Litigation Update for the Energy Industry Other Jurisdictions

Eugene Kuntz Conference on Natural
Resources Law and Policy
Oklahoma City, Oklahoma
November 7, 2014
Litigation Update for the Energy Industry
in Oklahoma, With Select Cases From
Other Jurisdictions
Mark D. Christiansen
McAfee & Taft
A Professional Corporation
Oklahoma City, Oklahoma
Mark D. Christiansen
Mark Christiansen is the Co-Leader of the Energy and Oil & Gas Industry Group
in the law firm of McAfee & Taft, and practices in the firm’s Oklahoma City office. His
practice involves the representation of oil and gas producers, purchasers and other
sectors of the energy industry primarily in litigation matters and in certain transactional
matters.
Mark serves on the Board of Trustees, and on the Executive Committee, for the
Dallas-based Center for American and International Law. He also served in 2011 - 2013
on the Board of Directors for the Board of Trustees, and as Treasurer, for the Denverbased Rocky Mountain Mineral Law Foundation.
Since 1997, he has been listed in Best Lawyers in America under the practice
areas of Natural Resources and Energy Law. Since the inaugural listings of Oklahoma
lawyers in these two publications, Mark has been listed in Oklahoma Super Lawyers on
the list of the Top 50 lawyers in the State of Oklahoma and on the list of top attorneys
in the area of Energy and Natural Resources Law, and in the Chambers USA Directory's
listing of leading Oklahoma attorneys in the area of Energy and Natural Resources Law.
Since 1996, Mark has been a member of the Board of Editors for The Oil and Gas
Reporter (Matthew Bender/Lexis). He served as the Chair of the Energy and Natural
Resources Litigation Committee of the ABA Section of Environment, Energy, and
Resources (SEER) from 2001–2003. From 1985 to the present, Mark has served as lead
editor and co-author of annual reports of legal developments in the United States in the
area of energy law for the Year in Review publication of the ABA SEER. He is lead
editor for a similar "energy litigation update" published each Summer in the Rocky
Mountain Mineral Law Foundation Journal.
Some of Mark’s other publications include: Author of Chapter titled "Oil and Gas
Royalty Class Action Lawsuits," in the ABA Tort Trial & Insurance Practice Section's
Book titled A Practitioner's Guide to Class Actions (2010 – 2013); "The Top Ten Recent
Court Decisions Challenging the Oil and Gas Industry," 58 Oil & Gas Instit. Chapt. 4, at
87 (2007); Co-Author, "A Different 'Slant' on JOAs," 57 Rocky Mountain Mineral Law
Institute 25 (2012); "Class Actions Pushed to the Extreme--Will Class Action Plaintiff
Lawyers Be Permitted to Re-Zone Our Courts for Tract Housing?” 24 Journal of Land,
Resources and Environmental Law 77 (2004); “A Landman’s Guide to Drafting
Provisions for the Allocation of Gas Marketing-Related Costs Under the Oil and Gas
Lease,” 45 Rocky Mountain Mineral Law Institute 21 (1999); “A Comparison of the
Model Form Gas Balancing Agreements - Catching Up With a Changing Market
Environment,” 40 Rocky Mountain Mineral Law Institute 16 (1994); and Co-Author,
“COPAS for Landmen and Lawyers,” 48 Rocky Mountain Mineral Law Institute (2002).
2
Table of Contents
Page
I.
Non-Operator v. Operator, Gas Balancing, and Other Oil
and Gas Operations-Related Cases
4
II.
Royalty Owner Litigation
11
III.
Oil and Gas Lease Cancellation, Termination and Breach of
Obligation Cases (Other than Royalty)
17
IV.
Oil and Gas Contracts, Transactions and Title Matters
32
V.
Marketing and Refining of Oil and Gas Production
44
VI.
Surface Use, Surface Damages, Surface Damages Act, and
Environmental Cases
46
VII.
Conservation Commission-Related Cases
51
VIII. Litigation Over International Energy and Resources
Operations
54
IX.
Antitrust, Unfair Competition and Securities Litigation
Involving the Energy and Resources Industries
61
X.
Other Energy Industry Cases
68 - 76
3
I.
Non-Operator v. Operator
Operations-Related Cases
A.
and
Other
Oil
and
Gas
Court Finds That Plaintiff’s Delay in Asserting Preferential
Purchase Rights Under JOA Led to the Claims Being Barred Under
the Doctrine of Laches.
The case of Kirk v. Devon Energy Production Company, L.P.,1 involved a suit by
Kirk for specific performance of the preferential right of purchase provision of an
operating agreement. He alleged that Texas Energy Supply, Inc. assigned certain oil
and gas leases to Devon without giving Kirk prior notice and the opportunity to acquire
the leases under the preferential right of purchase clause of the JOA covering the unit.
The factual record in the case showed that Kirk waited nearly three years after
he first learned that Texas Energy assigned the leases to Devon without complying with
the JOA before seeking to enforce his preferential purchase right. During that threeyear period, Devon paid over $4.1 million to drill an oil well on the unit, with total
drilling and completion costs exceeding $7.4 million. Devon filed a motion for summary
judgment, urging that Kirk’s rights were barred under the doctrines of laches and
estoppel. Devon relied in part on the prior decision of the Oklahoma Court of Appeals
in Chesapeake Operating, Inc. v. Carl E. Gungoll Exploration, Inc.2 in which the court
found the contractual rights Gungoll possessed to acquire certain oil and gas leases of
Chesapeake could not be enforced due to the passage of time under the doctrines of
laches and estoppel. The trial court granted summary judgment in favor of Devon on
the grounds of laches and Kirk appealed.
In affirming the trial court’s judgment in favor of Devon, the Court of Appeals
noted that Kirk waited nearly three years after learning of Devon’s acquisition of the
leases before seeking to enforce his preferential right, and that Devon undertook
substantial financial risks and expended millions of dollars in the development and
drilling of the well while Kirk remained silent. The court noted that the doctrine of
laches is rigorously applied in suits involving property of speculative value, particularly
oil and gas properties.
Substantially the same outcome occurred in a separate preferential right of
purchase enforcement lawsuit brought by Kirk against Cimarex Energy, which was
removed to federal court. See Kirk v. Cimarex Energy Company,3
1
85 OBJ 1479 (Okla. App. 2014 - #111,488) (Not for Publication).
2005 OK CIV APP 45, 116 P.3d 213.
3 No. 5:2011-cv-00384-W, United States District Court for the Western District of
Oklahoma.
4
2
B.
Court determines the proper manner for computing “deferred
production damages” associated with pipeline rupture.
The court in Contango Operators, Inc. v. United States,4 was presented with a
series of issues associated with injury caused to a gas pipeline owned by Contango and
certain non-operating working interest owners that ran along the floor of the Gulf of
Mexico. In February of 2010, a dredge owned by Weeks Marine struck and ruptured
the pipeline. Contango asserted that various instrumentalities of the United States
hired Weeks Marine to perform the dredging and provided inadequate notice to Weeks
regarding the existence and location of the Contango pipeline. Contango’s pipeline was
shut-in for thirty-five days from the date it was struck until it was repaired and placed
back in service. During this thirty-five-day period Contango was not able to produce or
sell gas or condensate from the wells connected to the pipeline.
The present lawsuit was filed by Contango against Weeks Marine and the United
States in order to recover for the resulting damages. Contango alleged that the United
States breached the duty to ensure that dredging activities did not interfere with or
endanger the Contango pipeline, and that Weeks Marine breached its duty to conduct
dredging operations in a reasonable manner. Contango asserted that both defendants
committed negligence per se based on violations of various federal maritime regulations
governing the operation of the Weeks Marine dredging barge.
At the conclusion of a one-week bench trial, the District Court ruled on a variety
of issues presented in this dispute, including the manner for computing the damages
sought by Contango.
(A)
The court awarded Contango $543,634,03 in uninsured repair costs, with
the court rejecting the defendants’ argument that $106,062.38 of that amount was not
recoverable because Contango “bettered” the pipeline by burying it deeper as part of
the repairs.
(B)
The court awarded $78,073.00 for lost hydrocarbons. The United States
initially argued that, since the non-operating working interest owners were not parties
to the lawsuit, this portion of the damages should be reduced by the lost hydrocarbons
attributable to those non-litigants. However, that objection was rendered moot when
the plaintiffs filed an amended complaint adding the working interest owners has
plaintiffs.
(C)
The element of damages which led to the greatest disagreement before
the court was Contango’s claim for “deferred production damanges.” Using a discount
rate of 8%, Contango argued that it was entitled to recover $7,981,927.00 in deferred
4
2014 WL 1278628 (S.D. Tex. 2014).
5
production damages, which represent the difference between the value of gas and
condensate that Contango would have produced during the thirty-five days when its
wells were shut-in and the present value of that same product when it is actually
produced over the remaining life of the wells. The court noted that the practical and
economic measure of an oil company’s loss from delayed production is the difference
between the net revenue flow with and without the delay. It was noted that projecting
the rate of production is essential to determining the proper measure of Contango’s
deferred production damages.
At trial, when the defendants’ expert was asked why his projections for a
particular well were lower than what the well actually produced, the expert replied that
Contango opened the choke, or did something else to artificially manipulate the
reservoir. Consequently, the court noted that the defendants’ damages model may not
account for the non-pressure-related factors relevant to Contango’s production profile
as accurately as the damages model of the plaintiff did.
The defendants criticized the damages model of the plaintiff as relying too
heavily on production data, while the court noted that the defendants’ damages model
relied too heavily on pressure data. The court recognized that Contango might have
economic and operational reasons for speeding or slowing production that are
independent of the particular characteristics of the reservoir. Nonetheless, they would
affect the rate of production, and it is the rate of production that largely determines the
amount of Contango’s deferred production damages.
The court concluded that Contango was not obligated to adjust its production
schedule in order to minimize its deferred production damages at the expense of its
legitimate economic and operational reasons for producing at a particular rate.
Therefore, Contango was entitled to deferred production damages in accordance with
its reasonable and legitimate management of the production rates of its wells.
Because the damages model of Contango verified the projections against actual
production data as it became available, the court found that model to be more reliable
in predicting the rate of production. The court awarded to Contango the requested
$7,981,927.00 in deferred production damages.
C.
Texas Supreme Court, in lawsuit for unpaid JIBs, determines the
date from which post-judgment interest should run where the
case was remanded for further evidentiary proceedings.
In Long v. Castle Texas Production Limited Partnership,5 Castle operated gas
wells in which Long owned certain interests. Long sued Castle for breach of the
5
426 S.W.3d 73 (Tex. 2014).
6
applicable joint operating agreement (JOA) and for conversion of natural gas
production. Castle counterclaimed for unpaid joint interest billings (JIBs) and prevailed
on that counterclaim. In the first judgment entered below, in 2001, the trial court
awarded Castle prejudgment interest of $73,998.90 without specifying the manner in
which it calculated that amount.
At issue in this appeal was the manner in which postjudgment interest on the
unpaid JIBs should be calculated. In particular, the Texas Supreme Court was
presented with the task of deciding the date from which postjudgment interest begins
to accrue when a remand of the case requires further evidentiary proceedings. In the
proceedings below, the trial court awarded Castle postjudgment interest from the
original judgment date in 2001. The Court of Appeals affirmed, holding that “a party
that ultimately prevails is entitled to postjudgment interest from the date the original
judgment was rendered, irrespective of whether the original judgment was erroneous,
because that is the date upon which the court should have rendered a correct
judgment.”6 The Texas Supreme Court granted Long’s petition for review.
In reversing the decisions below and remanding the case for further proceedings,
the Court observed that (1) if the trial court determines that it must reopen the record
on remand based upon the record and pleadings as they existed at the time of the
remand, postjudgment interest will accrue from the subsequent judgment; but (2) if the
court of appeals instead can or does render the judgment the trial court should have
rendered, postjudgment interest accrues from the original, erroneous trial court
judgment.
Here, the court of appeals remanded the case for the trial court to assess
prejudgment interest based upon the date Long received joint interest billings. The trial
court determined that it required additional evidence to decide the issue. Because
there was insufficient evidence in the record establishing when Long received the
billings and because the trial court had no duty to deny Castle’s request for
prejudgment interest on the existing record, the Court found no basis to conclude that
the trial court’s ruling to reopen the record was an abuse of discretion. Accordingly, the
Court held that postjudgment interest must accrue from the trial court’s final judgment
in 2009.
D.
Court finds that party first committing a substantial breach of
contract cannot complain that the other party fails to perform.
The analysis of the Wyoming Supreme Court in Black Diamond Energy, Inc. v.
6
330 S.W.3d 749, 753.
7
Encana Oil and Gas (USA) Inc.,7 concerning disputes that arose under a multi-well
farmout agreement will be of interest to the many who have been presented with
complex contractual disputes that involve disagreements as to which side first breached
the underlying agreement. The applicable farmout agreement contemplated the drilling
of a series of wells, with the rights earned being dependent upon certain factual
variables. As occurs with some regularity in the oil and gas industry, disputes arose
regarding the payment of joint interest billings, the issue of when and if assignments
had been earned, and similar issues.
A variety of arguments were raised in the ensuing litigation between the parties,
with each party asserting certain claims against the other. The trial court disposed of
some of the issues through summary judgment rulings, and the remainder of claims
and defenses proceeded to a jury trial. The jury returned a verdict finding that Black
Diamond (BDE) breached the farmout agreement but Encana proved no damages. BDE
appealed.
In affirming the ruling of the trial court, the Wyoming Supreme Court made the
following findings that are of interest generally in oil and gas contract disputes:
1.
BDE’s primary challenge on appeal was the assertion that the trial court
erred in instructing the jury that if a party materially breaches a contract, the nonbreaching party is no longer required to continue to perform. While it agreed that this
is a correct statement of the law generally, BDE argues that the circumstances of the
present case gave rise to the qualifying principal of law that,
“a victim of a breach must either declare the breach or move ahead with
the contract; it cannot continue to receive benefits under the contract and
then refuse to perform its part of the bargain. As applied to this case,
BDE contends the jury should have been instructed that if BDE breached
the FOA by failing to remit payments due, Encana either had to declare
the breach and terminate the FOA at the time or continue to accept
payments from BDE and perform Encana's part of the bargain by
assigning the leasehold interests BDE had earned. Because Encana
continued to accept payments, BDE argues, Encana was obligated to
complete the wells and assign the leasehold interests.” 326 P.3d at 910.
However, the court concluded that the instruction to the jury was consistent with
Wyoming law because the party first committing a substantial breach of contract cannot
complain that the other party fails to perform.
7
2014 WY 64, 326 P.3d 904.
8
2.
Related to the preceding issue, BDE further argued that the trial court
erred in giving the jury a Verdict Form that asked it to determine which party breached
the contract and the damages proven by the non-breaching party. BDE asserted that
the effect of that Verdict Form and the instruction discussed above was to erroneously
instruct the jury that there could be only one breaching party and only one party
entitled to damages. BDE urged that the District Court should have instead given the
jury BDE’s proposed Verdict Form which asked the jury to determine (a) first, whether
Encana breached the farmout and, if so, what BDE’s damages were and, (b) second,
whether BDE breached the farmout and, if so, what Encana’s damages were. For the
same reasons as the court rejected BDE’s foregoing complaint about the jury
instructions, it rejected these complaints regarding the Verdict Form.
3.
BDE additionally emphasized paragraph 16 of the farmout agreement
which provided in detailed terms that BDE could earn certain leasehold rights in some
circumstances even if not all of the minimum requirements of the agreement had been
met. BDE urged that the effect of this paragraph was to require Encana to assign
certain acreage to BDE even if BDE had failed to meet its financial obligations.
However, the court found that, while BDE interpreted paragraph 16 in that manner, the
jury may have interpreted the farmout agreement to mean that BDE was entitled to
partial assignments only if it had satisfied the requirement that 8 test wells be drilled
and completed (which had not occurred under the evidence presented at trial).
4.
The appellate court noted that, in interpreting the disputed issues under
the farmout agreement, the District Court ruled that the phrase “completed as a
producer” meant “a well capable and ready to produce gas, including perforation and
fracking, but did not require that the well be hooked up to the pipeline.” 326 P.3d at
909, ¶ 15.
5.
Those who encounter these issues in their trial work may want to note
that the opinion of the court includes a detailed discussion regarding the trial court’s (a)
exclusion of certain expert testimony and reports, and (b) exclusion of evidence that
Encana was holding funds BDE had paid toward a separate well under a separate
contract, and that BDE had asked Encana to apply those funds to the amounts owed
Encana under the subject farmout agreement.
E.
Jury Reaches Unusual Verdict in Lawsuit Seeking Recovery for
the Drilling of a New Well at an Incorrect and Unintended
Location.
In Mosaic Potash Carlsbad, Inc. v. Devon Energy Production Co., L.P.,8 Devon
8
No. D-503-CV-2010-00990, Fifth Judicial District Court for Eddy County, New Mexico
(Final Judgment filed May 12, 2014) (Unpublished).
9
held certain oil and gas leasehold rights covering portions of the federal lands at issue
in this case (Section 25). Mosaic claimed ownership of a potash lease covering the
same area.
In 2005, Devon staked, and sought permission from the Bureau of Land
Management (BLM) to drill, a gas well at a location 1,980 feet from the south line and
660 feet from the west line of Section 25. BLM personnel advised Devon by telephone
that the agency was not going to approve the proposed well location and instead asked
Devon to move the proposed well location some 1,400 feet to a location between two
existing wells. Devon agreed and staked the location for the proposed well some 1,400
feet away, at a position 2,310’ FSL and 1,980’ FWL. In September 2005, the BLM
approved the new location.
Through inadvertent and unintended mistake, Devon erroneously drilled the well
at the original proposed location that had not been approved by the BLM. The error in
the location was first discovered by Devon in February 2006, and company personnel
promptly notified the BLM to discuss how the situation should be handled. On March
27, 2006, the BLM approved the new well as drilled (i.e., at the original proposed
location of 1980’ FSL and 660’ FWL).
It was undisputed that no mineable potash was physically destroyed by the new
well. In 2010, Mosaic brought the present lawsuit seeking monetary recovery against
Devon based upon claims for negligence, trespass and prima facie tort. A series of
complex issues and arguments were raised in the lawsuit. Most related to the federal
regulatory scheme that applied to the competing development of oil and gas and
potash on the subject federal lands. Mosaic asserted, among other arguments, that it
suffered injury as a result of the revised well location because of a regulatory order that
established a one-half (1/2) mile regulatory buffer around natural gas wells within
which area potash mining could not occur.
The plaintiff’s claims relied on the period of time when Devon had not obtained
BLM approval to drill at the actual drilled location—i.e., from the fall of 2005 until March
27, 2006. During that approximate six-month period, Mosaic’s potash mine was more
than a full mile away from the well site. Among the multiple arguments and
considerations it presented, Devon actively disputed the plaintiff’s assertion that it had
suffered, or would suffer, injury and losses in its development of potash by virtue of the
location of the well. Devon also asserted that Mosaic’s claim of trespass should fail
because Mosaic never owned any “property right” in the potash near the well.
The case proceeded to jury trial on March 24, 2014. At the close of the plaintiff’s
case-in-chief, the trial court directed a verdict in favor of Devon on the plaintiff’s claim
of prima facie tort. The remainder of the case was submitted to the jury on April 1,
10
2014. On April 2, 2014, the jury returned a verdict awarding Mosaic the sum of one
cent ($0.01) on its claim of negligence. The jury found for Devon on the plaintiff’s
claim of trespass. The plaintiff did not appeal.
II.
Royalty Owner Litigation
A.
Court of Appeals reverses lower court order granting class
certification in proposed statewide class suit over alleged royalty
underpayments.
The case of Fitzgerald v. Chesapeake Operating, Inc.,9 involved Chesapeake’s
appeal of the district court’s order certifying a statewide class covering tens of
thousands of royalty owners and possibly 10,000 wells with claims alleging the
underpayment of oil and gas royalties. Fitzgerald alleged that Chesapeake paid
royalties to him and the proposed class members using a “common methodology” of
basing royalty payments on the net revenue received by Chesapeake under its
marketing arrangements.
Chesapeake responded that the proposed class included 75,000 leases with
varying terms covering 1,100 fields that produced gas of varying quality that required
varying amounts of gathering, compression, dehydration, treatment and processing to
bring the gas to the desired markets. Chesapeake showed that the proposed class also
included royalty owners who did not have leases with Chesapeake but were entitled to
payment from Chesapeake under compulsory pooling orders of the Oklahoma
Corporation Commission. As a result, the determination of whether any underpayments
had been made was an individual issue as to each putative class member, as were the
determinations of fraud and other tort claims.
In the court’s summation of its ruling at the beginning of its opinion, the court
stated: “Despite the trial court’s finding that Chesapeake uses a common method to
calculate royalties, the variety of leases and the varying marketability of gas throughout
the class wells will require individual determinations of whether royalties were
underpaid. Therefore, common issues do not predominate over individual issues and a
class action is not the superior method for resolving these claims.”10
After reviewing applicable statutory and case law, including recent rulings of the
Tenth Circuit Court of Appeals11 as well as the decision of the United States Supreme
___ O.B.J. ___ (Okla. App. 2014 - #111,566) (Not for Publication).
Id. at par. 1.
11 Wallace B. Roderick Revocable Living Trust v. XTO Energy, Inc., 725 F.3d 1213
(10th Cir. 2013) and Chieftain Royalty Co. v. XTO Energy, Inc., 528 Fed. Appx. 938
11
9
10
Court in WalMart Stores, Inc. v. Dukes,12 the Oklahoma Court of Appeals concluded as
follows:
In this case, the trial court's decision is 57 pages long. In that span, the
court analyzed all the possible differences in claims and strained to
dismiss those distinctions in order to find common issues which
predominate. Because our review is de novo, we need not consider each
of the trial court's voluminous findings. Our review of the record shows a
class action is not the superior method of adjudicating these claims due to
two material questions which will have to be proved individually: whether
a particular lease allows some or all GCDTP [gathering, compression,
dehydration, treatment and processing] costs to be born by the royalty
owners and at what point the gas in a particular field or gathering system
is marketable (and therefore what GCDTP services and costs are
necessary and whether they may be passed on to the royalty owner).
The question of liability is not common to the whole class, and counsel
essentially conceded the question of damages was not common to the
whole class. If a class proceeding would require thousands of mini trials
on the questions of liability and damages, it is difficult to perceive what
might be accomplished by class certification.13
The Court of Appeals reversed the district court’s order granting class certification.
B.
Royalty owner alleges Operator is obligated to provide a
replacement check when employee of royalty owner diverts the
check for his own use.
In Coastal Strategies Income Fund-C v. Mewbourne Oil Company,14 Mewbourne
as operator had sent Coastal a royalty check in the amount of $5,220.00. However, the
check was never deposited in Coastal’s account because it was intercepted by an
employee of Coastal who apparently altered the payee on the check and negotiated the
check for his own use. The present lawsuit ensued over the issue of whether Coastal or
Mewbourne should bear the loss.
At trial, the district court instructed the jury on the “mailbox rule” which provides
that, when a letter is shown to have been properly addressed and mailed, a prima facie
presumption of delivery arises until overcome by contradictory evidence. The jury
found in favor of Mewbourne.
(10th Cir. 2013).
12 131 S.Ct. 2541, 180 L.Ed. 2d 374 (2011).
13 ___ O.B.J. ___ (Okla. App. 2014 - #111,566) (Not for Publication), at par. 16.
14 84 O.B.J. 2299 (Okla. App. 2013 - #110,063) (Not for Publication).
12
In affirming the trial court’s judgment, the Court of Appeals noted that “[t]he
question of which party, payor or payee, has the responsibility to make good on a
stolen or intercepted check is not often discussed in Oklahoma case law, and the
parties’ motions contained scant citation to applicable cases.” However, Coastal argued
that Mewbourne was responsible for making good on the stolen check even if delivered
to Coastal, because of various statutes that Coastal urged in the case as well as
fiduciary duty law in Oklahoma.
The Court of Appeals found that none of those statutes applied to this situation.
The court additionally rejected the contention that Mewbourne owed a fiduciary duty to
inspect all deposited royalty checks for alteration or to detect theft, alteration or
embezzlement.
With regard to the issue of attorney’s fees, the court noted that the defendant
had incurred approximately $173,549 in attorney’s fees and $14,043 in costs in
connection with this dispute over a $5,220.00 check. The district court awarded the
defendant $75,000 in fees and some $3,800 in costs. The court noted that it was not
clear why the two parties had expended such large sums in litigation over this check.
The court noted that the attorney’s fees sought must bear some reasonable relationship
to the amount in controversy. However, the court noted that Coastal’s broad
contention in this case was that Mewbourne was responsible, as a matter of law, to
replace any check that is lost or stolen after delivery, even after it has been cashed.
Thus, the “stakes” for the defendant, as an established sender of royalty checks, were
considerably more than the approximate $5,000 at issue in this one case. Given those
circumstances, the court concluded that that award of $75,000 in fees was not
unreasonable.
C.
Court rejects Royalty Owners’ interpretation of the “free of
expenses” special wording in the oil and gas lease.
The case of Potts v. Chesapeake Exploration, L.L.C.,15 presented a dispute over
the meaning of the royalty provisions of an oil and gas lease. Chesapeake Exploration,
L.L.C. (Chesapeake), was the successor-lessee under the lease, and Chesapeake
Operating, Inc. (COI) was the operator on Chesapeake’s behalf. COI sold the gas
produced from the lease to Chesapeake Energy Marketing, Inc. (CEMI), another affiliate
of Chesapeake, at the wellhead located on the leased property. CEMI then transported
the gas through a gas gathering system and resold it to unaffiliated purchasers a gas
pipeline hubs located considerable distances from the wellhead (e.g., the Houston Ship
Channel and locations in Louisiana and Alabama). CEMI paid Chesapeake the weighted
15
760 F.3d 470 (5th Cir. 2014).
13
average sales price that CEMI received from the downstream gas sales, after deducting
post-production costs that CEMI incurs between the wellhead and the points at which
the deliveries to unaffiliated purchasers occur. Chesapeake in turn paid royalties based
upon 1/4th of the price Chesapeake received from CEMI.
Potts sued Chesapeake alleging that it was not permitted to deduct postproduction costs in calculating royalty payments. The district court granted summary
judgment in favor of Chesapeake and held that, under Texas law, Chesapeake was
permitted to calculate “market value at the point of sale” by starting with the market
value received from unaffiliated purchasers and subtracting reasonable post-production
costs incurred (a) between the downstream points of sale to unaffiliated purchasers and
(b) the point of sale by Chesapeake to CEMI. The lessors appealed.
The Fifth Circuit Court of Appeals found that three provisions of the oil and gas
lease were pertinent to this controversy. Paragraph 11 of the oil and gas lease
provided in relevant part:
The royalties to be paid by Lessee are: ... on gas ... the market value at
the point of sale of 1/4 of the gas sold or used.... Notwithstanding
anything to the contrary herein contained, all royalty paid to Lessor shall
be free of all costs and expenses related to the exploration, production
and marketing of oil and gas production from the lease including, but not
limited to, costs of compression, dehydration, treatment and
transportation.16
Paragraph 29 contained a “favored nation” provision, which states:
Lessee agrees if Lessee or any of its Working Interest Partners has agreed
to pay or later agrees to pay a higher royalty or bonus consideration to
another landowner, mineral owner or other parties, (in the same drilling
unit, spacing unit or pooled or utilized land to which the leased lands are
included), then Lessee shall pay to Lessor an amount based on such
higher royalty, or bonus consideration retroactive to the effective date of
the Lease(s).17
Paragraph 37 provided, in pertinent part:
Payments of royalties to Lessor shall be made monthly and shall be based
on sales of leased substances to unrelated third parties at prices arrived at
16
17
760 F.3d at 471-72.
760 F.3d at 472.
14
through arms length negotiations. Royalties to Lessor or leased
substances not sold in an arms length transaction shall be determined
based on prevailing values at the time in the area. Lessee shall have the
obligation to disclose to Lessor any information pertinent to this
determination.18
So, the oil and gas lease contained language providing that the royalty was to be
free and clear of all costs and expenses related to the production and marketing of gas
including, but not limited to, costs of compression, dehydration, treatment and
transportation. However, the court concluded that since it was undisputed that
Chesapeake sold gas at the wellhead, and since the lessors did not contend that the
sales to the unaffiliated purchasers were at less than market value, Chesapeake could
arrive at the market value at the wellhead by deducting reasonable post-production
costs to deliver the gas from the wellhead to the point at which the gas was sold to
unaffiliated purchasers.
As a result, it found that the district court correctly ruled that Chesapeake’s
calculation of royalties was consistent with the methodology for calculating market
value at the wellhead explained by the Texas Supreme Court in Heritage Resources,
Inc., v. NationsBank,19 The court found that “A ‘net-back’ method of calculation does
not ‘burden’ or reduce the value of the royalty.20
The Fifth Circuit affirmed the district court’s ruling in favor of Chesapeake.
For another 2014 decision of the Fifth Circuit Court of Appeals in which the
royalty provisions of certain oil and gas leases were analyzed by the court to determine
if the lessee was allowed to factor into royalty payments certain post-production
expenses, see Warren v. Chesapeake Exploration, L.L.C.21 See also Chesapeake
Exploration, L.L.C. v. Hyder,22 in which the decision of the Texas Court of Appeals was
the subject of continuing appellate proceedings at the time of the submission of this
paper.
760 F.3d at 472.
939 S.W.2d 118 (Tex. 1996). The court rejected the royalty owners’ argument that
the Heritage decision is no longer binding law in Texas. 760 F.3d at 476.
20 760 F.3d at 475.
21 759 F.3d 413 (5th Cir. 2014).
22 427 S.W.3d 472 (Tex. App. – San Antonio 2014, pet. filed).
15
18
19
D.
Court finds that the lessee properly factored into royalty
payments a proportionate share of the cost of CO2 associated
with CO2 injection activities to enhance oil and production.
In French v. Occidental Permian, Ltd.,23 the underlying oil and gas operations
involved enhanced oil recovery activities whereby carbon dioxide (CO2) was injected
into the reservoir to pressure the oil to the producing wells. “The CO2 returns to the
surface entrained in casinghead gas produced with the oil.” 24 The plaintiff royalty
owner in this lawsuit asserted that the royalty due on the casinghead gas production
must be determined as if the injected CO2 was not present, with the royalty bearing no
share of the expense of removing the CO2 from the gas. She asserted that her royalty
should be based on the value of 100% of the NGLs net of the expense of extracting
them from the gas and removing H2S, plus the value of the residue gas—i.e., the
plaintiff claimed royalty based on the value of the native casinghead gas stream that
was being processed at the prior processing plant before the CO2 flood project was put
in place.
French owned royalty interests under two oil and gas leases. The Fuller Lease
called for royalty “on gas, including casinghead gas or other gaseous substance
produced from said land and sold or used off the premises or in the manufacture of
gasoline or other product therefrom” equal to “the market value at the well of oneeighth (1/8th) of the gas so sold or used”.25 The Cogdell Lease called for royalty of
“1/4 of the net proceeds from the sale” of “gasoline or other products manufactured
and sold” from casinghead gas “after deducting [the] cost of manufacturing the
same.”26
After a four-day non-jury trial, the trial judge ruled in favor of the royalty owner
and awarded her some $10 million in underpaid royalties, declaratory relief as to Oxy’s
ongoing royalty obligations consistent with the award and attorney fees. The Texas
Court of Appeals reversed based upon its disagreement with the way in which the
plaintiff had computed her damages.27
In affirming the Court of Appeals on different grounds, the Texas Supreme Court
concluded that the plaintiff, having given Oxy the rights and discretion to decide
whether to re-inject or process the casinghead gas, and having benefitted from that
decision, must share in the cost of CO2 removal. Under the Fuller Lease, that cost
23
24
25
26
27
2014 WL 2895999 (Tex. 2014).
Id. at *1.
Id.
Id.
391 S.W.3d 215 (Tex. App. – Eastland 2012).
16
must be considered in determining the market value of the gas at the well, on which
French’s royalty is based. Under the Cogdell Lease, the cost of CO2 removal must be
included in the cost of manufacturing the NGLs and residue gas. The court noted that
Oxy took the position that the gas processing activities directed toward returning CO2
to the reservoir were part of the production process, and the monetary fee Oxy paid a
midstream company for those expenses was not charged to the royalty owner. French
argued, however, that she should not bear any part of the 30% of NGLs that Oxy paid
Kinder Morgan as an in-kind payment for the post-production expense of CO2 removal,
but the court rejected that contention.
The judgment of the Court of Appeals in favor of Oxy was affirmed.
III. Oil and Gas Lease Cancellation, Termination and Breach of
Obligation Cases (Other Than Royalty)
A.
Court addresses class claims that operator of two units failed to
compensate the royalty owners for alleged drainage damages that
occurred over twenty years prior to the lawsuit, and claims for
disgorgement of profits.
In December, 2013, the Oklahoma Supreme Court issued its much-awaited decision in
Krug v. Helmerich & Payne, Inc.28 The case involved two 640-acre drilling and spacing units in
Western Oklahoma in which Helmerich & Payne (H&P) and others were the working interest
owners, and H&P was the operator. H&P divested its interest in the subject leases and wells in
1998.
The case was certified as a class action lawsuit on behalf of the royalty owners in the
two sections of land. The complex factual backdrop of the case (which included the settlement
of a take-or-pay gas contract lawsuit against ANR Pipeline Company) is detailed in the court’s
opinion. The plaintiffs alleged, among other things: (a) that H&P failed to act as a reasonably
prudent operator and allowed uncompensated drainage of natural gas to occur from the two
sections beginning January 1, 1982, and ending December 31, 1989; (b) that H&P received
payment for uncompensated drainage through its October 31, 1989, take-or-pay lawsuit
settlement with ANR; (c) that H&P concealed the settlement from the royalty interest owners
and that the plaintiff class was entitled to a share of the sum allegedly received by H&P under
that settlement for the asserted drainage claims; (d) that the class should recover all profits
H&P obtained from the monies that allegedly should have been paid to the royalty owners over
twenty years earlier; and (e) that the defendant’s conduct involved fraud, the defendant had
been unjustly enriched as a result, and the class should be awarded both actual and punitive
damages.
The case proceeded to a jury trial. The jury returned a verdict in favor of the plaintiff
class on the alternative claims and awarded (a) $3,650,000 for breach of the implied duty to
28
2013 OK 104, 320 P.3d 1012.
17
prevent uncompensated drainage, (b) $4,055,000 for breach of fiduciary duty for failure to
prevent uncompensated drainage, and (c) $6,845,000 for constructive fraud related to the ANR
settlement. Based on its finding that H&P had been unjustly enriched, the trial court conducted
a second-stage hearing for the jury to determine, relative to the “disgorgement of profits”
request, the amount of gross profit H&P made on the $6,845,000 that H&P had held since
October 31, 1989. After receiving evidence, the jury awarded the class $61,662,000 for
disgorgement of profits.
However, the trial court found that the award for disgorgement of profits should be
increased to $112,677,750. To that amount, the court added the $6,845,000 in damages and
set the total amount awarded against H&P as $119,522,750. The court also awarded interest on
the $6,845,000 amount from the date of rendition of the first award (November 21, 2008), and
interest on the remaining $112,677,750 amount from the date of rendition of the second award
(January 8, 2009) until paid in full. The court further awarded the class its costs and attorney
fees.
In reversing in part and affirming in part the judgment of the trial court, certain of the
key rulings of the Oklahoma Supreme Court are as follows:
First, with regard to H&P’s contention that the lower courts had incorrectly allowed a breach of
contract claim to be recast as an equitable unjust enrichment claim, leading to the court’s
disgorgement of lost profits, the court recognized long-standing principles of law to the effect
that a plaintiff may not pursue an equitable remedy when the plaintiff has an adequate remedy
at law. With regard to contract lawsuits in particular, the court stated in part:
Parties initiate contracts to provide a degree of certainty in their business
transactions. . . The essential principle of contract law is the consensual
formation of relationships with bargained-for duties. The obvious corollary is
bargained-for liabilities for failure to perform those duties. ‘Important to the
vitality of contract is the capacity voluntarily to define the consequences of the
breach of a duty before assuming the duty.’ Isler v. Texas Oil & Gas Corp., 749
F.2d 22, 23 (10th Cir. 1984).29
The court found that the plaintiffs in this case enforced their contract rights and were awarded
damages in the amount of $3,650,000 based on a breach of oil and gas lease contracts with
H&P. That award afforded the plaintiff class an adequate remedy at law, with the result that the
equitable claims cannot be recognized. The court reversed the $4,055,000 award for alleged
breach of fiduciary duty for failure to prevent uncompensated drainage, and further reversed
the $119,522,750 award for disgorgement of profits and constructive fraud.
Second, the court rejected H&P’s contention that the trial court erred in instructing the
jury regarding the allegations of uncompensated drainage. Specifically, H&P asserted that the
jury should have been instructed to determine the “net flow” of gas—i.e., whether the outflow
of gas from the sections was compensated for by counter-drainage and an in-flow of gas from
adjoining sections. The court found that, under the facts presented in this case, H&P’s gas
29
Id. at ¶35.
18
contract litigation settlement with ANR “was based on a time period where there would not
have been an outflow of gas because ANR was not taking gas at that time.”30 The damages
award of $3,650,000 for breach of contract (i.e., breach of the implied duty to prevent
uncompensated drainage) was left intact by the court.
Third, with regard to the contention of the plaintiff class that H&P violated a fiduciary
duty to the class to prevent uncompensated drainage, the court found that “the law is longstanding and settled that a producer’s liability is purely a contractual one and in no sense
fiduciary.”31 The court further found that the trial court erred in presenting the jury with an
instruction that permitted the jury to find that H&P owed a fiduciary duty to the plaintiffs to
prevent uncompensated drainage. Rather, because H&P’s duty was contractual (i.e., based on
the oil and gas lease), the court held that the remedy should be based on breach of contract.
Fourth, the court addressed the assertion that the claims for breach of implied covenant
under the oil and gas lease were barred by the five-year statute of limitations under 12 O.S.
2011, § 95(A)(1) since the lawsuit was filed on December 22, 1998. The court rejected this
contention and cited prior authority or the proposition that “a defendant is estopped from
interposing the defense of a time bar when the defendant’s conduct has induced the plaintiff to
refrain from timely bringing an action because of the defendant’s false, fraudulent or misleading
conduct or some act that induces the plaintiff to refrain from timely bringing an action.”32
In sum, the court left intact the jury’s verdict for $3,650,000 in damages for breach of
the oil and gas lease due to uncompensated drainage.33 The court reversed the awards of: (a)
$4,055,000 in damages for breach of fiduciary duty for failure to prevent uncompensated
drainage, and (b) $119,522,750, representing $6,845,000 in in damages for constructive fraud
plus $112,677,750 in disgorgement of profits.34 The case was remanded to the trial court to
revisit its award of interest, costs and attorney fees in a manner consistent with the court’s
opinion.35
B.
Court finds that the trial court erred in granting summary
judgment in favor of the defendants in an oil and gas lease
termination action due to the existence of disputed issues of
material fact.
The case of Stone v. Payne Exploration Company,36 involved a suit by mineral
owners seeking a determination that the underlying 1972 oil and gas lease had expired.
The subject lease contained a 60-day cessation of production clause which stated in
Id.
Id.
32 Id.
33 Id.
34 Id.
35 Id.
30
at ¶ 31.
at ¶ 18.
at ¶ 40, citing Jarvis v. City of Stillwater, 1987 OK 5, ¶ 4, 732 P.2d at 472-743.
at ¶ 42.
at ¶ 43.
at ¶ 46.
36 85 O.B.J. 446 (Okla. App. 2014 - #111,082) (Not for Publication).
19
31
part as follows:
If after discovery of oil or gas on said land . . . the production thereof
should cease from any cause after the primary term, this lease shall not
terminate if Lessee commences additional drilling or reworking operations
within sixty (60) days from the date of cessation of production . . .”37
The basic chronology of the key events was as follows:
Feb. 1973
The Griffin A well began to continuously produce oil and/or gas in
paying quantities from the lease.
Late 2009
The Griffin A experienced a mechanical problem and ceased
producing oil and gas in paying quantities.
Thereafter
The defendants began reworking the well, ultimately spending over
$112,000 in doing so.
Jan. 22, 2010
The defendants removed the pulling unit from the well site.
Thereafter
The defendants continued to monitor the well’s pressure on a
weekly basis.
March 2010
The defendants removed the electronic flow meter from the well.
April 22, 2010
Payne Exploration, the operator of the Griffin A well, filed an
application with the Oklahoma Corporation Commission (OCC)
requesting the creation of a 320-acre horizontal drilling and spacing
unit, encompassing the plaintiffs’ 160-acre mineral estate.
May 11, 2010
The OCC issued Payne Exploration a permit to begin drilling the
Rising 1-30H well.
May 20, 2010
The OCC issued its interim order creating the 320-acre horizontal
unit.
June 8, 2010
Payne Exploration began drilling the Rising 1-30H well.
Aug. 9, 2010
The Rising 1-30H well was completed.
37
Id. at par. 2.
20
Sep. 7, 2010
The OCC issued its final order creating the 320-acre unit.
Oct. 2010
The Rising 1-30H well began producing in paying quantities.
Thereafter
The plaintiffs rejected the royalty payments tendered by Payne
Exploration on the new well and filed this lawsuit to cancel the
lease.
The plaintiffs alleged in the present lawsuit that the lease terminated because
more than 60 days passed between the time the defendants abandoned reworking
operations on the Griffin A well and the time the defendants commenced drilling
operations on the Rising 1-30H well. The trial court granted summary judgment to the
defendants and held that the defendants were still reworking the Griffin A well through
March 2010 and started work on drilling the Rising 1-30H well in April 2010. The
plaintiffs appealed.
The Court of Appeals first noted that, after the expiration of the primary term of
an oil and gas lease, the effect of a cessation of production clause is to modify the
habendum clause and to extend or preserve the lease while the lessee resumes
operations designed to restore production. The literal provisions of the clause in each
case will govern what type of operation must be commenced or resumed.
The cessation of production clause contained in the lease in this case required
the lessee to commence additional drilling or reworking operations within 60 days from
the date of cessation of production from the Griffin A well. The court found that, since
it was uncontested that the defendants began their reworking activities within 60 days
of the time the well stopped producing, the issue in this suit was whether the efforts
and timing of the reworking and later drilling operations were sufficient to extend the oil
and gas lease.
The court concluded that the factual record might support a conclusion that the
defendants’ actions under the circumstances constituted a bona fide effort to restore
the lease to production. However, it found that a court could not make such a finding
as a matter of law. Rather, whether the defendants’ reworking and drilling operations
constituted reasonable, diligent and good faith efforts sufficient to extend the lease.
Such a determination must be made by the fact-finder. Accordingly, the summary
judgment ruling below in favor of the defendants was reversed and the case was
remanded for further proceedings.
21
C.
Court determines whether purported agent of XTO had authority
to bind XTO to an agreement to buy an oil and gas lease from the
plaintiffs.
In Eckles v. XTO Energy, Inc.,38 the issue in dispute was whether XTO was liable
as a principal with respect to an oil and gas lease agreement made between defendant
CGZ LLC and the plaintiff mineral owners. The factual backdrop as described by the
court was as follows: In February 2008, CGZ (a lease broker with general authority to
enter into oil and gas leases on behalf of XTO) sent the mineral owners a letter
proposing to acquire a lease from them that would “vest in possession” of CGZ upon
either the release of an existing oil and gas lease that clouded title, or a determination
that the existing lease was not valid. The offer letter enclosed proposed oil and gas
leases for signing and promised the payment of $634,285.00 for each of the mineral
owners. The mineral owners signed the leases in the presence of CGZ’s representative.
Approximately nine months later, in November 2008, XTO instructed CGZ to
cease leasing minerals in the area where the subject property was located. The mineral
owners obtained a release of the oil and gas lease that had clouded their title.
However, when they received no payments, they filed suit against CGZ and XTO in June
2009 to recover the $634,285.00 payments. XTO denied liability and cross-claimed
against CGZ, arguing that CGZ acted outside of its contractual authority as a lease
broker for XTO.
The trial court granted summary judgment in favor of the mineral owners and
against XTO. The mineral owners dismissed their claims against CGZ. The court
certified its judgment against XTO for immediate appeal notwithstanding that the court
had not disposed of XTO’s cross-claims against CGZ.
In affirming the trial court’s ruling against XTO, the Court of Appeals found in
part that the record contained numerous emails between CGZ and XTO establishing
that CGZ generally had authority to attempt to acquire oil and gas leases on behalf of
XTO. The court further found that the letter agreements signed by the mineral owners
were not lacking in consideration and did not lack necessary terms. In particular, the
Court of Appeals rejected the contention that the letter agreement requiring XTO to
perform at such future time as the existing oil and gas lease was removed as a cloud on
title was void for vagueness.39 The court additionally found that the agreements did
not violate the Rule Against Perpetuities, and it concluded that the district court did not
err in finding that the mineral owners properly relied on the apparent authority of CGZ
38
85 O.B.J. 80 (Okla. App. 2013 - #111,327) (Not for Publication).
The court noted that both CGZ and the mineral owners knew that the validity of the
existing oil and gas lease was the subject of pending litigation, and that litigation is a
process with a definite and reasonably predictable end point.
22
39
to bind XTO to the agreement.
D.
Court determines whether the special provisions of the oil and
gas lease required that a well be “capable of producing in paying
quantities” before the payment of shut-in royalties could extend
the term of the lease.
In PNP Petroleum I, LP v. Taylor,40 the parties to an oil and gas lease dated June
1, 2009, had included the following special savings clause:
“ii. SHUT-IN ROYALTY (Savings) If, at the expiration of the primary term
there is located on the lease premises a well or wells not
producing oil/gas in paying quantities, Lessee may pay as royalty
a sum of money equal to Twenty ($20) dollars per proration acre
associated with each well not producing. The shut-in well royalty
payment will extend the term of this lease for a period of one (1) year.
Lessee may extend this lease for one (1) additional year by the payment
of a like sum of money. MAXIMUM SHUT-IN It is agreed that this lease
cannot be maintained by the payment of shut-in royalty for a period of
more than two (2) years beyond the expiration date of the primary
term.”41
At the time the oil and gas lease was negotiated and signed, 13 wells that were
not actually producing oil or gas were already located on the leased premises. Those
wells had been drilled by a prior lessee whose lease had expired.
On May 12, 2010, PNP sent the mineral owner-lessors payment under the above
savings clause with the stated purpose of extending the term of the lease. The mineral
owners rejected the tendered payment and took the position that no well located on the
leased premises was “capable” of producing oil or gas in paying quantities, and that a
“shut-in royalty” payment would only extend a lease under Texas law if the well that
was shut-in was “capable” of producing in paying quantities. At the time the payment
was rejected, the only wells located on the leased premises were the same 13 preexisting wells that had been drilled by the prior lessee, and those wells were not
producing in paying quantities.
PNP filed suit seeking a declaratory judgment that its tender of payment
extended the term of the lease. On cross motions for summary judgment, the trial
court granted partial summary judgment in favor of the mineral owners.
40
41
2014 WL 2106572 (Tex. App. – San Antonio 2014).
2014 WL 2106572 at *1.
23
Seven months later, PNP filed a Motion to Reconsider the earlier summary
judgment ruling. In support of that motion, PNP attached an Affidavit providing details
of the negotiations between the parties preceding the signing of the lease. Exhibits to
the Affidavit included email correspondence and drafts revealing changes made to the
lease form, and the savings clause in particular, during the negotiations. The mineral
owners objected to the Affidavit and attached exhibits on the ground that those
documents were “extraneous, parol evidence offered ‘to vary, contradict, and/or create
ambiguity in the unambiguous PNP Leases.’”42 Hearsay and relevancy objections were
also made. PNP responded that the Affidavit and its exhibits should be considered as
“surrounding circumstances” that could be properly considered by the court.
The trial court sustained the mineral owners’ objections and struck the Affidavit
and exhibits from the record. The court then denied PNP’s Motion to Reconsider. PNP
appealed.
In reversing the trial court’s ruling in favor of the mineral owners and rendering
judgment in favor of PNP finding that the term of the oil and gas lease was extended by
PNP’s tendered payment, the Texas Court of Appeals found in part as follows:
1.
The Court of Appeals noted that the mineral owners’ primary objection to
the Affidavit and exhibits offered in support of the Motion to Reconsider was that those
documents were alleged to be inadmissible extrinsic, parol evidence offered to
contradict or create ambiguity in the lease. The court further observed that one of the
primary propositions PNP sought to establish with this evidence was that the red-lined
drafts of the lease and savings clause showed (A) that an earlier draft of the savings
clause was expressly worded to provide that a well had to be “capable of producing oil
or gas in paying quantities” in order for the lease to be extended by the payment of the
shut-in royalties, and (B) that wording was modified by the parties to replace the
phrase “capable of producing oil/gas in paying quantities” with the phrase “not
producing oil/gas in paying quantities” in describing the type of well that would give rise
to a right to extend the lease with such payments.43
2.
The appellate court reviewed prior decision of the Texas Supreme Court
and concluded that trial courts are allowed to consider contract negotiations as
surrounding circumstances in construing an oil and gas lease. The court also cited its
own prior decision in BP Am. Prod. Co. v. Zaffirini,44 in which the court held:
“ ‘[N]egotiations prior to or contemporaneous with the adoption of a
42
43
44
Id. at *2.
Id. at *6.
419 S.W.3d 485 (Tex. App. – San Antonio 2013).
24
writing are admissible in evidence to establish . . . (c) the meaning of the
writing, whether or not integrated.’ . . . In BP Am. Prod. Co., this court
considered evidence of the parties’ negotiations, including the offers and
counter-offers made. 419 S.W.3d at 500-01.”45
The court concluded that the parol evidence rule did not bar the introduction of the
evidence showing the deletions and changes made in the drafts of the oil and gas lease
during the parties’ negotiations, and that the trial court erred in ruling otherwise.
3.
In likewise finding that there was no valid hearsay objection, the court
stated that an out of court statement, offered to show what was said, rather than the
truth of what was said, is not hearsay. Since the deletions and revisions made in the
course of negotiating the oil and gas lease were offered to show what was said, the
appellate court ruled that the trial court also abused its discretion in sustaining the
hearsay objections to the lease drafts.
4.
With regard to the final evidentiary objection made by the mineral owners
to the proposed consideration of the redline drafts of the lease on the grounds that the
evidence was not relevant, the court found that “the lease drafts have a logical
connection in determining the intent of the parties in selecting the language used in the
Savings Clause. Accordingly, the trial court abused its discretion in sustaining the
relevancy objection.
5.
With regard to the heart of the oil and gas lease interpretational dispute,
the appellate court recognized the general rule that “[i]f a lease term has a generally
accepted meaning in the oil and gas industry, we use its generally accepted meaning.”46
The mineral owners asserted that the term “shut-in royalty” has a special meaning in
the oil and gas industry that requires that the underlying well be “capable” of producing
in paying quantities before shut-in royalty payments will extend the lease. However,
the court found that the general meaning had no application in this case because the
parties had expressly stricken from earlier drafts of the lease a requirement that the
wells be “capable” of commercial production.
6.
Taking into consideration the parties negotiations as reflected in the
various drafts of the lease and the plain language of the lease, the court concluded that
the parties did not intend to apply the oil and gas industry’s generally accepted
meaning of the term “shut-in royalty” in the savings clause of the subject lease. “Quite
simply, the parties could not have intended for the law to engraft into their agreement
45
46
2014 WL 2106572 at *8.
2014 WL 2106572 at *9.
25
the very language they removed.”47
Since wells were located on the leased premises at the end of its primary term
that were not producing oil/gas in paying quantities, the court held that PNP’s May 12,
2010 payment extended the term of the lease as a matter of law.
E.
Court declares the respective rights created under two oil and
gas leases from the same mineral owner lessors.
The case of Unit Petroleum Company v. David Pond Well Service, Inc.,48 involved
request for declaratory judgment related to the construction of two oil and gas leases:
(a) An Oil, Gas and Mineral Lease between Unit, as lessee, and the Tarboxes, as lessors
(the Unit Lease), and (b) a subsequently-executed Wellbore Oil & Gas Lease between
Pond, as lessee, and the Tarboxes, as lessors (the Pond Wellbore Lease). At the
conclusion of a bench trial, the trial court interpreted the leases and held that (a) the
Pond Wellbore Lease created an appurtenant right in Pond’s favor permitting him to
exclusively assign, designate and/or claim an eight acre proration unit for Pond’s
wellbore, and (b) Unit was estopped from asserting ownership of an exclusive right to
designate a proration unit for Pond’s wellbore.49 Unit appealed. Unit asserted on
appeal that the trial court erred in, among other things, finding that the wellbore lease
granted Pond an appurtenant contractual right to designate or establish a proration unit
extending beyond the physical limits of Pond’s leasehold estate.
The appellate court recognized that, when they granted the Unit Lease, the
Tarboxes reserved “the wellbore of the Tabox (sic) Unit #1 well located on the leased
premises, to be produced by Tarbox or his assigns and lessees.”50 The reservation was
limited to the wellbore as it then existed and production only from the Cleveland
formation in a 60-foot interval in which the wellbore was then completed. The court
found that the reservation contained no language reserving to the Tarboxes any right to
use acreage outside the wellbore, and did not reserve to them the executive right to
assign property outside the wellbore to a proration unit for purposes of a production
allowable.
While Pond and the trial court construed the reservation to carry with it the
contractual right, for regulatory purposes only, to assign, designate and/or claim the 80
acre proration unit for the Tarbox #1 well that was on file with the Railroad Commission
at the time of that reservation, the appellate court found that interpretation to be
47
48
Id. at *10.
2014 WL 2118091 (Tex. App. – Amarillo 2014).
Id. at *4.
50 Id. at *6.
26
49
unreasonable. Rather, Pond’s interpretation would give the reserved wellbore interest
holder rights that are greater than necessary to enable Pond to produce from the
existing wellbore and would grant Pond rights that would interfere with the
development activities clearly anticipated and intended by the Tarboxes and Unit when
the Unit Lease was executed.
The Court of Appeals, after reviewing the circumstances, reversed the judgment
of the trial court and held that Unit had the right under its lease to use the surface area
of its lease to the extent that it was reasonably necessary to develop and produce the
minerals, including the exclusive executive right to establish a proration unit
encompassing any of its leasehold estate, subject to an obligation to designate a
sufficient amount and configuration of acreage to permit Pond to produce oil, gas and
other minerals from the Tarbox #1 wellbore. That is, Unit had to designate a proration
unit of sufficient acreage to satisfy the minimum proration unit necessary to meet
regulatory requirements to obtain an allowable to produce from that wellbore. Pond did
not acquire under its wellbore lease the appurtenant right to establish, designate or
claim a proration unit encompassing any property other than the wellbore itself. The
case was remanded to the trial court for further proceedings consistent with the court’s
opinion.
F.
Court holds that lessee had the right to surrender the oil and gas
lease before its primary term and avoid liability under separate
clause of the lease that required the drilling of five wells.
In First Tennessee Bank National Association, as Trustee v. Pathfinder
Exploration, LLC,51 the plaintiff Trusts had granted an oil and gas lease to Pathfinder
which provided for a bonus consideration of $2,300,433.49, and a primary term of 5
years. Pertinent to the controversy in the present lawsuit, the lease also included the
following provisions:
“3. During the primary term hereof [five years] or any extensions as
provided for herein, Lessee shall have the obligation to drill or cause to be
drilled five (5) oil & gas wells on the leased premises.... In the event that
Lessee fails to drill the obligated wells .... Lessee will pay to Lessor the
sum of $100,000 per well not commenced, due immediately upon the
expiration of the primary term or any extension as provided for herein.”
The oil and gas lease further provided that
“[Pathfinder] may at any time and from time to time surrender this lease
51
2014 WL 1910601 (8th Cir. 2014) (applying Arkansas law).
27
as to any part or parts of the leased premises....”
Pathfinder surrendered the lease before the expiration of its primary term and
before drilling any wells. Pathfinder asserted that the amounts specified in the abovequoted paragraph 3 of the lease were not due because it surrendered the lease before
the primary term expired. The Trusts sued Pathfinder for the amounts they contended
were owed under paragraph 3. The District Court granted summary judgment in favor
of Pathfinder. The Trusts appealed.
In affirming the ruling in favor of Pathfinder, the Eighth Circuit agreed with the
District Court that the prior decision in Frein v. Windsor Weeping Mary, LP,52 provided
analogous authority and supported the position of Pathfinder.
The court rejected the Trusts assertion that Frein was distinguishable from the
facts in the Pathfinder case under the theories that (a) the bonus consideration here
included the drilling requirement and its liquidated damages provision, which could not
be abrogated, and (b) Pathfinder could not surrender the entire lease. The court found
that the relationship between the drilling requirement and the bonus consideration was
the same in this case as in Frein. With respect to the second argument that focused on
the specific wording of the surrender clause in the Trusts’ lease, the court held that,
absent limiting language, the right to surrender as to any part necessarily includes the
right to surrender or cancel as to the whole.
G.
Court finds that lessors’ acceptance of de minimis royalty
payments did not ratify oil and gas lease.
The case of Price v. K. A. Brown Oil and Gas, LLC53 involved an oil and gas lease
which had been entered into for the purpose of developing two wells that had been
drilled under an earlier oil and gas lease. The new lease at issue in this suit, which was
entered into in November 1988, did not require the lessee to drill any additional wells.
Rather, the lease only required that the two previously-drilled wells be made
productive.
In particular, paragraph 14 of the lease stated in part that “[t]he purpose of this
lease is so that the Lessee may put the existing wells into production.” 54 The lessee
was required to put the first well into production within six months, and the second well
into production within the following six months. Paragraph 14 of the lease then stated
that “[i]f this schedule is not adhered to, then the Lessee shall release said lease back
52
2009 Ark. App. 774, 366 S.W.3d 367 (2009).
2014 WL 2466360, 2014-Ohio-2298 (Ohio App. 2014).
54 Id. at *2.
28
53
to Lessor or begin paying shut-in royalties.”55 The lease also allowed the mineral
owners to take 200,000 cubic feet of free gas for domestic use, at their sole risk and
expense. Any additional volume of gas would be paid for at a fair domestic rate.
The first well was put into production in the spring of 1988, but the second well
was not put into production until 1995. There is no evidence that shut-in royalties were
ever paid.
In August 2012, some 24 years after the lease had been executed, the mineral
owners filed a declaratory judgment action asking the court to declare that the lease
had terminated due to expiration of the primary term, the non-production of the two
wells, and the failure of the lessee to pay production or shut-in royalties.
The mineral owners presented evidence (a) that the second well was not put into
production until 1995, (b) that no production royalties had been paid except for five de
minimis checks in 2004 and 2005 totaling $68.59, (c) that no shut-in royalties had been
paid, and (d) that neither the current lessee nor the prior lessees under the expired
lease reported any production to the Ohio Department of Natural Resources until 2008.
There was no evidence that either well produced in paying quantities prior to 1995.56
The lessee responded by (a) introducing production records from 2003 – 2011,
(b) showing that the mineral owners admitted that they had no personal knowledge of
what occurred with the wells from 1988 to 1999, and (c) showing that a mineral owner
had used some of the gas for personal purposes. The lessee argued that the mineral
owners had ratified the lease by their acceptance of royalties, by taking gas for
personal use, and by failing to take affirmative action to terminate the lease in a timely
manner.
The trial court granted summary judgment in favor of the mineral owners on the
grounds that the lease required both wells to be put into operation by November 1,
1989, and that if both wells were not put into production by that date, the lease
terminated. The court held that paragraph 14 of the lease did not require any
affirmative action by the mineral owners to terminate the lease. The lessee appealed.
In affirming the trial court’s summary judgment ruling in favor of the mineral
owners, the Ohio Court of Appeals held in part as follows:
1.
The court noted that the lessee “presents one argument on appeal, and
this was the only argument made in opposition to summary judgment at the trial court
55
56
Id.
Id. at *5.
29
level.”57 The lessee argued that the mineral owners ratified the 1988 lease by
implication due to certain actions on their part, and that the mineral owners cannot now
deny that the lease is still valid.
2.
However, the court found that the doctrine of ratification was not
applicable in this case. It found that, in Ohio, the doctrine of ratification “refers to
actions taken by a corporation to validate an unauthorized contract.” 58 Since the
mineral owners were not corporate entities, the ratification doctrine was found to have
no application.
3.
The court noted that reference had also been made in the brief to the
theories of waiver and estoppel. However, since those defenses were not raised before
the trial court in the summary judgment proceedings, the court found that it did not
need to consider those defenses on appeal. However, the court proceeded to review
the evidence and it found that the concepts of waiver and estoppel could not even be
applied in this lawsuit. The mineral owners’ acceptance of $68.59 in royalties did not
equate to the waiver of an express and automatic termination clause in the lease. With
regard to the free gas clause of the lease, the evidence in the record did not show any
violation of that clause by the mineral owners. The trial court’s ruling was affirmed.
H.
Court determines whether the assignee received wellbore rights
only, and whether the assignees unilateral modification of the
assignment after it was signed rendered the assignment void.
In Armstrong v. Berco Resources, LLC,59 Armstrong sought to quiet title to an
interest in the Bakken formation that he purchased from Berco. Armstrong also sued
Encore for breaching a letter offer under which Encore offered to purchase Armstrong’s
interest in the Bakken formation, and for trespassing on, and converting the oil and gas
attributable to, Armstrong’s interest. Berco filed a counterclaim asking the court to
declare that the Assignment and Bill of Sale under which Armstrong received his Bakken
interest from Berco was null and void because Armstrong altered the assignment after it
had been executed by Berco but before it was recorded.
The courts found that the “purchase agreement” contained wording that would
normally be interpreted to convey only wellbore interests.60 However, they observed
57
Id. at *3.
Id.
59 752 F.3d 716 (8th Cir. 2014) (applying North Dakota law).
60 752 F.3d at 720: “The Purchase Agreement’s granting clause states that ‘[t]his
transaction will only cover all of Berco’s interest in the two wellbores, associated
equipment and production from the Bakken formation as described on Exhibit ‘A’.” The
Exhibit A described the well names, the working interest percentages and the net
30
58
that the Exhibit A to the “assignment” contained different language that was relied
upon by Armstrong in asserting that he acquired the leasehold rights in the Bakken and
not just wellbore rights.61 The court found that the language in the Exhibit A to the
assignment that described the assigned rights as including “production from the Bakken
formation” gave rise to an ambiguity in the assignment. Specifically, the court found
that the reference to “production from the Bakken formation”
“could mean either (a) all oil and gas produced from the Bakken
underlying the property on which the two wells are located, regardless of
whether it is produced through those two wells or through other wells
(i.e., a leasehold interest) or (2) the oil and gas produced from the
Bakken through only those two wellbores (i.e., a wellbore-only interest).62
The district court granted summary judgment in favor of the defendants on
Armstrong’s breach of contract claim and in favor of Berco on its counterclaim, finding
that the modified assignment recorded by Armstrong was null and void on its face. At
the conclusion of the trial on the remaining claims, the court dismissed Armstrong’s
quiet title, trespass and conversion claims because it found that Armstrong received
only a wellbore assignment from Berco and had no interest in the properties beyond the
wellbores. Armstrong appealed.
In affirming the district court’s rulings, the Circuit Court of Appeals found in part
as follows:
1.
The court noted that the expert witnesses on both sides of the case had
testified that “the well-established custom and usage in the oil and gas industry
indicates that if the parties intended to convey an interest in an oil and gas lease or
leases, there would be not only a mention of the leases, but an adequate legal
revenue interest percentages, and then added the following footnote to the stated net
revenue interest percentage numbers: “ *limited to the Bakken formation found
in both wellbores at footage depths between 9,800’ and 10,350’ only.”
61 Id. “[The assignment’s] granting clause states that ‘[Berco] hereby assigns, grants,
bargains, sells and conveys to [Armstrong] all of [Berco’s] right, title and interest in and
to the assets, properties, and production described on Exhibit ‘A’” The Exhibit A to the
assignment described the well names, the working interest percentages and the net
revenue interest percentages, and then added the following footnote to the stated net
revenue interest percentage numbers: “ *limited to the wellbores, associated
equipment and production from the Bakken Formation found at footage
depths between 9,800 feet and 10,350 feet only.” (Emphasis added by the
court).
62 752 F.3d at 721.
31
description of the property subject to the leases.”63
2.
The court affirmed the district court’s finding “that ‘[c]ustom and usage,
along with Berco’s stated intention to convey only an interest in the two well bores,
demonstrate[s] that the’ assignment from Berco to Armstrong ‘was intended as a
wellbore-only assignment.’”64 Because of that conclusion, the claims for trespass and
conversion were properly dismissed by the district court.
3.
It was undisputed in the proceedings below that Armstrong amended the
Exhibit A to the assignment, prior to recording it, by adding a fourth column of
descriptive information about the wells which showed the real property description of
the tracts of land on which the wells were located. Armstrong asserted that the
addition of that information was necessary for proper indexing of the assignment by the
recording officer and that the parties had “anticipated”65 the addition of that
information. However, the appellate court found that the district court properly ruled,
under North Dakota law, that Armstrong’s unilateral alteration of the Exhibit A before
recording it rendered the recorded assignment null and void.
IV.
Oil and Gas Contracts, Transactions and Title Matters
A.
AMI provisions of Exploration Agreement found by court to not
require that acreage offered to, but declined by, other parties to
the agreement be re-offered to those who elected to purchase
their proportionate shares of the newly-acquired acreage.
The case of Cynostar Energy, Inc. v. Chesapeake Exploration, L.L.C.,66 involved a
dispute between parties to an Exploration Agreement that contained a provision that
recognized a defined geographical area of mutual interest (AMI) between the parties.
The AMI provision stated in part as follows:
[A]ny acreage acquired within the AMI and outside the Drillsite Sections
after the closing date will be offered to the other Parties and those Parties
shall have the option to take their proportionate share of the interest
based on the percentages in Article I by paying their proportionate share
of actual acquisition costs within fifteen (15) days of receipt of offering.67
63
64
65
66
67
752 F.3d at 722.
Id.
752 F.3d at 725.
2014 OK CIV APP 7, 317 P.3d 217.
Id. at ¶ 2.
32
Chesapeake acquired oil and gas leasehold acreage within the AMI and, pursuant to the
above contractual commitment, offered the leasehold acreage to the other parties.68
The Cynostar plaintiffs, parties to the Exploration Agreement, elected to purchase their
proportionate shares of the leasehold acreage. However, another party to the
agreement elected to decline the opportunity to purchase a share of the acreage.69
Chesapeake did not offer the Cynostar plaintiffs the option to acquire a share of the
acreage that the other party declined.70
The Cynostar plaintiffs filed the present lawsuit seeking a judicial declaration that
the AMI provision of the Exploration Agreement required Chesapeake to offer to the
other parties the right to acquire a proportionate share of the acreage declined by the
other party.71
The trial court granted summary judgment in favor of Chesapeake, ruling that
“[f]or the Court to interpret the language as Plaintiffs request would be to add an
option that did not exist and to read into the contract words that it does not contain.” 72
The Cynostar plaintiffs appealed.
In affirming the ruling of the district court in favor of Chesapeake, the Oklahoma
Court of Appeals found that the Exploration Agreement was clear and unambiguous on
the issue in dispute.73 The court recited a series of fundamental rulings of contract
interpretation, including the rule to the effect that if the language of the contract is
clear and explicit and does not involve an absurdity, the language of the contract will
govern its interpretation.74 It noted that the AMI provision was entirely silent on subject
of the rights of the others if one or more of the parties to the Exploration Agreement
declined the offer of an interest in newly-acquired acreage.75 The court further
observed that “if the parties had intended to require the ‘re-offer’ of rejected acreage,
they could have easily provided” such a requirement.76
The Court of Appeals affirmed the summary judgment ruling in favor of
Chesapeake.
Id.
Id.
70 Id.
71 Id.
72 Id.
73 Id.
74 Id.
75 Id.
76 Id.
68
69
at ¶ 3.
at ¶ 4.
at
at
at
at
at
at
¶
¶
¶
¶
¶
¶
5.
7.
13.
9, citing 15 O.S. 2011, § 154.
11.
12.
33
B.
Court addresses lien priority contest between pre-existing oil and
gas mortgage and the well lien of a service company under a unit
agreement and 52 O.S. 2011, §287.8.
The court in Gasrock Capital, L.L.C. v. Endevco Eureka, L.L.C., 77 was presented
with a lien priority contest between an oil and gas mortgagee (Gasrock Capital) and a
well service company (Pan American Drilling) who contracted with the operator of the
unitized field and asserted a statutory oil and gas lien. The subject unit was formed
under the unitization provisions of 52 O.S. 2011, §287.1, et seq.78 The underlying oil
and gas leases on which the competing liens were claimed were owned by EnDevCo
Eureka, L.L.C. (EnDevCo).79
Gasrock Capital’s mortgage from EnDevCo was recorded in the real estate
records on April 24, 2006.80 EnDevCo subsequently hired Pan American Drilling to drill a
well on the unit that included EnDevCo’s oil and gas leases.81 Pan American Drilling
commenced work at the well location on or about September 25, 2007.82 EnDevCo
ultimately defaulted on its payment obligations to GasRock Capital and to the drilling
contractors.83 Pan American Drilling filed its oil and gas lien statement on July 8, 2008.84
In the lien foreclosure litigation that followed, GasRock Capital asserted that
because its mortgage was recorded prior to Pan American Drilling’s commencement of
work on the property, GasRock Capital had first-in-time priority over the competing well
lien under 42 O.S. 2011, § 144.85 Pan American Drilling responded that 52 O.S. 2011,
§287.8 granted its contractor lien claim first priority for the operating expenses of the
unit.86 Section 287.8 provides in pertinent part:
Subject to such reasonable limitations as may be set out in the plan of
unitization, the unit shall have a first and prior lien upon the leasehold
estate and other oil and gas rights . . . in and to each separately-owned
tract, the interest of the owners thereof in and to the unit production and
all equipment in the possession of the unit, to secure the payment of the
amount of the unit expense charged to and assessed against such
77
78
79
80
81
2013 OK CIV APP 98, 313 P.3d 1028.
Id. at ¶ 2.
Id. at ¶ 1.
Id. at ¶ 3.
Id. at ¶ 4.
Id.
Id.
84 Id. at ¶ 5.
85 Id. at ¶ 6.
86 Id.
82
83
34
separately-owned tract. (Emphasis added by the court).87
The trial court ruled in favor of Pan American Drilling.88 GasRock Capital appealed.
In affirming the decision of the trial court, the Oklahoma Court of Appeals first
found that “[a]n oil and gas unit operator’s statutory lien has priority over a
mortgagee’s lien regardless of the first-in-time recording of the mortgage.”89 GasRock
Capital asserted that the foregoing proposition had no application to the present case
because Pan American Drilling was not the operator of the unit and was merely a
contractor.90 However, the court noted that the Plan of Unitization for the subject unit
expressly provided that the unit would have a first and prior lien on the leasehold
interests to secure payment of unit expense.91 The Plan of Unitization further stated:
The lien hereinabove provided for shall be for the use, benefit and
protection of the Unit Operator or other Lessees or Persons entitled to
receive or share in the monies, the payment of which is secured
thereby, and in the event of failure of the Unit to enforce such lien, the
Unit Operator or other Persons entitled to the benefit thereof,
shall be subrogated to the lien rights of the Unit, including the right
of foreclosure. (Emphasis added by the court)92
The court concluded that Pan American Drilling was clearly a person entitled to the
benefit of the unit’s lien priority.93 It went on to observe notice of the Plan of Unitization
had been filed in the real estate records decades prior to the recording of GasRock
Capital’s oil and gas mortgage.94
The court affirmed the lower court’s ruling finding that Pan American Drilling’s
lien had priority over the oil and gas mortgage of Gasrock Capital.
52 O.S. 2011, §287.8.
Id. at ¶ 7.
89 Id. at ¶ 9, citing TCINA, Inc. v. NOCO Investment Co., Inc., 2004 OK CIV APP 62, 95
P.3d 193 and Ladder Energy Co. v. Intrust Bank, N.A., 1996 OK CIV APP 126, 931 P.2d
83d.
90 2013 OK CIV APP 98, 313 P.3d 1028 at ¶ 10.
91 Id. at ¶ 11.
87
88
Id.
Id. at ¶ 13.
94 Id.
92
93
35
C.
Rescission of mineral deeds is granted based upon finding of
constructive fraud due to the failure of the buyer to disclose
certain information to the seller.
In Widner v. Enerlex, Inc.,95 the Widners received an unsolicited offer from
Enerlex to purchaser certain of their mineral interests. At the time Enerlex made the
offer, it was aware, but did not disclose to the Widners, that a well had been producing
from a unit that included some of the Widner mineral interests and that both a bonus
payment of $60 per acre and almost $35,000 in production proceeds were being held in
suspense for the owner of the interests Enerlex proposed to acquire.96 Enerlex offered
$3,800 plus a $250 signing bonus to one of the Widners and $3,000 plus a $250 signing
bonus to the other Widner plaintiff.97
The Widners accepted Enerlex’s offer. It was undisputed in the proceedings
below that the Widners would not have sold and conveyed their mineral interests to
Enerlex if they had known about the producing well and the large sum of accrued
production proceeds available to be claimed by the owner of the subject minerals.98
When the Widners later learned of those facts, they sued Enerlex alleging, among other
assertions, that Enerlex had a duty to inform them of the producing well and accrued
production proceeds, and that the failure to do so constituted constructive fraud. 99 The
Widners asked the court to rescind the mineral deeds and award consequential
damages, actual damages and punitive damages.100
The trial court ruled in favor of the Widners, cancelled the mineral deeds and
directed a rescission of the purchase and sale transaction.101 Enerlex appealed. The
Oklahoma Court of Appeals reversed on the grounds that Enerlex “made no factual
inducement, representation or misrepresentation that gave rise to a duty to disclose the
pooled mineral interests or production.”102 The Widners sought, and the Oklahoma
Supreme Court granted, discretionary review by that court.
In contrast to the ruling of the Court of Appeals, the Oklahoma Supreme Court
emphasized that the mineral deeds submitted by Enerlex to the Widners for signing
included an assignment to Enerlex of “all royalties, accruals and other benefits, if
any, from all Oil and Gas heretofore or hereafter run, whether they be held
95
2013 OK 91, 313 P.3d 930, at § 4.
Id.
Id. at ¶ 5.
98 Id.
99 Id. at ¶ 8.
100 Id.
101 Id. at ¶ 9.
102 Id. at ¶ 10.
96
97
36
therefore by any purchaser or other legal entity, or hereafter produced, sold and paid to
the Grantee.”103 (Emphasis added by the court). The court found that, by using the “if
any” language in the mineral deeds, “Enerlex, indirectly if not directly, created a false
impression that Enerlex did not know of any production or any accruals from all oil and
gas heretofore run.”104 Concluding that the issues presented in this case were controlled
by the court’s prior pronouncements in Croslin v. Enerlex, Inc.,105 the court affirmed the
trial court’s ruling in favor of the Widners and found that rescission was the appropriate
remedy for the defendant’s misrepresentation and constructive fraud.106
D.
Court reverses the district court’s award to the defendant of
attorney’s fees, costs and expert witness fees under the
Oklahoma Production Revenue Standards Act.
The case of Fleetwood v. Chevron U.S.A. Production Company,107 involved
Fleetwood’s challenge to the validity of a 1994 order authorizing the leasing of certain
mineral rights by a receiver. Fleetwood specifically argued that the receiver’s lease did
not convey any interest to Chevron because the 1994 order, under which the receiver
was appointed and the lease interest sold to Chevron, was void because publication
notice was insufficient and failed to meet minimum due process, and the court lacked
subject matter jurisdiction because a necessary element required by 52 O.S. 2011, §
521 et seq. was never pled or proven.
The trial court granted summary judgment in favor of Chevron. The trial court
granted Chevron’s request for an assessment of attorney’s fees, costs and expert
witness fees in the amount of $140,095.02 against Fleetwood under the Production
Revenue Standards Act (PRSA).108 Fleetwood appealed.
In reversing the award of attorney’s fees and costs against Fleetwood, the
Oklahoma Court of Appeals found that the PRSA’s scheme for the treatment of
proceeds from production was never triggered in this case because the PRSA does not
set forth standards for determining (a) ownership disputes, or (b) whether an order is
void. Therefore, the lawsuit was not one brought under the PRSA and no violation of
the PRSA occurred in this case. The trial court erred in awarding Chevron attorney’s
fees and related expenses.
Id.
Id.
105 Id.
106 Id.
at ¶ 6.
at ¶¶ 11 and 12.
at ¶ 11, citing Croslin v. Enerlex, Inc., 2013 OK 34, 308 P.3d 1041.
at ¶ 13.
107 85 O.B.J. 1994 (Okla. App. 2014 - #111,161) (Not for Publication).
108 52 O.S. 2011, § 570.14(C)(2).la
37
103
104
E.
Court affirms judgment granting seller of oil and gas properties
specific performance of the Purchase and Sale Agreements as
against the buyer.
Under the facts in Preston Exploration Company, L.P. v. G.S.F., L.L.C.,109
Chesapeake executed three purchase and sale agreements (PSAs) under which it
agreed to purchase from Preston Exploration over 500 oil and gas leases covering lands
in the State of Texas. When Chesapeake did not close the transaction, Preston sued for
specific performance. The litigation below had a long and complicated history. On the
latest remand from the Fifth Circuit Court of Appeals, the district court found: (1)
Preston had reasonably cured Chesapeake’s alleged title defects (or would do so within
six months of the closing); (2) Preston was ready, willing and able to perform on the
Closing date; and (3) Chesapeake breached the PSAs by failing to close.110 The district
court ordered specific performance of the PSAs in favor of Preston for “all leases for
which it has recording information.”111 Chesapeake appealed.
In affirming the district court’s ruling in favor of Preston, the Fifth Circuit Court of
Appeals found in part as follows:
1.
Preston satisfied all conditions precedent outline in the PSAs. Preston
advised Chesapeake that Chesapeake would be given title at the closing, and “Preston
was prepared to . . . [convey] marketable title to Chesapeake at Closing as ‘a
reasonable and prudent person’ in the industry would accept unrecorded title when
accompanied with Preston’s guarantees. . .”112
2.
Preston’s lack of title to certain of the oil and gas leases prior to the
closing did not violate any of the PSAs’ covenants and agreements. Those leases were
not to be included in the November 7 closing but were to be postponed until
subsequent mini-closings. The court noted that Preston now has marketable title to
the leases at issue.
3.
In sum, Preston is entitled to specific performance because it complied
with the PSAs, including tender of performance, and was ready, willing and able to
perform on November7, 2008, and at all relevant times.
2014 WL 1712469 (5th Cir. 2014) (Unpublished). For a more detailed description of
the underlying facts, see Preston Exploration Co. v. GSF, L.L.C., 669 F.3d 518, 519 – 22
(5th Cir. 2012).
110 Preston Exploration Co., LP v. GSP, LLC, 2012 WL 6048947 (S.D. Tex. Dec. 5, 2012).
111 Id. at *9.
112 2014 WL 1712469, at *1.
38
109
F.
Court finds that assignment did not provide for “proportionate
reduction” of a reserved production payment in the event of the
expiration of 2 of the 4 underlying oil and gas leases.
In McDaniel Partners, Ltd. v. Apache Deepwater, LLC,113 the dispute before the
court involved a production payment reserved to the assignor under the terms of a
1953 assignment that covered 4 oil and gas leases. A parenthetical clause in the
assignment described the manner of calculating the payment. The issue presented was
whether the expiration of two of the four oil and gas leases should modify the manner
of computing the production payment.
The precise language of the reserved production payment was as follows:
“there is expressly excepted from this conveyance as a ‘production
payment interest,’ the title to and ownership of . . . (1/16th of 35/64ths
of 7/8ths, being one sixteenth of the entire interest in the
production from said lands to which Assignor claims to be
entitled under the terms of said respective oil and gas leases) of
the total oil, gas, casinghead gas and other minerals in and under and
which may be produced from the above described land, i.e., from each
and both of said Surveys 36 and 37, Block 40, Township 5 South, T&P Ry.
Co. Lands, until the net proceeds of said reserved interest . . .” 114
(Emphasis added by the court)
The 35/64 fraction represented the fact that the portion of the minerals
attributable to each of the 4 leases at the time of the conveyance and reservation was
as follows:
Cowden 36 lease: 16/64 of the total;
Cowden 37 lease: 16/64 of the total;
Peterman lease: 1/64 of the total; and
Broudy lease: 2/64 of the total.
In 1994, the Cowden 36 lease and Cowden 37 lease expired for lack of
production. However, production continued as to the other 2 leases, with Apache
commencing additional wells on those other leases.
113
114
2014 WL 1266812 (Tex. App. – El Paso 2014).
Id. at *1.
39
Apache sent a Division Order to McDaniel showing that McDaniel was entitled to
1/16 of 3/64 of 7/8 of the production from the remaining 2 leases. McDaniel, in
contrast, asserted that his production payment should continue to be computed as 1/16
of 35/64 of 7/8 of the production from the 2 remaining leases.
McDaniel sued Apache for breach of contract, conversion and for an accounting.
At trial, neither party asserted that the subject assignment was ambiguous. The trial
court found that the expiration of 2 of the original 4 leases should lead to a
proportionate reduction of the production payment. McDaniel appealed.
In reversing the judgment of the trial court and ruling in favor of McDaniel, the
Texas Court of Appeals found in part as follows:
1.
The court found that the single issue for review was whether the trial
court correctly interpreted the production payment reservation under the 1953
Assignment. The appellate court concluded that the “exacting, ‘longhand’ description of
the interest”115 reserved unambiguously provided a precise fractional equation by which
the production payment was to be computed: 1/16 of 35/64 of 7/8 of production. It
was likewise unambiguous that the entire fractional equation was to be calculated
against the total production from all of the lands.
2.
The appellate court noted that the foregoing finds left the question of
whether the terms of the assignment permitted a reduction of the production payment
in the event any of the assigned leases expired. The parties and the court focused
upon the following wording from the excerpt from the assignment quoted above:
“(1/16th of 35/64ths of 7/8ths, being one sixteenth of the entire interest in the
production from said lands to which Assignor claims to be entitled under the
terms of said respective oil and gas leases).” Apache argued that this language
explained how to compute the production payment at any particular point in time---i.e.,
based on the amount of working interest acreage that is then attributable to the
underlying leases.
3.
The court rejected Apache’s contention and found that there was no
language in the assignment providing for any adjustments, in the event of oil and gas
lease termination, to either (a) the production payment’s $3,550,000 dollar sum, or (b)
the production payment’s volumetric total of 1,420,000 barrels of oil. The court noted
that if the parties had intended to periodically adjust the production payment, the
assignment surely would have included language providing for the adjustment of those
numbers.
115
Id. at *4.
40
4.
Apache argued that McDaniel’s interpretation of the assignment ignored
the fundamental nature of production payments. In support of that assertion, it offered
the expert witness testimony of a legal expert and of its Land Department supervisor.
The court found that such testimony was outside the four corners of the contract and
was barred by the parol evidence rule.
5.
Finally, the court observed that while certain legal scholars had opined
that a production payment interest expires with the termination of the underlying oil
and gas leases, it could find no prior Texas case deciding whether a production
payment (absent express contractual language) can be proportionately reduced
following the expiration of some, but not all, of the underlying leases.
G.
Colorado Supreme Court considers the vitality and applicability of
the Rule Against Perpetuities in Colorado.
In Atlantic Richfield Company v. Whiting Oil and Gas Corporation,116 the dispute
involved a 1968 agreement under which ARCO committed $2 million to fund Whiting’s
research into methods of recovering oil shale from several properties. In return,
Whiting conveyed half of its undivided 50% interest in the properties (the “Boies
Block”) to ARCO, thereby allowing ARCO to share in any future profits from oil shale
production. The 1968 agreement further provided that if oil shale was not in
commercial production by 1983, Whiting would convey an additional interest in the
Boies Block to ARCO (the “Additional Conveyance”).
By 1982, Whiting’s research had not led to commercial production of oil shale.
So, in 1983, following a year of negotiations, ARCO and Whiting agreed to amend the
1968 agreement to postpone the Additional Conveyance. As an incentive for Whiting to
complete its research, ARCO granted Whiting a non-exclusive option (the “1983
option”) to buy back the interest in the Boies Block that ARCO had previously acquired
from Whiting under the 1968 agreement. Under this 1983 option, Whiting’s right to
exercise the option would expire 25 years later on February 1, 2008, at 11:59 p.m. The
amendment further provided that “ARCO shall retain the sole and exclusive right to
cancel this Option at any time during its term.”117 The parties set an initial price at
which the 1983 option could be exercised, and provided for annual market-based
adjustments tethered to the annual percentage change in ARCO’s published benchmark
price for West Texas sour crude oil.
Whiting’s research never led to commercial production of oil shale from the
116
117
320 P.3d 1179, 2014 CO 16.
Id. at 1182, ¶ 9.
41
properties. In the early 2000s, Whiting proposed to acquire ARCO’s interest in the
Boies Block after discovering that the property contained valuable reserves of natural
gas. In 2003, ARCO rejected a $10,000 offer from Whiting. ARCO took no action to
revoke the 1983 option. In 2006, Whiting attempted to exercise the 1983 option at the
then-applicable option exercise price, which was significantly below the property’s 2006
market value.
When ARCO refused to convey the interest in the Boies Block to Whiting, Whiting
sued for specific performance of the 1983 option. ARCO moved for entry of judgment
on the pleadings and argued that, as a matter of law, the 1983 option was void ab initio
because the 25-year option period violated the common law Rule Against Perpetuities.
In response, Whiting asserted that the common law Rule Against Perpetuities did not
apply to cancelable or revocable interests, and that the right of ARCO to cancel the
1983 option prevented that option from imposing any practical restraint on ARCO’s
property interest. Alternatively, Whiting contended that even if the 1983 option
violated the common law rule, the court was required to reform the option by inserting
a savings clause pursuant to section 15-11-1106(2) of Colorado’s Statutory Rule Against
Perpetuities Act118 which supersedes the common law for nonvested property interests
created after May 31, 1991. The common law still applies in Colorado to nonvested
property interests created prior to that date.
The trial court denied ARCO’s motion. The court agreed with ARCO that the 25year option violated the common law Rule Against Perpetuities. However, it found that
the option could and should be reformed under section 15-11-1106(2) by inserting a
savings clause. The trial court granted specific performance to Whiting. ARCO
appealed. In a 2-1 decision, the Colorado Court of Appeals affirmed the trial court’s
judgment.119 ARCO petitioned the Colorado Supreme Court to review the Court of
Appeals’ decision, and that petition was granted.
In affirming the Court of Appeals’ ultimate decision on different grounds, the
Colorado Supreme Court found that, because ARCO retained the right to cancel the
option at any time during its term, the 1983 option posed no practical restraint on
ARCO’s ability to improve or sell the property. Consequently, the 1983 option did not
violate the common law Rule Against Perpetuities. The statutory reformation provisions
therefore had no application to this case since those provisions relate only to
documents that violate the rule.
The court also noted that the crude oil market-based price term for the exercise
§§ 15-11-1101 to -1216, C.R.S. (2013)
Whiting Oil & Gas Corp. v. Atlantic Richfield Co., 2010 WL 3432211 (Colo. App. Sept.
2, 2010).
42
118
119
of the option was negotiated by two highly sophisticated parties. The option was not
invalid simply because ARCO, at the time of the exercise of the option many years later,
stood to lose under the terms of its bargain.120
H.
Court finds that claims for alleged violations of a covenant not to
compete were released under the applicable contract when the
entity that possessed those claims ceased doing business.
The issues before the court in Macro Oil Company, Inc. v. Deep South
Petroleum, Inc.,121 arose from the plaintiffs’ (Macro) and defendants’ (Deep South)
formation of a new limited liability company (UFL) under the laws of Louisiana. Macro
and Deep South each transferred their fuel distribution assets to UFL and entered into
an operating agreement with UFL which included a covenant on the part of Macro and
Deep South not to compete with UFL. Macro and Deep South each owned fifty percent
of the membership interest in UFL.
Almost seven years after its formation, UFL sold its assets to Talen. On the date
of that sale,
Deep South and Macro signed a release agreement stating that both
“agree that neither has any claims against the other arising out of or in
any way connected to their membership in UFL” and “to the extent that
Macro or Deep South has any such claims, the same are hereby waived,
released, remitted and otherwise extinguished.”122
Deep South subsequently attempted to assert on behalf of UFL that Macro had violated
the covenant not to compete at some point after Hurricanes Katrina and Rita. Macro
brought the present lawsuit seeking a judicial declaration as to the rights and
obligations of the parties under the operating agreement and the release agreement
and accompanying injunctive relief. In particular, Macro asked the court to rule that
“any and all claims against Macro were released for its alleged violation of any covenant
not to compete with UFL.”123 The trial court granted Macro’s motion for summary
judgment. Deep South appealed. In affirming the judgment in favor of Macro, the
appellate court held in part as follows:
1.
The court found that the wording of UFL’s operating agreement
compromised any claims UFL might have had “when it clearly states that [the covenant
320 P.3d at 1190, 2014 CO 16 at ¶ 48.
112 So.3d 1004 (La.App.3 Cir. 2013).
122 Id. at 1005.
123 Id. at 1007.
120
121
43
not to compete] ceases to apply upon ‘cessation of business.’”124
2.
Deep South argued that the provision of the operating agreement that
terminated the covenant not to compete required the complete cessation of business,
and that UFL “did not completely cease conducting business, as it still pays bills, collects
receivables, etc.”125 The court rejected this argument and found that UFL had in fact
ceased conducting its ordinary and regular business operations. The court noted that
UFL was in fact obligated to cease conducting business because of the covenant not to
compete that it had made in favor of Talen, the purchaser of its business.
3.
Finally, Deep South cited a provision of the Louisiana Statutes that
provides that “[a] compromise does not affect rights subsequently acquired by a party,
unless those rights are expressly included in the agreement.”126 However, the court
found that, upon the sale of UFL and the cessation of its business operations, any
claims of UFL were reserved to the owners, Macro and Deep South. The release
agreement of Macro and Deep South waived, released and extinguished any claims
Deep South might have otherwise had against Macro for breaches of the covenant not
to compete.
V.
Marketing and Refining of Oil and Gas Production
A.
Oklahoma’s Production Revenue Standards Act is found to be
applicable to wellhead sales of production, but not to
downstream sales in interstate commerce.
In Gaskins v. Texon, LP, Gaskins sought a judicial declaration that Texon had a
statutory duty under the Oklahoma Production Revenue Standards Act (PRSA)127 “to
hold all revenue or proceeds from the purchase of oil and gas in trust for the benefit of
the legal owners.”128 Under the facts alleged in this case, Gaskins sold 642 barrels of oil
to SemCrude in June and July of 2008. That oil was delivered into SemCrude’s pipeline
system and was commingled with oil from other wells in order to transport it to a major
oil trading center located in Cushing, Oklahoma.129 The oil was “eventually sold [by
SemCrude] to several downstream purchasers, including Texon, who purchased 1,650
barrels of oil in June and 1,085 barrels in July, 2008.”130
Id.
Id. at 1008.
126 Id., citing La.Civ.Code art. 3078.
127 52 O.S. 2011, § 570.1 et seq.
124
125
128
129
130
2014 OK CIV APP 22, ¶ 2, 321 P.3d 98.
Id. at ¶ 3.
Id.
44
SemCrude subsequently filed for bankruptcy protection on July 22, 2008, and
failed to pay Gaskins the approximate $62,000.00 sum due for his oil. In the present
action, Gaskins asserted that, by virtue of the provisions of the PRSA, Texon held
proceeds from SemCrude’s sale of Gaskins’ oil to Texon, which included proceeds
attributable to Gaskins’ portion of the oil stream.131
The district court ruled that the PRSA did not apply to either Gaskins' sale of oil to
SemCrude or to SemCrude’s sale of oil to Texon. The court dismissed the case on the
grounds that Gaskins’ petition failed to state a claim for which relief could be granted.132
Gaskins appealed.
The Oklahoma Court of Appeals noted at the outset of its analysis of the case
that the specific provision of the PRSA that was the focus of arguments was Section
570.10(A) which states as follows:
All proceeds from the sale of production shall be regarded as separate and
distinct from all other funds of any person receiving or holding the same
until such time as such proceeds are paid to the owners legally entitled
thereto. Any person holding revenue or proceeds from the sale of
production shall hold such revenue or proceeds for the benefit of the
owners legally entitled thereto. Nothing in this subsection shall create an
express trust.133
Gaskins asserted that the above provision of the PRSA required Texon to hold revenue
or proceeds from the purchase and sale of oil and gas in trust for the benefit of the
persons entitled to receive those proceeds.134 Texon, in contrast, contended that the
PRSA applies only to sales of production at the wellhead, and not to subsequent resales
of the production downstream from the well.135
In rejecting Gaskins’ assertions and in affirming the decision of the district court,
the Oklahoma Court of Appeals found that the wording in Section 570.10(A) is clear and
unambiguous.136 In particular, the court found that:
[N]othing in the language of § 570.10(A) creates or suggests a duty on a
downstream purchaser or applies to downstream purchasers of oil and gas
after it reaches the stream of interstate commerce. Moreover, there is
Id.
Id.
133 Id.
134 Id.
135 Id.
136 Id.
131
132
at
at
at
at
at
¶
¶
¶
¶
¶
5.
5, quoting 52 O.S. 2011, § 570.10(A).
8.
9.
10.
45
nothing in that language requiring the imposition of an implied trust.137
In finding that the requirements of Section 570.10 did not lead to the imposition of an
implied trust, the court cited as persuasive the decision of a Delaware Bankruptcy Court
in In re SemCrude, L.P. (Samson Res. Co. v. SemCrude, L.P. et al.).138 In that earlier
decision, the court concluded that Section 570.10 “does not create a resulting trust
because the intent to create one is simply not provided by the plain words of the
statute.”139
The Court of Appeals affirmed the district court’s decision in favor of Gaskins.
Vi.
Surface Use, Surface Damages, Oklahoma Surface Damages
Act, Condemnation and Environmental Cases
A.
New Lawsuit Over Seismicity Issues.
A new lawsuit was filed on August 4, 2014, in the District Court of Lincoln
County, Oklahoma, entitled “Sandra Ladra, Plaintiff vs. New Dominion, LLC, Spess Oil
Company, John Does 1-25,” Case No. CJ-2014-115. In the Petition filed in that lawsuit,
the plaintiff alleges in part that “[i]n recent years, hundreds of earthquakes have
occurred in central Oklahoma,” and that “[s]o far this year, Oklahoma has had more
than twice the number of earthquakes as California, making it the most seismically
active state in the continental United States.” The plaintiff goes on to contend that the
earthquakes are tied to the disposal of saltwater related to fracing operations.
The plaintiff asserts that she “suffered personal injuries as a direct result of manmade earthquakes occurring in and around Prague in November of 2011.” The
defendants are alleged to operate wastewater injection wells around Lincoln County.
Claims for “absolute liability” and “negligence” are asserted in the Petition. The plaintiff
seeks to recover actual and punitive damages, as well as pre-judgment and postjudgment interest.
On October 16, 2014, the district court granted the defendants’ Motion to
Dismiss the case, finding that an adjudication of this lawsuit would require the Court to
decide issues that are within the exclusive jurisdiction of the Oklahoma Corporation
Commission. The findings of the district court included the following, among others:
The Court further finds that the Oklahoma Corporation Commission
137
138
139
Id. at ¶ 13.
407 B.R. 140 (D. Del. 2009).
Id. at 153-154.
46
authorized the Defendants to conduct the disposal operations that the
Plaintiff claims caused her damages.
The Court further finds that there are no allegations that the
Defendants violated the terms of the licenses as granted to them by the
Oklahoma Corporation Commission.
The Court further finds that the Oklahoma Corporation Commission
is vested with exclusive jurisdiction, power and authority with reference to
the exploration, drilling, development, production and operation of wells
used in connection with the recovery, injection or disposal or mineral
brines. 17 O.S. § 52(a)(1)(d).
As a result, it dismissed the case due to its finding that the court does not have
jurisdiction to hear the case.
B.
Court finds that a pipeline transporting NGLs does not have the
right of condemnation afforded under Texas Statutes to pipelines
transporting crude petroleum, nor was the subject pipeline a
common carrier.
In Crosstex NGL Pipeline, L.P. v. Reins Road Farms-1, Ltd.,140 Crosstex appealed
the District Court’s denial of its request for injunctive relief to prevent the landowner
from interfering with Crosstex’s attempt to survey the property to complete its planned
natural gas liquids pipeline. Among other arguments, the landowner asserted that
Crosstex does not possess the power of eminent domain for a pipeline that would
neither (a) transport crude petroleum, nor (b) be used by the public.
In affirming the trial court’s ruling in favor of the landowner, the Court of
Appeals found in part as follows:
1.
For purposes of Chapter 111 of the Natural Resources Code, the trial
court’s conclusion that a pipeline used to transport natural gas liquids is not the same
as a pipeline used to transport crude petroleum was a reasonable conclusion based on
the statute and the evidence presented at the hearing. The trial court did not clearly
abuse its discretion in rejecting Crosstex’s argument that the term “crude petroleum”
includes a by-product like natural gas liquids.
2.
Crosstex alternatively claimed that, even if its line was not a crude
petroleum pipeline under the condemnation statutes, Crosstex had the right of
140
404 S.W.3d 754 (Tex. App. – Beaumont 2013).
47
condemnation because it is a “common carrier” owning a pipeline that is available for
public use and is subject to the authority of the Texas Railroad Commission. After
reviewing the evidence offered by Crosstex at the hearing in support of its contention
that liquids owned by non-affiliates of Crosstex would make use of the line, the Court of
Appeals concluded that the evidence supported a conclusion that Crosstex was building
a pipeline for the exclusive purpose of transporting its own natural gas liquids for
further processing by Crosstex affiliates. Based on the record presented, the court held
that the trial court’s conclusion that Crosstex would probably be using the pipeline’s
entire capacity to transport its own natural gas liquids to Crosstex affiliates for further
processing was reasonable.
C.
The TransCanada Keystone Pipeline project is found to qualify for
condemnation rights under the Texas Statutes.
In another case from late 2013, Crawford Family Partnership v. TransCanada
Keystone Pipeline, L.P.,141 the court was presented with a condemnation action
involving the well-publicized Keystone Pipeline project, which the court summarized as
follows:
“The Keystone Pipeline system owned by TransCanada as projected
contemplates the installation and operation of a network of over 2,100
miles of pipeline for the transmission of crude petroleum which originates
in Canada, traversing markets within the midwest United States to
Cushing, Oklahoma. The crude petroleum which is gathered at Cushing,
Oklahoma, enters a portion of the Keystone Pipeline System known as the
Gulf Coast Project, which crosses over into Texas to its ultimate
destination in the Port Arthur, Texas, area. It is this Gulf Coast Project
portion of the pipeline that has been planned to traverse the Crawford
property in Lamar County.” 409 S.W.3d at 911.
In rejecting the landowner’s challenge to TransCanada’s assertion
condemnation rights under the Texas Statutes, the trial court found as follows:
“TransCanada has the legal capacity to bring this proceeding and to
recover the easements sought; TransCanada is a common carrier;
[Crawford] is the owner of the Property; that there is a public necessity
for the Easements along, across, and over the Property sought in this
proceeding by TransCanada and that TransCanada has strictly complied
with the statutes authorizing this condemnation proceeding.” 409 S.W.3d
at 912-13.
141
409 S.W.3d 908 (Tex. App. – Texarkana 2013).
48
of
On appeal, Crawford contended that (1) the trial court erred in denying its motion to
dismiss for want of jurisdiction, (2) the trial court erred in granting TransCanada's
combined traditional and no-evidence motion for summary judgment, and (3) the trial
court erred by denying, in part, Crawford's fourth motion for a continuance.
In affirming the District Court’s ruling in favor of TransCanada, the Court of
Appeals found in part as follows:
1.
Crawford's conclusion that TransCanada cannot meet the definition of a
common carrier is based on the premise that the introductory phrase in the statute (“A
person is a common carrier subject to the provisions of this chapter”) means that any
such common carrier must comply with each and every provision set forth in Chapter
111 of the Natural Resources Code. The court finds that interpretation to be an
incorrect reading of the statute. First, the language preceding the definition of
“common carrier” does not specifically state that such common carrier is subject to all
of the provisions of the chapter. It merely states, in a descriptive manner, that a
common carrier under this section is one that is subject to the provisions of the
chapter. Moreover, the language does not confer common carrier status to such
carriers only if they are subject to each of the provisions of the chapter.
2.
The court additionally rejected the landowner’s assertion that
TransCanada’s status as an “interstate” carrier precluded TransCanada from qualifying
for common carrier status under the Texas Statutes.
3.
The court found that the landowner submitted no evidence to the trial
court to refute or otherwise challenge the evidence of TransCanada concerning its
status as a common carrier “to or for the public for hire” under TEX. NAT. RES. CODE
ANN. § 111.002(1). TransCanada produced undisputed evidence that it will ship crude
petroleum for one or more customers who will retain ownership of the oil, thereby
complying with the reasonable probability test under Tex. Rice Land Partners, Ltd. v.
Denbury Green Pipeline–Tex., LLC.142
D.
Operator is found to have the right to use any part of tracts
within a pooled unit for an access road associated with its
operations within the unit.
The case of Key Operating & Equipment, Inc. v. Hegar,143 the issue before the
court was whether, when parts of two mineral leases have been pooled but production
is from only one lease, the mineral lessee has the right to use a road across the surface
142
143
363 S.W.3d 192, 198 (Tex.2012).
2014 WL 2789933, 57 Tex. Sup. Ct. (Tex. 2014).
49
of the lease without production in order to access the producing lease.
Key had operated Well 1 on Tract 1 since 1987. In 1994, Key acquired oil and
gas leases on a contiguous tract, Tract 2, and reworked an existing well (Well 2) on
Tract 2. That same year, Key built an access road on Tract 2 to access both wells.
Well 2 stopped producing in 2000, and the oil and gas leases on Tract 2 expired.
However, also in 2000, the owners of Key purchased a mineral interest in Tract 2 and
promptly granted an oil and gas lease to Key which gave Key the right to pool the
minerals with other property in the immediate vicinity. Key pooled its leased minerals
in Tract 2 with its leased minerals in Tract 1.
In 2002, Hegar bought 85 acres in Tract 2. That acreage included the access
road Key used to access Well 1. In 2003 or 2004, Hegar built a house on its acreage in
Tract 2, used the access road to access the land and for several years too no action to
restrict Key’s use of the road. However, when Key drilled Well 1A on Tract 1, and the
traffic on the access road increased, Hegar filed suit claiming that Key’s continued use
of the access road was a trespass on Tract 2. At trial, Hegar’s petroleum engineer
testified that (a) Well 1A was the only well on the pooled acreage with significant
current production, (b) the size of the reservoir from which Well 1A produced was
three-and-a-half surface acres, (c) the well’s drainage area did not reach the Hegar
property, and (d) the well was not draining oil from Hegar’s property.
The trial court enjoined Key from using the part of the access road that was on
Hegar’s property (Tract 2) for any purpose related to producing minerals from Tract 1.
The court found that Key’s prior use of the road on Tract 2 was trespass, and that Key’s
use of the surface of Tract 2 was not reasonably necessary to extract minerals from
beneath Tract 2. Key appealed.
The Texas Court of Appeals initially reversed. But then it granted Hegar’s motion
for rehearing and affirmed.144 Key petitioned the Texas Supreme Court for review,
arguing that it had the right to sue the surface estate of Hegar’s property in producing
minerals from “any part” of the pooled unit. The court granted the petition for review.
In reversing the trial court’s ruling in favor of the landowner and in rendering
judgment in favor of Key, the Texas Supreme Court found in part as follows:
1.
The owner of the dominant mineral estate in Texas has the right to go
upon the surface of the land to produce and remove the minerals, and also has the
incidental rights necessary for that production and removal. See Merriman v. XTO
144
403 S.W.3d 318.
50
Energy, Inc.145 Additionally, when leases are pooled, production and operations
anywhere on the pooled unit are treated as if they have taken place on each tract
within the unit.
2.
Consequently, once Key pooled the leases, production from the pooled
part of Tract 1 also constituted production from the pooled part of Tract 2. The court
noted that Hegar did not contend that Key had no right to use the access road to
produce minerals from Tract 2. Because of the pooling, Key had the right to use the
road to access the pooled part of Tract 2.
3.
Finally, the court noted that the accommodation doctrine was not raised
with the trial court, so the appellate courts did not need to determine whether that
doctrine was correctly applied. Under the accommodation doctrine of Texas, a surface
owner may obtain relief on a claim that the mineral lessee failed to accommodate an
existing surface use by proving that the existing use is precluded or substantially
impaired by the mineral lessee, and that no reasonable alternative method is available
to continue the existing use.146
VII. Conservation Commission-Related Cases
A.
Court of Appeals addresses multiple foundational attacks on the
propriety of compulsory pooling proceedings before the
Corporation Commission.
The case of Chesapeake Operating, Inc. v. Staats,147 involved two mineral
owners who had been overlooked, and were not included as respondents, in the original
force-pooling proceedings before the Corporation Commission. Some 10 wells were
drilled from 2005 through August of 2009 when the Operator filed a compulsory
pooling application naming the two mineral owners as respondents.
On October 21, 2009, some two months after the filing of the force-pooling
application, the mineral owners filed a lawsuit in the District Court of Stephens County
asking the court to grant judgment for their share of the production revenue from the
prior years of operation of the wells under the Oklahoma Production Revenue Standards
Act (PRSA).148 The owners also sought an accounting.
On November 18, 2009, the Corporation Commission issued its force-pooling
407 S.W.3d 244, 248-49 (Tex. 2013).
Merriman v. XTO Energy, Inc., 407 S.W.3d 244, 249 (Tex. 2013).
147 85 O.B.J. 1594 (Okla. App. 2014 - #111,474) (Not for Publication).
148 52 O.S. § 570.1 et seq.
51
145
146
order (Order No. 571611), pooling the mineral interest of the two owners.
On September 9, 2011, the district court denied the Operator’s motion for
summary judgment in the Stephens County lawsuit.
On September 21, 2011, the Operator filed a “clean-up” pooling against the two
owners and asked the Commission to find that the working interest of those owners
was statutorily transferred to the Operator and to declare the terms of the transfer.
On November 9, 2011, the district court stayed the Stephens County action
pending the outcome of the Commission proceedings.
The mineral owners filed a motion to dismiss in the Commission proceedings,
arguing that their dispute with the Operator was a private royalty dispute and that
jurisdiction over that dispute resided with the district court. The Administrative Law
Judge (ALJ) for the Commission agreed with the mineral owners and recommended
dismissal of the case. However, the Appellate Referee reversed the ALJ’s decision. On
January 17, 2013, the Commission issued its order finding that the two mineral owners
were force-pooled and that the owners were deemed to have accepted a bonus of $350
per acre and a 1/8th royalty in return for the compulsory transfer of their working
interest rights to the Operator under the prior Order No. 571611.
The owners appealed. They raised six grounds of alleged error in the
proceedings below. In rejecting the owners’ arguments and affirming the order of the
Corporation Commission, the Oklahoma Court of Appeals held in part as follows:
1.
The court rejected the owners’ contention that, having been overlooked as
respondents in the initial force-pooling proceedings, the Operator could only seek to
pool their interests by asking for an “amendment” of the first compulsory pooling order,
as opposed to seeking a “new” pooling order. The court found that no prior case law
directly addresses that issue, and it concluded that the Commission was within its
powers when it considered a “new” pooling application in this matter.
2.
The court next addressed the owners’ contention that they were not given
proper notice of the 2009 pooling application. The court noted from the record (a) that
notice of those proceedings was sent to the owners by certified mail, (b) that the Postal
Service was unable to hand the letter to either owner for signature, (c) that the postal
employee had noted that he or she had twice left notice to the owners at their address
to pick-up the envelope at the post office, and (d) that the owners did not do so and
the Postal Service eventually returned the letter unclaimed.
3.
Of particular interest, the Court of Appeals found that the “statutory and
52
regulatory requirements for the service of notice of a pooling application and hearing
are not entirely clear.” The general statute relating to the service of Corporation
Commission orders provides for service in the same manner provided for the service of
summons in civil lawsuits in the Oklahoma district courts.149 The court then noted that
12 O.S. 2011, § 2004(b), relating to civil lawsuits, provides that service by mail of the
summons and petition is to be accomplished by “certified mail, return receipt requested,
and delivery restricted to the addressee.” However, 52 O.S. 2011, §87.1, which deals
specifically with pooling applications, provides for “notice by mail, return receipt
requested.” The court concluded that “it therefore appears that the requirement of
delivery restricted to the addressee is not required for service of a pooling application
and notice.”
4.
At the Commission hearing, the owners testified that they neither
witnessed that they neither witnessed a delivery attempt nor saw any notice left by the
Postal Service at their address. The Operator testified that the owners had received
other certified mailing at the same address. The court noted that the matter hinged on
the credibility of the owners versus the records of the Postal Service. The court
concluded that the Postal Service records provided sufficient evidence to sustain a
finding that the owners knew of, but refused to collect, the certified mailing.
5.
The court rejected the owners’ assertion that the Commission did not
have jurisdiction to determine if they had made the election regarding participation
pursuant to 52 O.S. 2011, § 87.1.
6.
With regard to the owners’ assertion that the case presented a “private
rights” dispute beyond the jurisdiction of the Commission, the Court of Appeals stated
that it found no evidence of any contractual arrangement between the owners and the
operator. The court further found that, absent a dispute based on such a “side
contract,” a forced pooling inevitably involves correlative or public rights because the
royalty rate and question of an election to participate affect all pooled interests.
B.
Commission upholds the Commission’s denial of respondent’s
request that the applicant-operator be required to produce
production data for the landowner for its use in preparing for the
force-pooling hearing.
In The F. M. Erikson Revocable Trust v. Chesapeake Operating, Inc.,150 Erikson
was the only respondent to an application for compulsory pooling filed by Chesapeake.
In preparation for the hearing on the pooling application, Erikson filed a motion
requesting the Commission to compel Chesapeake to provide it with “well completion
149
150
12 O.S. 2011, § 107.
85 O.B.J. 1593 (Oka. App. 2014 - #111,429) (Not for Publication).
53
and production data for all Chesapeake wells located in the area.” Chesapeake
opposed that request and argued that the “fair market value” determination to be made
in connection with a force-pooling application should be determined based on
consummated transactions in the area between a willing buyer and a willing seller.
Chesapeake also asserted that the Commission had a long history of denying requests
for production data in pooling cases. The Commission ultimately denied Erikson’s
request.
After reviewing in detail the additional points and counter-points raised by
Chesapeake and Erikson, the Court of Appeals quoted in part a prior decision of the
Oklahoma Supreme Court holding that “[t]he measure of compensation for forcibly
pooled mineral interests is their ‘fair market value’ the level at which this interest can be
sold, on open-market negotiations, by an owner willing, but not obliged, to sell to a
buyer willing, but not obliged, to buy. . .”151 The court found that Chesapeake
presented ample evidence at the hearing, without producing production data, to
support the Commission’s fair market value determination. The court affirmed the
pooling order of the Commission.
VIII. Litigation Over International Energy and Resources
Operations
A.
Court finds that, under the facts presented, statements of the
defendant corporations in response to an inquiry of the DOJ in
connection with possible violations of the FCPA were not
absolutely privileged, but were instead only conditionally
privileged.
In Writt v. Shell Oil Co.,152 the issue before the court was whether the
defendants had “an ‘absolute privilege,’ or ‘immunity,’ to make [alleged] defamatory
statements about [Writt] to the United States Department of Justice (‘DOJ’).”153 In his
employment with Shell, Writt
was charged with the responsibility of approving payments to contractors
on certain Shell projects in foreign countries, including Nigeria. During the
course of his work, Writt learned that certain Shell contractors were under
investigation “by various governmental agencies” for making and receiving
illegal payments and one of Shell’s vendors had pleaded guilty to violating
Miller v. Corporation Commission, 1981 OK 55, 635 P.2d 1006.
409 S.W.3d 59 (Tex. App. – Houston 2013).
153 Id. at 61.
54
151
152
the Foreign Corrupt Practices Act (“FCPA”).154
Writt alleged that the defendants voluntarily submitted a report to the DOJ, in response
to an informal inquiry, that
falsely stated that he had been involved in illegal conduct in a Shell
Nigerian project by recommending that Shell reimburse contractor
payments he knew to be bribes and by failing to report illegal contractor
conduct of which he was aware.155
The trial court granted the defendants’ motion for summary judgment and
determined that the defendants had an absolute privilege and immunity with regard to
the alleged defamatory statements at issue in this lawsuit. Writt appealed.
In a lengthy split decision of the three-judge panel, the majority of the Texas
Court of Appeals panel reversed the trial court’s decision and ruled that the statements
of the defendants were not absolutely privileged, but were instead only conditionally
privileged.156 Some of the key findings of the majority in reaching their decision are as
follows:
1.
In the context of circumstances like those presented in this case, an
absolute privilege “applies only to communications made in judicial proceedings and
those communications made preliminary to or in serious contemplation of a judicial
proceeding.”157 Not all communications to public officials are absolutely privileged.
2.
The court found that, although Shell prepared the report “in its effort to
cooperate with the DOJ, Shell actually prepared the report during the course of its own
voluntary ‘internal investigation’.”158
3.
While the defendants’ internal investigation was conducted “in response to
a DOJ inquiry after attending a meeting requested by the DOJ,”159 there was no
showing that a criminal case had been filed against Writt or the defendants “at either
154
155
156
Id. at 62.
Id. at 63.
The court noted that “[t]he distinction between the absolute privilege and the
conditional, or qualified, privilege is that ‘an absolute privilege confers immunity
regardless of motive whereas a conditional privilege may be lost if the actions of the
defendant are motivated by malice.’ ” Id. at 66.
157 Id. at 73.
158 Id. at 72.
159
Id.
55
the time the DOJ contacted Shell or when Shell submitted its report to the DOJ.”160 The
court found that the fact that the DOJ later filed a proceeding against the defendants
did not establish that the DOJ was proposing that such a proceeding be filed when it
contacted Shell or received Shell’s report.
4.
By way of analogy, the court noted that the statements made in the
report with regard to Writt “were more in the nature of information provided by a
private party to a prosecutorial agency implicating another in wrongful conduct.”161
5.
The court concluded that the defendants’ communication with the DOJ fell
within the protection of the conditional privilege that applies to communications to one
who may act in the public interest.
6.
At the outset of the majority opinion, the court expressed its belief that
absolute privilege and immunity in circumstances of the type presented here would
have the result of “actually discouraging parties from being truthful with lawenforcement agencies and instead encourage them to deflect blame to others without
fear of consequence.”162 The dissenting judge expressed a thoughtful opposing concern
in support of upholding the absolute privilege:
When a citizen, corporate or otherwise, is approached by a lawenforcement agency for cooperation in an ongoing investigation of a
contemplated criminal prosecution, the administration of justice requires
absolute privilege, which encourages the citizen’s full and unreserved
cooperation in the agency’s information-gathering efforts, unhampered by
fear of retaliatory lawsuits. . . [A] conditional privilege frustrates the kind
of frankness, cooperation, and self-reporting that is vital to the DOJ’s
prevention and prosecution of corporate misconduct in internal business
dealings under the FCPA.163
On August 22, 2014, the Texas Supreme Court agreed to review the above
decision. Oral argument is set to occur in November.
Id.
Id. at 74.
162 Id. at 61.
163 Id. at 77.
160
161
56
B.
Lawsuit over condensate allegedly stolen from Pemex in Mexico
and sold in the United States is dismissed based upon the
plaintiff’s lack of standing.
In Pemex Exploracion Y Produccion v. Murphy Energy Corp.,164 the plaintiff (as
assignee of certain causes of action) asserted claims against the defendants “arising
from sales in the United States of natural gas condensate allegedly stolen from [Pemex]
in Mexico.”165 The plaintiff’s claims included indirect claims, as assignees, “for fraud,
breach of warranty, and breach of contract.”166 The present action was the third lawsuit
filed by Pemex in the same court asserting that condensate stolen in Mexico had been
sold in the United States.167 Before the court were the defendants’ motions to dismiss
the suit on the grounds that the plaintiff lacked standing. In granting the motions to
dismiss, certain of the key rulings of the court were as follows:
1.
The court initially observed that:
Standing requires, at a minimum, three elements: injury in fact, a “fairly
traceable” causal link between that injury and the defendant’s conduct,
and the likelihood that the injury will be “redressed by a favorable
decision.”168
The court additionally found that standing under Texas law requires “a concrete injury
to the plaintiff and a real controversy between the parties that will be resolved”169
through the lawsuit.
2.
With regard to the plaintiff’s contention that the defendants breached
their contractual obligations and warranties to the plaintiff’s predecessors by failing to
deliver good title to the condensate, the court noted that the plaintiff’s predecessors
purchased oil from Plains, received the amount of oil promised, and used
that oil. The value as warranted and received was the same. There is no
allegation that [the predecessors] lost any money, lost the value of any
oil, were required to turn over the oil to a rightful owner, were unable to
sell the refined oil for the expected value, or received oil that was less
useful than promised...170
164
165
166
167
168
169
170
923 F.Supp.2d 961 (S.D. Tex. 2013).
Id. at 963.
Id. at 964.
Id. at 963.
Id. at 965.
Id.
Id. at 966.
57
The court concluded that a “theoretical title defect”171 to the condensate would not
satisfy the requirement for an actual injury.
3.
The court additionally held that the predecessor-assignors’ promise to
reimburse the plaintiff-assignee for any stolen condensate that the plaintiff had
purchased or received did not show that the predecessor-assignors suffered an injuryin-fact. It noted that “in addition to agreeing not to seek reimbursement from the
assignors, [plaintiff] agreed not to pursue its claims against the assignors.”172
4.
The defendants argued, and the court agreed, that the assignments of the
indirect claims asserted in the present lawsuit were against public policy and invalid
under Texas law because “the assigned claims are claims for contribution from nonsettling tortfeasors that are invalid under Texas law.173
C.
Court dismisses lawsuit against OPEC on the grounds that the
means of service of process attempted by the plaintiff failed to
validly serve OPEC in the manner required by the applicable
rules.
In Freedom Watch, Inc., v. Organization of Petroleum Exporting Countries,174 the
plaintiff, a political advocacy group, sued the Organization of Petroleum Exporting
Countries (OPEC) for alleged antitrust violations.175 The matter was before the court on
OPEC’s motion to dismiss the lawsuit for lack of service of process pursuant to Fed. R.
Civ. P. 12(b)(5). In granting the motion to dismiss, certain of the primary observations
of the district court were as follows:
1.
The court noted that there was no dispute regarding the fact that this
case is governed by Fed. R. Civ. P. 4(h)(2) because
(1) OPEC is (i) an unincorporated association that is (ii) subject to suit
under a common name, and (iii) headquartered outside of the United
States (i.e., in Austria); (2) no waiver of service has been filed; and (3)
federal law does not provide otherwise.176
Id.
Id. at 969.
173 Id. at 976.
171
172
174
288 F.R.D. 230 (D.D.C. 2013).
Specifically, Freedom Watch asserted that OPEC violated the Sherman Act, 15 U.S.C.
§ 1, and the Clayton Act, 15 U.S.C. § 1.
176 288 F.R.D. at 232.
58
175
As a result, Freedom Watch was required to show “that it effectuated service on OPEC
‘in any manner prescribed by Rule 4(f) for serving an individual, except personal
delivery under (f)(2)(C)(i).’”177
The prior decision of the Eleventh Circuit in Prewitt Enters., Inc. v.
was recognized by the court as having already rejected a number of the
arguments raised by Freedom Watch in the present suit. In Prewitt, the court
2.
OPEC,178
concluded that service on OPEC without its consent was ineffective under
Rule 4 because “no other means of service has been ‘otherwise provided
by federal law’”; there was no “‘internationally agreed means reasonably
calculated to give notice . . . and, most notably, “service on OPEC [by
registered mail] was prohibited by the law of Austria.”179
3.
The court observed that Freedom Watch did raise one argument that was
not addressed in Prewitt. It asserted that OPEC was served in this lawsuit through its
Washington, D.C. attorneys with the law firm of White & Case. However, OPEC showed
that it never authorized that law firm to accept or receive service of process from the
plaintiff. Without such authorization, the plaintiff could not validly serve OPEC through
its legal counsel.
D.
Litigant is found to have waived its claim that the arbitrator
should be disqualified from the proceedings below on grounds of
bias.
The court was presented in Grynberg v. BP Exploration Operating Co. Ltd.180 with
the appeal of the lower court’s denial of the petitioners’ motion to disqualify an
arbitrator “from any further participation in two arbitrations on the grounds of partiality
and bias, and to stay the arbitrations pending his replacement.” 181 The underlying
arbitration proceedings “arose out of the settlement of a 1996 dispute concerning rights
to an oil field in the Caspian Sea near the Republic of Kazakhstan” 182 involving
settlement agreements containing arbitration provisions that designated an agreed
individual as the arbitrator. Disputes that later developed with respect to the settlement
led to arbitration proceedings that lasted ten years. The arbitrator issued a detailed
award in which he made thirteen separate determinations, including an award of
177
178
179
180
181
182
Id., citing Fed. R. Civ. P. 4(h)(2).
353 F.3d 916 (11th Cir. 2003).
288 F.R.D. at 232.
965 N.Y.S.2d 463 (N.Y. 2013).
Id.
Grynberg v. BP Exploration Operating Limited, 2010 WL 5137912 at *2 (N.Y. Sup.
2010).
59
sanctions against Grynberg in the amount of $3 million.183
In the present phase of the appellate proceedings, the court found that the
petitioners waived any disqualification claim they might have possessed by failing to
identify the prior court’s effective refusal to discharge the arbitrator as error in their
prior notice of appeal. The petitioners asserted that because they did not advance any
arguments in support of their request that the prior court discharge the arbitrator, and
the court did not expressly address the issue in its rulings, they did not waive the
disqualification claim on the ground of alleged bias. However, the court held that “by
failing to make any arguments as to the arbitrator’s alleged partiality during [the
proceedings to confirm the arbitration award], petitioners’ waived that challenge.”184
E.
Where the plaintiff’s oil was attached by a Panamanian court, the
force majeure clause of the applicable Transportation and
Storage Agreement is found to excuse the defendant from its
obligation to make the oil available to the plaintiff.
The court in Castor Petroleum Ltd. v. Petroterminal De Panama, S.A.,185 was
presented with the question of whether the attachment of the plaintiff’s oil by a
Panamanian court, which prevented the defendant from carrying out its contractual
obligation to make that oil available to the plaintiff, triggered the force majeure
provision of the Transportation and Storage Agreement between the parties. The
attachment occurred in connection with certain lawsuits in Panama against the plaintiff,
and resulted from the fact that the plaintiff was not licensed to do business in Panama.
In dismissing the plaintiff’s complaint, the court found that the provision in
question was a “relatively broad force majeure provision [that] relieves defendant of its
obligation under the parties’ Transportation and Storage Agreement (TSA) in the event
of, among other things, a ‘government embargo or interventions or other similar or
dissimilar event or circumstances.’”186 The court held that the force majeure clause
applied to the present circumstances to excuse the performance otherwise required of
the defendant, and that “any other reading of the TSA would render the force majeure
provision (as well as other provisions of the contract) meaningless.”187
The award of sanctions was vacated in an earlier phase of the proceedings as
exceeding the authority of the arbitrator. 2010 WL 5137912 at *5.
184 Id. at 464.
185 107 A.D.3d 497 (N.Y. 2013).
186 Id. at 498.
183
187
Id.
60
IX.
Antitrust, Unfair Competition and Securities
Involving the Energy and Resources Industries
A.
Litigation
Court denies motion to dismiss class action lawsuit asserting
antitrust claims with respect to alleged efforts to manipulate
crude oil prices.
The court in In re Crude Oil Commodity Futures Litigation188 was presented with
the various defendants’ motions to dismiss under Fed.R.Civ.P. 12(b)(6) a putative class
action lawsuit that asserted claims under section 2 of the Sherman Act 189 and the
Commodities Exchange Act190 (CEA). That lawsuit arose from the alleged manipulation
of West Texas Intermediate (WTI) grade crude oil prices in 2008.191
The defendant Parnon Energy Inc. and certain affiliates (Parnon) were involved
in the trading of physical and futures contracts for crude oil, including WTI. In late
2007, the defendants noticed that the physical supply of crude oil in Cushing, Oklahoma
(a major trading and market hub for crude oil) had become very low. The plaintiffs
alleged that the defendants, in January 2008, “executed a four-step manipulation
scheme to exacerbate and profit from tightness in WTI supply.”192 The final step of the
scheme was alleged to have involved the defendants’ dumping of some 4.6 million
barrels of their own WTI on the market “after leading the market to believe that supply
would remain tight.”193 Parnon successfully repeated the same scheme in March 2008
and was alleged to have realized profits of over $50 million as a result of the scheme.
The court first discussed the defendants’ motion to dismiss with respect to the
plaintiffs’ claim of monopolization under section 2 of the Sherman Act. It noted that the
plaintiffs’ complaint alleged that
[t]he relevant geographic market is “in or around Cushing, Oklahoma.” . .
. The relevant product market is January, March, and April 2008 WTI
crude oil “readily available for delivery at Cushing, Oklahoma,” i.e., the
physical WTI market.194
188
913 F.Supp.2d 41 (S.D.N.Y. 2012) (decided December 21, 2012).
15 U.S.C. § 2.
190 7 U.S.C. § 13 et seq.
191 The United States Commodity Futures Trading Commission filed a separate
enforcement action against Parnon. See U.S. Commodity Futures Trading Comm’n v.
Parnon Energy Inc., 875 F.Supp.2d 233 (S.D.N.Y. 2012).
192 913 F.Supp.2d at 49.
189
193
194
Id.
Id. at 53.
61
However, the court also recognized that other portions of the complaint indicated that
the plaintiffs would also be asserting that the WTI derivatives (futures) market could be
a relevant market. The court noted that
[m]onopoly power alone is insufficient to sustain a section 2 violation. A
plaintiff must also show “the willful acquisition or maintenance of that
power as distinguished from growth or development as a consequence of
a superior product, business acumen, or historic accident.”195
After reviewing other aspects of the proper pleading of a monopolization claim, the
court concluded that the plaintiffs had properly alleged Parnon’s willful intent to acquire
monopoly power.
Parnon also argued in support of dismissal that the plaintiffs could not “establish
antitrust injury because they did not trade in the physical market Parnon allegedly
monopolized.”196 The court noted that “[a]ntitrust injury is an injury ‘of the type the
antitrust laws were intended to prevent ... flow[ing] from that which makes defendants’
acts unlawful.’ ”197 After reviewing the allegations in the lawsuit, the court concluded
that the plaintiffs “allege a quintessential antitrust injury—losses stemming from
artificial prices caused by antitcompetitive conduct.”198
Parnon additionally contended that the plaintiffs’ private action for violation of
the CEA was time-barred under applicable statutes of limitation because the suit was
allegedly not filed within two years after the cause of action arose. With regard to the
issue of when the CEA claim arose, the court found:
Because the Complaint alleges a complex series of steps taken across
different markets to intentionally manipulate prices, there are questions of
fact as to when Plaintiffs’ claim arose. Plaintiffs contend that the market
switch from backwardation to contango alone was not enough to put
them on inquiry notice because “[m]arkets are surprised all the time.”199
The court concluded that dismissal at the pleading stage would not be appropriate
because of the fact-intensive arguments presented by the parties.
After reviewing and rejecting a number of additional assertions of the
Id.
Id.
197 Id.
198 Id.
199 Id.
195
196
at
at
at
at
at
56.
57.
56-57.
57.
58-59.
62
defendants, the court denied the defendants’ motion to dismiss.
B.
Appellate court concludes that the Natural Gas Act does not
preempt state antitrust claims arising out of price manipulation
associated with transactions falling outside of FERC’s
jurisdiction.
The multidistrict antitrust proceedings in In re Western States Wholesale Natural
Gas Antitrust Litigation,200 arose out of the energy crisis of 2000-2002. Certain retail
purchasers of natural gas alleged
that Defendants (natural gas traders) manipulated the price of natural gas
by reporting false information to price indices published by trade
publications and engaging in wash sales.201
The resulting lawsuits were ultimately consolidated into the present multidistrict
litigation. The plaintiffs in this phase of the litigation appealed the district court’s entry
of summary judgment in favor of the defendants on the grounds that the Natural Gas
Act (NGA)202 preempted the plaintiffs’ state law antitrust claims. In reversing that
portion of the trial court’s rulings below, the Ninth Circuit found in part as follows:
1.
The court began its analysis of the issues in the case by characterizing the
primary question before it as follows:
The question presented by this appeal is as follows: does Section 5(a) of
the NGA, which provides FERC with jurisdiction over any “practice”
affecting jurisdictional rates, preempt state antitrust claims arising out of
price manipulation associated with transactions falling outside of FERC’s
jurisdiction? We conclude that such an expansive reading of Section 5(a)
conflicts with Congress’s express intent to delineate carefully the scope of
federal jurisdiction through the express jurisdictional provisions of Section
1(b) of the Act.203
2.
The court found that to interpret Section 5(a), the jurisdictional provision
of the NGA, to broadly impart “FERC jurisdiction over price manipulation associated with
nonjurisdictional sales would risk nullifying the jurisdictional provisions of Section 1(b),
which reserve to the states regulatory authority over nonjurisdictional sales.”204
200
201
202
203
204
715 F.3d 716 (9th Cir. 2013).
Id. at 724.
15 U.S.C. §§717 et seq.
715 F.3d at 729.
Id. at 732-33.
63
3.
The defendants argued on appeal that “FERC had authority to regulate
the market manipulation that gave rise to the energy crisis of 2000-2001.”205 In support
of that contention, the defendants pointed to the fact that the Code of Conduct,
promulgated by FERC in 2003, “prohibited jurisdictional sellers ‘from engaging in actions
without a legitimate business purpose that manipulate or attempt to manipulate market
conditions, including wash trades and collusion.’”206 The court rejected this argument,
finding first that Congress’s enactment of the Energy Policy Act of 2005,207 authorizing
FERC to promulgate rules and regulations to protect against market manipulation,
indicated that FERC did not already have regulatory authority over the types of
anticompetitive conduct at issue in this case. The court additionally observed that FERC
had limited the scope of the Code of Conduct to sales within its jurisdiction. As a result,
FERC’s enactment of that Code did not conflict with the court’s conclusion “that the
NGA does not grant FERC jurisdiction over claims arising out of false price reporting and
other anticompetitive behavior associated with nonjurisdictional sales.”208
C.
Court holds that FERC lacked jurisdiction to charge and assess a
fine against a trader of natural gas futures contracts traded on
the NYMEX, a CFTC-regulated exchange, for alleged manipulation
of the settlement price in futures contracts.
The plaintiff in Hunter v. Federal Energy Regulatory Commission209 was a trader
for Amaranth, a hedge fund, and “traded natural gas futures contracts on the New York
Mercantile Exchange (NYMEX).”210 NYMEX is regulated by the Commodity Futures
Trading Commission (CFTC). Under the authority of the Energy Policy Act of 2005, the
Federal Energy Regulatory Commission (FERC) fined the plaintiff $30 million for
allegedly manipulating natural gas futures contracts. In the present appeal, the plaintiff
asserts that FERC does not have authority to impose the $30 million fine on him
“because the [CFTC] has exclusive jurisdiction over all transactions involving commodity
futures contracts.”211 The CFTC intervened in this appeal in support of the plaintiff on
the jurisdictional issue. In ruling in favor of the plaintiff and against FERC, certain of the
primary findings of the court were as follows:
First, after a review of pertinent legislative enactments, the court found that
205
206
207
208
209
210
211
Id. at 735.
Id.
15 U.S.C. § 717c-1.
715 F.3d at 736.
711 F.3d 155 (D.C. Cir. 2013).
Id. at 156.
Id.
64
“Congress crafted CEA212 section 2(a)(1)(A) to give the CFTC exclusive jurisdiction over
transactions conducted on futures markets like the NYMEX.”213
Second, the court recognized that the Energy Policy Act of 2005,214 which was
enacted by Congress in light of the California energy crisis, significantly expanded
FERC’s Authority to regulate manipulation in energy markets. FERC argued that that Act
repealed, by implication, the provisions of the CEA giving the CFTC exclusive jurisdiction
with respect to “ ‘transactions involving contracts of sale of a commodity for future
delivery, traded or executed’ on a CFTC-regulated exchange.”215 However, the court
found that because FERC failed to show an implied repeal of the exclusive jurisdiction of
the CFTC, “FERC lacks jurisdiction to charge Hunter with manipulation of natural gas
futures contracts.”216
D.
Inaccurate information in FERC filings, designed to avoid
disclosure of possible violations of covenant not to compete,
leads to FERC assessment of civil penalty.
In Kourouma v. Federal Energy Regulatory Commission,217 FERC had assessed a
$50,000 civil penalty on Kourouma “because he made false statements and material
omissions in forms he filed with the Commission and a market operator the Commission
regulates.”218
The underlying actions of Kourouma related to his employment as a trader in
various energy markets with Energy Endeavors LP. In the course of that employment,
“Kourouma signed an employment contract that contained a non-compete clause that
committed him to trade only for Energy Endeavors during his time at the firm and for
two years after leaving the firm.”219 During the course of that employment, Kourouma
formed his own trading firm, Quntum Energy LLC. To enable Quntum to participate as a
trading company in the energy markets, “Kourouma filed applications with FERC and a
regional transmission organization that operates”220 trading markets in electricity, PJM
Interconnections LLC. The court found that the filings concealed Kourouma’s role with
Quntum, and inaccurately listed other individuals as holding certain positions with that
company.
212
213
214
215
216
217
218
219
220
The Commodity Exchange Act is codified at 7 U.S.C. 1 et seq.
711 F.3d at 157.
42 USC § 15801 et seq.
711 F.3d at 158.
Id. at 160.
723 F.3d 274 (D.C. Cir. 2013).
Id. at 276.
Id.
Id.
65
In the course of the FERC investigation into his activities Kourouma
acknowledged that he used inaccurate names in the filings “in order to avoid making
Energy Endeavors aware of his involvement with Quntum.”221 In reliance on
Kourouma’s admission that he had included inaccurate information in his filings, FERC
concluded, without a hearing, “that Kourouma violated Market Behavior Rule 3 and
assessed a $50,000 civil penalty payable over five years to accommodate his financial
condition.”222
Kourouma filed a petition for review with the court alleging procedural and
substantive errors by FERC. In denying that petition, the court first upheld FERC’s
summary disposition of the case without a hearing under 16 U.S.C. § 823b(d)(2)(A)
because “Kourouma’s admissions resolved all disputes of material fact, making an
evidentiary hearing unnecessary.”223
With respect to Kourouma’s contention that FERC’s ruling was in error “because
there was no showing that he had any intent to deceive FERC or PJM with his false
filings,”224 the court noted that Market Behavior Rule 3 does not require an intent to
deceive as an element of the offense. The court also observed that Rule 3 “forgives
false or misleading submissions only if they are made inadvertently despite the filer’s
due diligence to avoid such errors.”225
E.
Court rules in favor of defendants in lawsuit alleging federal
securities fraud.
In Securities and Exchange Comm’n v. St. Anselm Exploration Co.,226 the United
States Securities and Exchange Commission (SEC) sued the defendant energy company
and its officers for alleged misrepresentations in violation of section 17(a)(2) of the
Securities Act of 1933227 and SEC Rule 10b-5(b).228 The SEC also asserted scheme
liability under sections 17(a)(1) and (3) of the Securities Act229 and SEC Rules 10b-5
and (c). After the conclusion of a bench trial, the district court granted the defendants’
motion for entry of judgment in the defendants’ favor as a matter of law under
Fed.R.Civ.P. 52(c). In reaching that conclusion, the court made detailed findings and
Id. at 277.
Id.
223 Id. at 278.
224 Id.
225 Id.
221
222
226
227
228
229
936 F.Supp.2d 1281 (D. Colo. 2013).
15 U.S.C. § 77q(a)(2).
17 C.F.R. §240.10b-5(b).
15 U.S.C. §77q(a)(1) & (3).
66
rulings, including the following:
1.
The court observed that “[t]he securities laws ‘do not create an
affirmative duty to disclose any and all material information.’” 230 Rather, those laws
create a duty to disclose “only ‘when necessary to make ... statements made, in the
light of the circumstances under which they were made, not misleading.’” 231 Here, in
support of its claims of securities fraud, the SEC asserted
two primary misrepresentations—that investor funds would be used to
advance the company’s operations (specifically drilling and property
acquisition) and that payments to investors would be funded by the
operations of the company (primarily from asset sales)—and two primary
omissions—that investor funds were used to pay off existing debt and that
the company had insufficient funds to pay ongoing expenses without
raising new capital from promissory notes.232
2.
The court found that the defendants’ “Subscription Agreement was not
misleading simply because it did not specifically enumerate debt service as a possible
use of investor funds.”233 Moreover, investors who inquired about the use of their
invested funds “were told plainly about SAE’s policy of ‘bridging the gap’ by relying on
monies from new notes to service debt”234 associated with existing activities. The court
found that “servicing company debt is a proper business purpose”235 of the defendant
company.
3.
The SEC’s contention that one of the officers committed fraud by assuring
certain investors that the company was not a Ponzi scheme was rejected by the court,
which found that the evidenced failed to show that the investment “had any of the true
hallmarks of a Ponzi scheme.”236
4.
With respect to the alleged fraud concerning the financial condition of the
company, the court concluded that the evidence failed to show that the defendant
company’s “actual economic position at the time of [certain communications with
investors] was so precarious as to make this disclosure materially misleading.”237
230
936 F.Supp.2d at 1295
Id.
Id.
233 Id.
234 Id.
235 Id.
236 Id.
237 Id.
231
232
at
at
at
at
at
at
1293.
1295.
1294.
1287.
1286.
1298.
67
5.
In regard to the SEC’s assertions of scheme liability, the court found that
“scheme liability exists only where there is deceptive conduct going beyond
misrepresentations.”238 The court found that there was nothing inherently deceptive
about the actions the SEC alleged as the basis for its claim for scheme liability, so it
additionally entered judgment in favor of the defendants as to that claim.
X.
Other Energy Industry Cases
A.
Court Addresses Lawsuit by Clients and Their Attorneys Against
Expert Witness for Negligence and Breach of Contract in the
Performance of the Duties of the Expert Witness in a Lawsuit
Alleging Groundwater Pollution as a Result of Oilfield Waste
Disposal.
Without attempting to describe the lengthy and complex factual and procedural
history of this case in detail, those involved in either expert witness work or a litigation
practice may want to note for future reference the case of Ellison v. Campbell.239 In
that lawsuit, the plaintiffs had previously alleged in a separate lawsuit that the
defendants were responsible for causing pollution of the groundwater on the Ellisons’
property. Campbell was hired to serve as an expert witness for the plaintiffs. The
plaintiffs and their attorneys in that prior lawsuit alleged in the present action that the
defendant expert witness had been negligent, had breached his contractual obligations
and in fact had tortuously breached its contract in the course of performing as an
expert witness in the prior underlying pollution lawsuit. The plaintiffs alleged that, as a
result of the defendant’s performance, they were required to settle the pollution lawsuit
for far less that the actual value of that case. The defendants asserted counterclaims
for declaratory judgment, breach of contract and unjust enrichment.
The trial court granted the defendants’ motion to dismiss the negligence and
tortious breach of contract claims. The case proceeded to jury trial in 2010. At the
conclusion of the trial, and based on the jury’s verdict, the trial court entered a
judgment finding in favor of the plaintiffs and against the defendants in the amount of
$408,748.68, plus statutory interest, on the breach of contract claim. The defendants
appealed.
In a 2-1 decision, the Oklahoma Court of Appeals found that the trial court erred
in not requiring the plaintiffs to present an expert witness to refute the defendant
Campbell’s own expert testimony and to establish that the defendants’ actions
238
239
Id. at 1299.
84 Okla. Bar J. 1986 (Okla. App. 2013 - #108,468), opinion vacated at 2014 OK 15,
326 P.3d 68.
68
constituted a breach of contract. Rather than presenting a like scientific expert to
counter Campbell’s testimony, the plaintiffs presented as witnesses (a) one of the
defense attorneys from the underlying pollution lawsuit who testified that Campbell’s
expert report did not make sense, that Campbell was unable to support the report at
his deposition, and that the Ellisons’ pollution lawsuit was in serious trouble after
Campbell’s deposition, and (b) one of the plaintiff attorneys from the present lawsuit
and the underlying pollution lawsuit who testified that, at his deposition, Campbell was
unable to explain his opinions stated in his report, nor could he explain the errors
contained in the report, and that Campbell’s work was scientifically unsupportable, and
Ellisons’ attorneys knew after Campbell’s deposition that they would be unable to use
Campbell to advance the Ellisons’ case. However, the Ellisons did not, in the Court of
Appeals’ view, present any expert witness to counter the expert testimony that
Campbell provided at trial in defense to the Ellisons’ claims. Because of that omission,
the court concluded that the Plaintiffs failed to establish their claim for breach of
contract. The court reversed the trial court’s judgment in favor of the Ellisons.
However, on certiorari review before the Oklahoma Supreme Court, 240 the
opinion of the Court of Appeals was vacated and the trial court’s judgment in favor of
the Ellisons was affirmed. After a lengthy, detailed review of the factual record at trial,
the court held as follows:
¶22 This opinion should not be read for the proposition that a losing
party may recover monies paid to an expert witness for the formulation
and presentation of an opinion in the context of litigation merely because
the party requesting such opinion did not prevail or recover to the extent
anticipated. Rather, here, we are faced with a unique set of
circumstances. An individual held himself out as an expert in hydrogeology
capable of preparing a scientifically supportable report in that field. He
contracted with the Ellisons to prepare such a document and be available
to support it with his testimony. Instead, he produced a report which was
admittedly error-riddled and based upon methodologies not meeting
either state or federal regulations. Simply, Campbell did not perform the
services for which the Ellisons contracted and paid.
¶23 The cause was tried to a jury. It heard evidence competent to
support its verdict. Whether we agree or disagree with the outcome is
immaterial. It is not for this Court to second-guess such a verdict.
Therefore, we affirm both the trial court's denial of a new trial and motion
for judgment notwithstanding the verdict.
The court held, as a matter of “first impression,” that it was not necessary in the
240
2014 OK 15, 326 P.3d 68.
69
present breach of contract suit---in which the plaintiff sought compensation for an
expert witness’s failure to provide competent litigation support services in an underlying
lawsuit---to prove the claims with the presentation of expert testimony. The testimony
presented at trial was such that a lay person, through common knowledge or
experience, could determine that Campbell did not produce the very thing for which the
Ellisons contracted---a supportable expert opinion concerning the state of groundwater
underlying their property and the source of its pollution.
B.
Reserve pits used in commercial oil development are found to be
outside the reach of the Migratory Bird Treaty Act.
In United States v. Brigham Oil and Gas, L.P.,241 the government had initially
charged seven oil and gas companies with violations of the Migratory Bird Treaty Act
("MBTA").242 Three of the companies entered into plea agreements and the charges
against one of the companies were dismissed by the government. Brigham, Newfield
and Continental Resources proceeded to defend the charges filed aginst them and they
moved the court to dismiss the indictments against them for violations of the MBTA. As
to all three defendants, the indictments were based upon the discovery of dead
migratory birds near the companies' reserve pits in North Dakota.
The court found the reserve pits were not directed at migratory birds or their
habitats, and that the pits had little effect on bird habits "except to attract occasional
birds which mistake the pits for a pond or lake."243 The court ruled that "the use of
reserve pits in commercial oil development is legal, commercially-useful activity that
stands outside the reach of"244 the MBTA, and it granted the three defendants' motions
to dismiss.
C.
Court in Deepwater Horizon litigation addresses certain of the
standards applicable in determining whether court approval of a
proposed class action settlement will be granted.
Class action lawsuits, with accompanying class settlements, have been a
dominant feature of energy and resources litigation in recent years. In In re: Oil Spill by
the Oil Rig “Deepwater Horizon” in the Gulf of Mexico, on April 20, 2010,245 the district
court was presented with the parties’ motions for final approval of a proposed class
action settlement relating to certain claims for economic loss and property damage
resulting from the Deepwater Horizon incident. In a very lengthy order, the court
241
242
243
244
245
840 F.Supp.2d 1202 (D. N.D. 2012).
16 U.S.C. §§ 703 and 707(a).
840 F.Supp.2d at 1211.
Id.
910 F.Supp.2d 891 (E.D. La. 2012), decided December 21, 2012.
70
addressed a multitude of issues particularly encountered with large class action
settlements in the energy and resources sector. Some of the key rulings of the court
are as follows:
1.
Citing the Supreme Court’s prior decision in Amchem Prods., Inc. v.
246
Windsor,
the court noted that when courts are asked to certify a case solely for
settlement purposes,
[A] district court need not inquire whether the case, if tried, would present
intractable management problems . . . for the proposal is that there be no
trial. But other specifications of the Rule—those designed to protect
absentees by blocking unwarranted or overbroad class definitions—
demand undiluted, or even heightened, attention in the settlement
context. Id. At 620, 117 S.Ct. 2231.”247
2.
In the Fifth Circuit, six factors guide the determination of whether a
settlement is fair, reasonable and adequate:
(1) the existence of fraud or collusion behind the settlement; (2) the
complexity, expense, and likely duration of the litigation; (3) the stage of
the proceedings and the amount of discovery completed; (4) the
possibility of plaintiffs’ success on the merits; (5) the range of possible
recovery; and (6) the opinions of the class counsel, class representatives,
and absent class members.248
3.
The court found that a strong presumption exists in favor of finding that a
class settlement is fair, reasonable and adequate because the public interest strongly
favors the voluntary settlement of class actions.249
4.
The court took judicial notice of prior oil spill litigation (e.g., Exxon Valdez)
that required at least 15 to 20 years to resolve, and then observed:
This litigation has taxed the resources of both the parties and the Court.
In light of the complex issues of law, engineering, science, and operative
fact presented by this litigation, simply completing trial could require
several years.250
246
247
248
249
250
521 U.S. 591, 621, 117 S.Ct. 2231, 138 L.Ed.2d 689 (1997).
910 F.Supp.2d at 911.
Id. at 912.
Id. at 930-31.
Id. at 931-32.
71
The court went on to note that the complex and novel issues presented in the litigation
would likely lead to appeals that could continue the proceedings for a decade or more.
The proposed class settlement would largely remove the many years otherwise standing
between the class and any recovery.
5.
With regard to the factors of the probability of success on the merits and
the range of possible recovery, the court found that it “must not try the case in the
settlement hearings because the very purpose of the compromise is to avoid the delay
and expense of such a trial.”251 It further recognized that courts are to determine
whether the settlement consideration is fair
not by attempting the impossible task of deciding whether the parties
have “reached ‘exactly the remedy they would have asked the Court to
enter absent the settlement,’” but instead by “whether the settlement’s
terms fall within a reasonable range of recovery, given the likelihood of
plaintiffs’ success on the merits.’”252
6.
In regard to the multiple objectors, the court found that non-settling
persons generally have no standing to challenge a proposed class settlement. Those
who fall outside the scope of the proposed settlement are unaffected and therefore lack
standing to object. The court did note that “[n]on-settling defendants who will suffer
‘plain legal prejudice’ as a result of a settlement have sometimes been held to have
standing to challenge the settlement.”253 However, the court found that the proposed
settlement did not cause the non-settling defendants in the present case (such as
Halliburton) “plain legal prejudice,”254 so that they lacked standing.
7.
On the issue of whether organizations could file objections on behalf of
their members, the court held that a group called GO FISH lacked standing to object
because “no organization may represent its members where the underlying form of
relief at issue is money damages.”255
8.
With respect to the efforts of certain Gulf Coast states to object, the court
found that the states lacked standing to object for a variety of reasons described in its
opinion.256 With regard to the provisions of the Class Action Fairness Act (CAFA) that
require the giving of notice to certain states of proposed class settlements of lawsuits
Id.
Id.
253 Id.
254 Id.
255 Id.
256 Id.
251
252
at 933.
at 942-43.
at 943.
at 943-44.
72
removed to federal court under CAFA,257 the court concluded that “[t]his statute simply
requires notification; it does not create standing that a state official otherwise lacks.”258
9.
The court noted that some states argued that their standing to object
derived from their view that the proposed settlement inadequately compensated their
citizens, and would thus require those particular states to spend more in unemployment
insurance and other benefits. The court rejected that contention and observed that
“[t]his argument would logically give standing to any state to challenge any settlement
of a private dispute; thus, similar arguments have been repeatedly rejected by federal
courts.259
10.
Some of the objectors asked the court to conditionally approve the
settlement subject to the parties agreeing to modify the terms of the Settlement
Agreement in certain respects. In response, the court cited prior authority for the
proposition that
although the Court has the power to approve or reject a settlement
negotiated by the parties, the Court may not require the parties to accept
a settlement or a consent order to which they have not agreed.260
With regard to the concept of “conditional” approval, the court noted that it is only
appropriate to impose conditions where modifications are needed in order to keep the
settlement from failing to satisfy an analysis under Fed. R. Civ. Proc. 23(e).
11.
The court additionally held that the settlement class members do not have
the right to be informed as to the exact dollar amount of their compensation prior to
the deadline for opting out of the settlement.261
12.
Certain objectors complained that the release under the Settlement
Agreement was unduly broad. However, the court responded that “the law is settled
that defendants entering into a class settlement are entitled to obtain global peace and
that class action releases may be broader than the claims directly compensated under
the Settlement.”262
The court approved the proposed class settlement as fair, reasonable and
adequate.
257
258
28 U.S.C. § 1715.
910 F.Supp.2d at 943.
Id.
Id. at 944.
261 Id. at 945.
262 Id. at 962.
259
260
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D.
Additional discussion of class settlement standards in second
phase of Deepwater Horizon litigation.
Three weeks after entering the rulings described in the preceding section of this
report which approved the economic and property damages settlement agreement in
MDL 2179, the court issued a separate order approving the medical benefits class action
settlement. In re: Oil Spill by the Oil Rig “Deepwater Horizon” in the Gulf of Mexico, on
April 20, 2010.263 In approving that separate class settlement, the court repeated
certain of the standards mentioned above and made a number of additional
observations including the following:
1.
The court briefly discussed the possible use of subclasses in a class
settlement context “when there is a ‘fundamental’ conflict among class members.”264
2.
The court also noted that the settlement consideration negotiated at arm’s
length by knowledgeable counsel is presumed to be reasonable since, “under Rule 23,
Class Counsel ‘are in the best position to evaluate the fairness due to an intimate
familiarity with the lawsuit.’”265
E.
Court rejects finding that oil and gas title opinions were not
privileged because they were based on public information, and
discusses the standards in Colorado for resolving disputes over
the appropriate scope of discovery.
In DCP Midstream, LP v. Anadarko Petroleum Corp.,266 the Colorado Supreme
Court addressed discovery under Rule 26 of the Colorado Rules of Civil Procedure and
the question of whether the oil and gas title opinions that were sought to be obtained
through discovery in that case were subject to the attorney-client privilege. The
underlying litigation involved a suit by DCP against Anadarko for breach of contract and
other claims. DCP served Anadarko with requests for production of documents that
sought production of oil and gas title opinions and other materials. Anadarko asserted
that many of the document requests were not relevant to the lawsuit, and that the title
opinions were additionally protected from discovery as attorney-client communications.
DCP filed a motion to compel. “Without holding a hearing, the trial court granted DCP’s
motion. The trial court did not address any of Anadarko’s objections, nor did it provide
any analysis under C.R.C.P. 26(b)”267 to support its rulings. In a later order, the court
263
264
265
266
267
2013 WL 1440424 (E.D. La. 2013).
Id. at *27.
Id. at *43.
2013 CO 36, 303 P.3d 1187.
Id. at 1190, par. 3.
74
found, among other matters, that “Anadarko’s title opinions were not privileged
because they were based on public information.”268
In overruling the holdings of the trial court, the Colorado Supreme Court
observed that “[t]o conclude that legal advice loses its privileged character when based
on public information . . . would render the attorney-client privilege meaningless in
many circumstances.”269 The court concluded that the lower court’s reasoning was
without merit. The court held that the title opinions had to first be reviewed in order to
determine whether they were protected by the privilege.
With regard to the trial court’s decision that DCP was entitled to discovery on any
issue that is or may become relevant, the appellate court found that the trial court
erred by reaching its ruling without determining the appropriate scope of discovery in
light of the reasonable needs of the particular lawsuit presented and tailoring discovery
to fit those needs.270
F.
Court in Deepwater Horizon litigation affirms dismissal of
derivative shareholder lawsuit on forum non conveniens grounds,
finding that the action should instead be pursued in England.
The case of City of New Orleans Employees’ Retirement System v. Hayward,271
involved a shareholder derivative action “under the U.K. Companies Act 2006, alleging
that the 2010 Deepwater Horizon disaster was the culmination of a longstanding
pattern of Defendants’ breaches of fiduciary duties to BP.” 272 The defendants were
individual officers and directors of BP. The plaintiffs asserted that the lawsuit could be
brought in the U.S. because of numerous contacts between the U.S. and the underlying
facts of the suit and the business operations of BP. The plaintiffs also argued that
judicial economy would be served if the action proceeded in the U.S. due to parallel civil
and criminal proceedings in the same forum. The defendants moved to dismiss the case
on forum-non-conveniens (FNC) grounds and asserted that the case should be brought
in England. The district court sustained that motion, and the plaintiffs appealed. In
affirming the district court’s dismissal of the case, the circuit court found in part as
follows:
268
269
Id.
Id. at 1199, par. 42.
The appeal in this matter involved substantial participation by amici curiae, including
the American Association of Professional Landmen, the American Petroleum Institute,
the American Tort Reform Association, the National Association of Manufacturers, the
Product Liability Advisory Council and Chevron U.S.A. Inc.
271 508 Fed.Appx. 293 (5th Cir. 2013).
272 Id. at 295.
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270
1.
The district court appropriately conditioned its dismissal of the case “on
Defendants either providing proof of amenability to service of process or stipulating that
they would ‘submit to the jurisdiction of the English courts.’”273 The court noted that the
defendants had filed a stipulation to that effect.
2.
While there is usually a strong presumption in favor of the plaintiff’s
choice of forum, which should only rarely be disturbed, the court found that the present
lawsuit “presents an exception to the general rule of deference . . . because it ‘involves
the special problems of [FNC] which inhere in derivative actions.’”274 In particular, the
claim of any one plaintiff in a derivative action “that a forum is appropriate merely
because it is his home forum is considerably weakened.”275 The court noted that such is
especially the case where the plaintiffs were “mere phantom plaintiff[s] with interest
enough to enable [them] to institute the action and little more.”276
3.
The court considered the private interest and public interest factors that
are to be taken into account in connection with FNC objections and concluded that the
district court appropriately exercised its discretion in finding that those factors favored
dismissal.
Id. at 296.
Id. at 297.
275 Id.
276 Id.
273
274
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