict under the MBTA.  The case serves as a warning for federal prosecutors to not rely on a sledgehammer approach when using the “strict liability” element/argument to convict under the MBTA.  Indeed, after Citgo, EPA may be forced to take a more reasoned approach in its enforcement efforts.

[1]           U.S. v. Apollo Energies, Inc., 611 F.3d 679, 686 (10th Cir. 2010); U. S. v. FMC Corp., 572 F.2d 902 (2d Cir. 1978).

[2]           Newton Cnty. Wildlife Ass’n v. U.S. Forest Serv., 113 F.3d 110 (8th Cir. 1997); Seattle Audubon Soc’y v. Evans, 952 F.2d 297, 302 (9th Cir. 1991).  See also U.S. v. Brigham Oil and Gas, L.P., 840 F. Supp. 2d 1202 (D.N.D. 2012).

[3]           The Court of Appeals noted in a footnote that it likely would reach the same conclusion if the indictment had been for “killing” migratory birds instead of “taking”, theorizing that under the MBTA the word “kill” had little to no independent meaning separate and apart from “take.”

U.S. Fifth Circuit Limits Vessels’ Obligations Under Louisiana One-Call Reporting

Posted in Exploration and Production, Industry News, Litigation, Offshore, Pipeline

A panel of the United States Fifth Circuit consisting of Chief Judge Stewart and Judges Jolly and Graves recently issued a per curiam opinion regarding the effect of the Louisiana Underground Utilities and Facilities Protection Law (the “Louisiana One-Call Statute”). Plains Pipeline, L.P. et al. v. Great Lakes Dredge & Dock Co., et al., No. 14-31046, 2015 U.S. App. LEXIS 14337 (5th Cir. Aug. 12, 2015). The Louisiana One-Call Statute requires persons planning to “excavate” to give at least forty-eight hours’ notice, allowing operators of nearby underground facilities time to mark their assets. Noting that “[t]he Louisiana Supreme Court has never interpreted the One-Call Statute’s definition of ‘excavation’” and, the panel made what it termed an “Erie guess” holding that a vessel that anchors without first placing a One-Call does not violate the One-Call Statute. Id. at *4-5.

The case involved a Great Lakes vessel that anchored using both a cutter head (a dredging tool) and traditional anchors to stabilize the vessel. The cutter head, the court noted, penetrated deeper into the seabed than traditional anchors and was used to keep the vessel at a complete stop. The cutter head punctured a pipeline owned by Plains Pipeline that carried product for Phillips 66.

In litigation that followed, Plains and Phillips argued that Great Lakes’ anchoring activity constituted excavation, requiring that Great Lakes provide notice under the One-Call Statute. The district court (Judge Fallon) disagreed, and this appeal followed. The Fifth Circuit affirmed Judge Fallon’s decision, finding that excavation required an element of intent. According to the panel, Great Lakes’ purpose was to anchor, not “movement of the earth.” The panel explained:

The Plaintiffs may well be right that movement of earth is an inevitable result of anchoring, and thus that a person who engages in anchoring does so knowing that he will cause the movement of earth. But under the One-Call Statute, an activity constitutes “excavation” only if the “purpose” – the actual object – of engaging in it is the “movement . . . of earth.” And the object of “anchoring” is, unmistakably, the securing of a ship, not the movement of earth.

Id. at *8 (emphasis in original). The panel based this conclusion mainly on a noscitur a sociis argument. First, each of the examples listed in the One-Call Statute as an “excavation” activity “is an activity in which the movement of the earth is the object, not just a side effect.” Id. at *9 (emphasis in original). Second, “the word ‘excavation’ itself connotes an activity that not only incidentally results in the movement of earth, but is actually aimed at it: that is why no one would say, for instance, that raking leaves constitutes ‘excavation.’”  Id. at *10. Thus, an activity constitutes excavation “only if—unlike anchoring—its actual goal is the movement of earth.”  Id.  The panel also noted that the One-Call Statute is penal in nature. As a result, “Louisiana courts resolve ambiguities in ‘penal’ statutes (such as this one) in the defendant’s favor.”  Id.  Both rationales compelled a ruling in favor of the dredge.

The panel also addressed a subsidiary issue: whether Phillips’ costs it incurred in transporting its oil by alternative means following the allision were precluded by Robins Dry Dock. General maritime law, through Robins Dry Dock, precludes the recovery of economic damages unless the plaintiff can demonstrate sufficient interest in the damaged object. Here, Phillips had argued that it had the exclusive right to the entire capacity of the pipeline and that it was “almost totally responsible” for expenses associated with the pipeline. Id. at *13. The Fifth Circuit held that Phillips’ exclusive use alone did not grant Phillips a propriety interest in the pipeline within the meaning of Robins Id.  Further, Plains retained ownership of the line and was initially responsible for all maintenance and repair costs. Id. at *14. In short, Phillips argument was rightly dismissed under the longstanding rule of Robins.

The Plains Pipeline decision is a concerning one for companies that operate submerged or buried pipelines. In essence, the decision suggests that a person or entity not having an intent to excavate is not required to give notice under the One-Call Statute. This is especially troublesome to the oil and gas industry given that coastal erosion and other forces have reduced the amount of cover over numerous pipelines in South Louisiana. Vessels that now have increased access to non-traditional waterways will not, under the federal court interpretation of the statute, be subject to statutory violation and penalties if, in anchoring or navigating, they damage an underground Louisiana line. Plains and Phillips have petitioned the full Fifth Circuit for en banc review.

Texas Court of Appeals Rules on Permission Needed for Off-Lease Horizontal Drilling

Posted in Exploration and Production, Industry News, Property Law, Texas

The Fourth Court of Appeals recently held that surface owners control the matrix of the underlying earth; thus, a surface owner can give permission to drill through the subsurface to an adjacent lease. In Lightning Oil Co. v. Anadarko E&P Onshore, No. 04-14-00903-CV, 2014 Tex. App. Lexis 8673 (Aug. 19, 2015), Anadarko leased the mineral estate under the Chaparral Wildlife Management Area (CWMA), and entered into a Surface Use and Subsurface Easement Agreement (Agreement) with the adjacent surface estate owners. The Agreement allowed Anadarko to place a drilling rig on the surface and to drill through the earth to form wells that open and bottom in the CWMA. Lightning held a mineral lease on the adjacent estate, and upon learning of Anadarko’s plan, sought an injunction. Following discovery, both Anadarko and Lightning moved for summary judgment on the claims of trespass and tortious interference with a contract. The trial court granted Anadarko’s motion for summary judgment, denied Lightning’s motion for summary judgment, and severed the remaining issues. Lightning appealed to the Fourth Court of Appeals.

Lightning argued that the surface owner’s permission to drill was not enough and declared its right to exclude others from drilling as the leaseholder of the mineral estate. Lightning also emphasized that it should not have to trust Anadarko to refrain from performing seismic surveys as it drilled through the subterranean structures to reach the CWMA. Lightning asserted claims for trespass and tortious interference with a contract. Anadarko, in turned, argued that the surface owners controlled the subterranean structures; thus, their permission is all that is needed to drill through Lightning’s mineral estate and claims of trespass and tortious interference must fail as a matter of law.

The court agreed with Anadarko and found that there was no evidence of an essential element of trespass, the right to exclude others from the earth surrounding the oil and gas for which Lightning has an exclusive right to explore, develop, operate, produce, own, market, treat, and transport according to its mineral lease. A mineral “‘lessee’s interest is a separate, real interest, amount[ing] to a defeasible title in fee to the oil and gas in the ground.’” Yet, the court held that the mineral lessee does not own the earth in which the mineral estate is contained. “The surface estate owner controls the earth beneath the surface estate.” The mineral estate only includes the minerals and does not give the mineral owner ownership of the earth surrounding those substances. Additionally, a conveyance of the mineral rights does not convey the entirety of the subsurface. Consequently, the surface estate owner owns all non-mineral molecules of the land. Texas precedent established that the mineral interest owner may not exclude others from drilling through its estate.

According to the court of appeals’ decision, there was also no evidence that Anadarko would conduct a seismographic survey which could constitute a trespass under Texas law. Moreover, Lightning offered no evidence that Anadarko has bottomed or opened a well within Lightning’s lease. Absent proof of these actions and without the right to exclude Anadarko from drilling through Lightning’s mineral estate, Lightning’s claim of trespass failed.

Lightning’s claim of tortious interference with a contract similarly failed. Anadarko established an affirmative defense of justification. A defendant is justified in his actions when he (1) acts within his own legal rights or (2) has a good faith claim to a colorable legal right, even if the claim ultimately fails. Here, the court ruled that Anadarko was within its own legal right granted by the surface estate owners to drill through the earth within in the boundaries of Lightning’s mineral lease to its mineral estate on the CWMA.

This decision has a significant impact on the practice of horizontal well drilling. It is common for operators to drill multiple horizontal wells from one drill pad. Lightning Oil Co. establishes the permission needed to drill from off-lease well pads.

Texas Court Rules Lease’s Retained Acreage Clause Incorporates Drilling Unit Size of Statewide Density Rule 38, ConocoPhillips Must Release 15,351 Acres to Lessor

Posted in Exploration and Production, Industry News, Litigation, Oil & Gas Contracts, Regulatory, Texas

A Texas appeals court recently ruled in ConocoPhillips Company v. Vaquillas Unproven Minerals, Ltd. that a lease’s retained acreage clause invoked the Texas Railroad Commission’s field spacing rule as well as the statewide drilling unit rule, Rule 38, which operated to reduce the acreage the lessee was permitted to retain under the lease from 640 acres per well to 40 acres per well. The effect of the ruling was that ConocoPhillips was ordered to release an additional 15,351 acres to the lessor.

In this case, ConocoPhillips was the lessee under two oil and gas leases, one covering 26,622.79 acres and the other covering 6,740 acres. Both of the leases contained a retained acreage clause which set the number of acres around each gas well that ConocoPhillips would be allowed to retain once its continuous drilling program ended:

 . . . Lessee covenants and agrees to . . . release . . . any and all portions of this lease which have not been drilled to a density of at least 40 acres for each producing oil well and 640 acres for each producing or shut-in gas well, except that in case any rule adopted by the Railroad Commission of Texas or any other regulating authority for any field on this lease provides for such a spacing or proration establishing different units of acreage per well, then such established different units shall be held under this lease by such production, in lieu of the 40 and 640-acre units above mentioned. . . .

It was undisputed that ConocoPhillips’ drilling program had ended, and it had apparently already released all acreage in excess of 640 acres per gas well. Because the retained acreage clause provided that its default allowance of 640 acres per gas well could be overridden by a field rule establishing a spacing or proration unit of a different size, the issue was whether such a rule had been adopted for the applicable field which would operate to reduce the acreage ConocoPhillips would be entitled to retain.

The only relevant rule for the field was a spacing rule which provided:

Rule 2. No well shall hereafter be drilled nearer than [467] feet to any property line, lease line or subdivision line and no well shall be drilled nearer than [1,200] feet to any applied for, permitted or completed well in the same reservoir on the same lease, pooled unit or unitized tract. . . .

The question thus became whether the spacing requirement of Rule 2 established a “different unit[] of acreage per well” than the 640 acres provided by the retained acreage clause. While the court of appeals agreed with ConocoPhillips that Rule 2 did not expressly set forth a unit of acreage, it found that the field rule must be read in conjunction with statewide Rule 38, which establishes the standard drilling unit size for gas fields in which “only spacing rules” exist, including field-specific spacing rules such as Rule 2. For fields in which the spacing requirement is 467/1200, as was the case for the field at issue per Rule 2, Rule 38(b) provides that the standard drilling unit is 40 acres per well.

The court concluded that Rule 2, read in conjunction with Rule 38, was a field spacing rule that established “different units of acreage per well” than that provided for in the retained acreage clause. Thus, the standard 40-acre drilling unit rule controlled the number of acres ConocoPhillips was entitled to retain under the leases. The Fourth Court of Appeals therefore affirmed the trial court’s ruling that ConocoPhillips had breached the leases by failing to release all acreage in excess of 40 acres for each gas well, resulting in a release of an additional 15,351 acres.

The Supreme Court’s Adopted Amendments to the Federal Rules of Civil Procedure: A Welcome Emphasis on Cooperative Case Management and Cost-Effective Discovery

Posted in Litigation

On April 29, 2015, the United States Supreme Court adopted the long anticipated amendments to the Federal Rules of Civil Procedure.  Pending Congressional review, the amendments will become law on December 1, 2015.  Together, the adopted amendments evidence the Court’s emphasis on promoting cooperative case management and reducing the delays and considerable costs often associated with the discovery process.

In pertinent part, amendments to Civil Rules 1, 4, 16, 26, 34, and 37 promote early and effective case management, enhance the means of keeping discovery costs proportional to the underlying litigation, increase the specificity requirements of discovery objections, and standardize the penalties for breaching a duty to preserve electronically stored information.  This article does not attempt to summarize each adopted amendment but instead provides a brief summary of the most noteworthy amendments and their impact on the federal practice.  A complete set of the amended and adopted rules may be accessed by clicking here.[1]

Rule 1: Scope and Purpose

Hyper-adversarial behavior often leads to exponential increases in litigation costs and delays to the detriment of both the court and the parties.  The Supreme Court’s revisions to Rule 1 obligate the court and the parties to employ the Rules of Civil Procedure to secure the just, speedy, and inexpensive determination of every action, stating:

These rules govern the procedure in all civil actions and proceedings in the United States district courts, except as stated in Rule 81.  They should be construed,and administered, and employed by the court and the parties to secure the just, speedy, and inexpensive determination of every action and proceeding.

As noted by the Committee on Rules of Practice and Procedure (“Committee”), the amendment to Rule 1 signals an intent, at the outset, to foster a cooperative and proportional use of the rules to temper the “over-use, misuse, and abuse of procedural tools that increase cost and result in delay.”[2]  This theme is embraced throughout the adopted amendments.

Rules 4 and 16: Expedited Summons and Pretrial Scheduling

Amended Rules 4 and 16 provide for a 30-day reduction in the time to serve summons on a defendant and for the court to enter a scheduling order.  Under the amended rules, the time for serving a defendant with the initial summons is reduced from 120 days to 90 days.  Similarly, the time for the court to issue a scheduling order is reduced to the earlier of 90 days (instead of 120 days) after any defendant has been served, or 60 days (instead of 90 days) after any defendant has appeared.  These amendments will reduce the delays encountered at the beginning of litigation and expedite the initial process for litigants.

Rule 16(b)(3)(v) is also amended to permit a court’s scheduling order to “direct that before moving for an order relating to discovery, the movant must request a conference with the court.”  Similar provisions are already found in the local rules for many federal courts but this amendment to Rule 16 standardizes the authority of a federal court to require such a conference in an effort to avoid unnecessary and costly discovery motion practice.

Rule 26: Refining the Scope and Proportionality of Discovery

Amended Rule 26 clarifies the permissible scope of discovery and emphasizes the need to balance the importance of the requested information against the burden of producing it.  In pertinent part, the amendment to Rule 26(b)(1) explains:

Unless otherwise limited by court order, the scope of discovery is as follows:  Parties may obtain discovery regarding any nonprivileged matter that is relevant to any party’s claim or defense and proportional to the needs of the case, considering the importance of the issues at stake in the action, the amount in controversy, the parties’ relative access to relevant information, the parties’ resources, the importance of the discovery in resolving the issues, and whether the burden or expense of the proposed discovery outweighs its likely benefit.  Information within this scope of discovery need not be admissible in evidence to be discoverable. including the existence, description, nature, custody, condition, and location of any documents or other tangible things and the identity and location of persons who know of any discoverable matter.  For good cause, the court may order discovery of any matter relevant to the subject matter involved in the action. Relevant information need not be admissible at the trial if the discovery appears reasonably calculated to lead to the discovery of admissible evidence.  All discovery is subject to the limitations imposed by Rule 26(b)(2)(C).

As amended, Rule 26 makes clear that the scope of discovery includes information that is relevant to any party’s claim or defense and is proportional to the needs of the case.  The amendment deletes the current provision for discovery of relevant but inadmissible information that appears “reasonably calculated to lead to the discovery of admissible evidence” because, as the Committee explains, this phrase “has been used by some, incorrectly, to define the scope of discovery.”  The misused phrase is replaced by the clearer statement that “Information within this scope of discovery need not be admissible.”  The amendment seeks to curb the misapplication of the phrase “reasonably calculated to lead to the discovery of admissible evidence” that often leads to unnecessary increases in the scope and cost of discovery.

The amendments to Rule 26 also emphasize the need to balance the competing interests at issue in a discovery request to ensure that discovery is proportional to the needs of the case.  The list of considerations that bear on proportionality is moved to the section defining the scope of discovery in order to reinforce the obligation of the parties to consider these factors in making discovery requests, responses, and objections.

Amended Rule 26(c)(1)(B) also explicitly provides for a cost-shifting mechanism allowing for the use of protective orders to shift the cost burden of discovery onto the requesting party.  Courts already have the authority to enter such an order but the explicit recognition of this practice is intended to forestall the temptation some parties may feel to contest this authority.  The Committee notes, however, that “the authority does not imply that cost-shifting should become a common practice” and litigants can still “assume that a responding party ordinarily bears the cost of responding.”

Rule 34: Objections to Requests for Production of Documents

Amended Rule 37 provides that objections to requests for production “must state whether any responsive materials are actually being withheld on the basis of that objection.”  The producing party does not need to provide a detailed description of all documents withheld.  The producing party simply needs to alert the requesting party that materials are being withheld under an objection in order to facilitate an informed discussion of the objection.  Further, if an objection recognizes that some part of the request is appropriate, the objection should reflect this distinction and provide a response to the appropriate portion of the request.  The Committee explains that the general intent of this amendment is to “end the confusion that frequently arises when a producing party states several objections and still produces information, leaving the requesting party uncertain whether any relevant and responsive information has been withheld on the basis of the objections.”  These changes are aimed at streamlining discovery by reducing the potential for a party to impose unreasonable burdens or create delay through objections to requests for production.

Rule 37: Standardized Remedies for Failing to Preserve Electronically Stored Information

Rule 37 was amended in an effort to address what the Committee calls “the serious problems resulting from the continued exponential growth in the volume” of electronically stored information (“ESI”) in litigation and to resolve the inconsistent sanctions or curative measures imposed by federal courts on parties who failed to properly preserve ESI.  The revisions to Rule 37(e) read as follows:

Absent exceptional circumstances, a court may not impose sanctions under these rules on a party for failing to provide electronically stored information lost as a result of routine, good faith operation of an electronic information system. If electronically stored information that should have been preserved in the anticipation or conduct of litigation is lost because a party failed to take reasonable steps to preserve it, and it cannot be restored or replaced through additional discovery, the court:

  1. Upon finding prejudice to another party from loss of the information, may order measures no greater than necessary to cure the prejudice; or
  2. Only upon finding that the party acted with the intent to deprive another party of the information’s use in the litigation may:
    1. Presume that the lost information was unfavorable to the party;
    2. Instruct the jury that it may or must presume the information was unfavorable to the party; or
    3. Dismiss the action or enter a default judgment.

A party has a duty to preserve relevant ESI when litigation is reasonably foreseeable; this duty remains unchanged.  Amended Rule 37(e) simply standardizes the remedies available following a party’s breach of this duty.  As amended, a court may apply curative remedies when three criteria are met, including: (1) the lost ESI “should have been preserved in the anticipation or conduct of litigation,” (2) the ESI was lost because a party did not “take reasonable steps to preserve it,” and (3) the loss of the ESI cannot be remedied by “additional discovery.”  If all these criteria are met and the court finds the requesting party is prejudiced by the lost ESI, the court may order a curative remedy but the remedy can be “no greater than necessary to cure the prejudice.”  Rule 37 clarifies that severe penalties such as an adverse inference, jury instruction or dismissal can only be applied if the three above-enumerated criteria are met and the court finds that the ESI was lost or destroyed “with the intent to deprive another party of the information’s use in the litigation.”  Notably, as amended, if the court finds that ESI was intentionally lost or destroyed, severe penalties such as dismissal may apply even in the absence of prejudice to the requesting party.

Amended Rule 37 does not affect the validity of tort claims for spoliation if state law applies, but the Committee anticipates that the revisions will help alleviate the concern that often causes parties to “[e]xpend excessive effort and money on preservation [of ESI] in order to avoid the risk of severe sanctions if a court finds they did not do enough.”  Adverse-inference instructions were developed as a remedy premised on the belief that a party’s intentional loss or destruction of evidence gives rise to the reasonable inference that such evidence was unfavorable.  Unintentional, negligent or reckless behavior does not support that inference.  As the Committee explains, “the remedy should fit the wrong.”  Accordingly, amended Rule 37 limits severe remedial measures to instances where ESI is intentionally lost or destroyed to prevent another party from using it.

Conclusion: A Client-Benefitting Focus on Efficient Litigation

The principle driving forces behind the amendments to the Federal Rules of Civil Procedure are the goals of ensuring cooperative case management and restraining the misuse of the rules to create delays and increase the cost of litigation.  The amendments emphasize that the courts and the parties share in the responsibility of employing the rules of procedure to secure a just, speedy, and inexpensive determination of every action.  On December 1, 2015, pending Congressional review, these prudent amendments will become law and will hopefully serve to reduce hyper-adversarial abuses of the rules and promote more cost-effective and efficient advocacy to the benefit of all litigants.

[1]          The approved amendments make the following minor revisions that are not discussed in detail herein: cross-references in Rules 30, 31, 33 are revised to reflect amendments to Rule 26; the word “final” is inserted into Rule 55 to clarify that a “default judgment that does not dispose of all of the claims among all the parties is not a final judgment” unless the court designates it as such pursuant to Rule 54(b); and the Rule 84 forms and the Appendix of Forms are both abrogated because “there are many excellent alternative sources for forms, including the Administrative Office of the United States.”

[2]           Click here to access the entire package of materials submitted by the United States Supreme Court to Congress on April 29, 2015, including amended civil rules, amended bankruptcy rules, orders adopting the amended rules, letters of transmittal, and related notes and memoranda of the Committee on Rules of Practice and Procedure.

The Fifth Circuit Further Clarifies Service Contract and Insurance Interplay Under Texas Law

Posted in Industry News, Insurance

Ironshore Specialty Insurance Co. v. Aspen Underwriting Ltd. et al., No. 13-51027 (5th Cir. June 10, 2015)

In March 2013, the federal Fifth Circuit ruled in the Deepwater Horizon litigation, under Texas law, that the scope of additional insured coverage was to be determined based only upon the four corners of the policy and that specific reference to an underlying contract or some other express wording in the policy was necessary to incorporate coverage limitations from the contract into the policy. The Fifth Circuit subsequently withdrew its opinion and certified the key issues to the Texas Supreme Court.

In February 2015, the Texas Supreme Court handed down its decision in In re Deepwater Horizon, __ S.W.3d __, 2015 WL 674744 (Tex. Feb. 13, 2015). Answering the questions certified by the Fifth Circuit, the Supreme Court held that two provisions contained in Transocean’s insurance policy were sufficient to incorporate intended additional insured coverage limitations in the contract into the policy: (1) the definition of “Insured” to include any entity to whom the named insured is obliged, in an “Insured Contract,” to provide insurance, and (2) the provision adding additional insureds “as required by written contract.” While the Supreme Court’s decision provided some degree of clarity, it left undecided whether both of the cited policy provisions were needed to incorporate contract limitations into the policy, or, instead, was one or the other provision sufficient.

On June 10, 2015, the Fifth Circuit further addressed this area of contract and insurance interplay with its decision in Ironshore Specialty Insurance Co. v. Aspen Underwriting Ltd. et al., No. 13-51027, (5th Cir. June 10, 2015). The appellate court was asked to determine whether, under Texas law, contractual requirements in a master service agreement obligating the contractor (Basic) to name the oil company (Endeavor) as an additional insured and provide $5 million in additional insured coverage served to limit the amount of insurance provided to $5 million notwithstanding that the liability limit of the contractor’s insurance program was significantly greater ($50 million). Because the contractor’s policy included only one of the two policy provisions cited by the Texas Supreme Court in the February 2015 Deepwater Horizon decision (the “Insured Contract” provision), the Fifth Circuit was forced to make its best “Erie guess” as to whether, under Texas law, the “Insured Contract” provision alone was sufficient to incorporate what the court determined to be the contract’s intended limitation of coverage to $5 million. The Court ultimately concluded that the “Insured Contract” provision discussed in Deepwater Horizon was sufficient to incorporate the limitations of the MSA. Below are key excerpts from the opinion:

Because Basic was “obliged by a written ‘Insured Contract’ . . . to provide insurance” to Endeavor, there is no dispute that the company meets the definition of “Insured” under Basic’s excess policies and is therefore covered by those policies. And there is no disagreement that under the MSA, Basic was only required to provide $5 million in insurance coverage to Endeavor. The dispute is limited to whether that provision in the MSA is incorporated into Basic’s insurance policies as a limit on Endeavor’s coverage. Ironshore contends that the policies do not limit Defendants’ coverage obligations, either expressly or through the incorporation of the MSA’s limitations. Defendants argue that their policies must be read “in conjunction” with the MSA, including its insurance provision, and therefore that Endeavor’s coverage is limited to $5 million.

As mentioned above, the “Insured Contract” provision in Basic’s policies is essentially the same as the corresponding provision in Transocean’s policies. That does not resolve the question, however, because it is not clear what effect the Deepwater Horizon court gave to the “Insured Contract” provision alone. The court also relied on another provision that is not present in Basic’s policies, adding additional insureds “where required by written contract.” We must decide, therefore, whether both the “Insured Contract” and “where required” provisions were necessary to Deepwater Horizon’s result, or whether each provision standing alone was an independent basis for the decision.

Our best reading of Deepwater Horizon is the latter. …

Our Erie guess, therefore, is that the “Insured Contract” provision was a sufficient ground in Deepwater Horizon to incorporate the Drilling Contract’s limitation on coverage for above-surface pollution. The nearly identical language in Basic’s policies thus compels the same result. Because Basic was only “obliged” to procure $5 million in insurance, we AFFIRM the district court’s grant of summary judgment in favor of Defendants.

Most standard form liability insurance policies contain a provision equivalent to the “Insured Contract” provision at issue in Deepwater Horizon and Ironshore Specialty. With an “Insured Contract” provision present in the policy, the Fifth Circuit’s decision in Ironshore Specialty indicates that, at least under Texas law, coverage limitations imposed on additional insured coverage in an underlying master service agreement will be enforced. Had the additional insured wording in the underlying contract in Ironshore Specialty been broader (e.g., provide additional insured coverage with limits of “at least $5 million”), it is conceivable that a different ultimate outcome may have been reached in the case.

Texas Supreme Court Holds Producer Not Required to Share in Natural Gas Pipeline Compression Costs

Posted in Industry News, Litigation, Oil & Gas Contracts, Pipeline, Texas

In Kachina Pipeline Company, Inc. v. Lillis, No. 13-0596, the Supreme Court of Texas interpreted a natural gas-purchase contract and held that a producer was not required to share in the costs of compression, even though that compression helped yield a higher re-sale price. Whether this decision narrowly reflects the language of one specific contract or represents a sea change is yet to be determined.

Factual Background

Kachina Pipeline Company, Inc. (“Kachina”) operates a natural gas gathering system, as well as a gas pipeline.  Kachina utilized its pipeline to transport gas it purchased to Davis Gas Processing’s Plant (“Davis Plant”) where it was re-sold.  Michael Lillis (“Lillis”) was one of the producers who sold natural gas to Kachina, dating back to 2001.

In 2003, Kachina installed the “Barker Central Compression Station” (“Compression Station”) on its pipeline, which allowed it to resell the gas in the pipeline at its high-pressure inlet, increasing its re-sale value to Davis.  In 2005, Kachina (the Buyer) and Lillis (the Seller) entered into a new Gas Purchase Agreement (“Agreement”).  Under the Agreement, Lillis would transfer his gas into Kachina’s gathering system to be transported through the pipeline to the Davis Plant.  In exchange, Kachina would pay Lillis a percentage of the re-sale price it obtained from Davis. The Agreement had an initial five (5) year term, and was scheduled to expire in May 2010.  After the expiration of the initial term, the Agreement continued on a month-to-month basis, and could be cancelled by either party after thirty (30) days notice.  The Agreement also included a provision allowing Kachina to “continue the purchase of gas under the terms of this Agreement” if Lillis attempted to cancel the Agreement and sell to a third-party, provided Kachina would match the price terms offered by the third-party.

Procedural History

In 2008, Lillis contracted to sell his gas directly to Davis, and constructed his own pipeline to the Davis Plant.  Lillis then brought suit against Kachina, alleging that compression costs had been improperly deducted in breach of the Agreement.  Kachina counterclaimed, arguing that Lillis breached the Agreement by failing to notify it of Davis’ third-party offer, as well as a declaratory judgment allowing it to both:  1) take compression deductions under the Agreement;  and 2) exercise a renewal of Agreement until May 2015.  Both parties filed motions for summary judgment.  The trial court denied Lillis’ motion and granted Kachina’s motions.

Lillis appealed the judgment to the Third Court of Appeals in Austin, which reversed both declarations, and held that the Agreement did not allow Kachina to deduct compression costs, and that the Agreement was not extended until May 2015.  In a 6-3 decision, the Supreme Court of Texas agreed with the Third Court of Appeals on both issues, with Justice Brown writing the majority opinion.  Chief Justice Hecht, joined by Justice Green and Justice Devine, dissented.

Does the Compression Contract Require Payment?

Kachina asserted that the Agreement allows for deductions for “any compression that aids in the final delivery to Davis of gas bought from Lillis.”  Id. at *7.  Conversely, Lillis asserted that the Agreement allows for deductions for compression that Kachina installed only after Lillis fails to deliver gas that can be transported through the pipeline.  Under Lillis’ interpretation, Kachina would be required to show:  “1) that Lillis was unable to deliver gas against Kachina’s working pressure, and (2) the compression equipment was installed after the Agreement’s execution.”  Id. at *7-8.  That interpretation would exclude deductions related to the Compression Station, which was installed in 2003, two years prior to the Agreement.  The specific provision on pressure read as follows:

Pressure:  Seller shall deliver the gas deliverable hereunder, at the above[-]described delivery point at a pressure sufficient to enter Buyer’s pipeline against the working pressure maintained therein from time to time.  Seller will regulate its[] pressures so as to not exceed the maximum allowed operating pressure (MAOP) as set from time to time by Buyer for deliveries into Buyer’s gas pipeline.  However, it is expressly understood and agreed that neither party hereto shall be obligated to compress any gas under the terms of this Agreement and if the well is no longer capable of delivering gas against the working pressures maintained at the delivery point and neither party elects to install a compressor, then Buyer shall, upon request from Seller, release such well and the gas produced therefrom from the terms and provisions of this Agreement.  If Buyer installs compression to effect delivery of Seller’s gas, Buyer will deduct from proceeds payable to Seller hereunder a value equal to Buyer’s actual costs to install, repair, maintain and operate compression, plus 20% of such costs to cover management, overhead and administration.

(emphasis by Court).  The Court noted that the Agreement put the burden of maintaining sufficient well pressure (to overcome the working pressure in the pipeline) on Lillis.  If Lillis’ wells failed to do so, then the Agreement provided Kachina with two options:  “[i]t may do nothing, in which case the well will be released from the Agreement.  Or it may elect to install compression so that the well can overcome the working pressure.”  Id. at *11.  If Kachina elected the latter, the Agreement provided it was entitled to deduct compression costs.

Based on this framework, the Court viewed the ability to deduct costs for compression as entirely contingent, arising “only if [Kachina] installs compression to effect delivery.”  Id. at *11-12.  As a result, Justice Brown held that it could not apply to pre-existing compression, as the provision utilized the word “installation.”  That word choice would not make any sense if the parties intended Kachina to charge Lillis for pre-existing compression.  The opinion also held that “only compression installed for the purpose of overcoming Kachina’s working pressure is installed to ‘effect delivery.’”  Id. at 12.  The Court reasoned that “if a well’s natural pressure is sufficient to overcome the working pressure at the delivery point, added compression can hardly be said to bring about delivery that would occur without it.”  Id. at *12-13.

Kachina argued that the Compression Station, though pre-existing, “effects delivery” by “lowering suction” which reduced upstream pressure and aided the flow of gas into the pipeline.  Chief Justice Hecht also echoed this point in his dissent.  The Court found this position unavailing, noting that, while this compression may aid in delivery, it does not “effect delivery.”  Id. at *15

Kachina also alleged, and the dissent agreed, that Lillis would have been unable to deliver the gas to the pipeline without the compression.  The Court disagreed, distinguishing between the “high-pressure” sales made possible by the Compression Station, and Davis’ ability to take low-pressure gas (albeit for a lower resale price).

The Court, however, did make sure to clarify that the location of the pressure was not determinative on the question of whether compression can “effect delivery,” as compression can reduce upstream pressure as well as downstream pressure.  This point stood in contrast to the Court of Appeals, and was urged by two pipeline industry amicus briefs.  In closing, the majority noted that while downstream compression of gas “was both common and critical to efficient transportation,” the industry custom of producers willingness to share in those costs could not overcome the unambiguous meaning of the Agreement.  Id. at *19.

In his dissent, Justice Hecht argued that the summary judgment evidence conclusively established that Kachina’s compression was necessary to effect the delivery of Lillis’ gas, noting that appellee’s counsel conceded that, without any compression in the Kachina pipeline, Lillis’ gas could not enter the delivery system.  Moreover, he rejected the majority opinion’s temporal distinction based on the word “installation,” asserting that it makes little sense for Lillis to stop paying for compression (as under the parties’ previous agreement) only to resume paying for it when it became necessary under the 2005 Agreement.  In closing, the dissent stated:  “Today’s lesson is that producers’ agreements to share in compression costs are common and critical and will be enforced unless a court can think of a way to avoid them, regardless of the evidence.”  Id. at *28.

Did the Compression Contract Extend the Contract?

The Court also addressed the extension of the Agreement.  Kachina asserted that its right to “continue the purchase of gas under the terms of this Agreement” afforded it the right to extend the Agreement by another five (5) years, because the five-year initial period was a “term.”  The Court rejected this argument, noting that the extension merely allowed Kachina to “continue to purchase gas,” and that the Agreement explicitly became month to month as of May 2010.  In his dissent, Justice Hecht joined this portion of the opinion.

The Court withdrew its June 12, 2015 opinion and issued a substituted opinion with the same reasoning on October 9, 2015.