Blawgletter®

Does the Supreme Court Disfavor Limitations Defenses?

Focus on substance over procedure

The Supreme Court just vacated a judgment that enforced a six-year statute of limitations against beneficiaries of a employer savings plan.

The ruling reinforces the view that this Court feels little love for limitations defenses. It suggests the Court prefers getting to legal substance.

Claims under ERISA

The Employee Retirement Income Security Act of 1974 governs savings, pension, and other plans that companies set up to benefit employees and their families. The statute protects plan beneficiaries partly by giving them the right to sue the plan sponsor (the employer) and other plan fiduciaries (often officers of the sponsor) for breaching their fiduciary duties to the plan and plan beneficiaries.

One kind of ERISA claim challenges the prudence of plan investment options on the ground that the plan and its fiduciaries should have periodically reviewed those options and substituted lower-cost alternatives.

The plaintiffs in Tibble v. Edison Int'l, No. 13-550 (U.S. May 18, 2015), made just such a claim. They alleged that the Edison 401(k) Savings Plan's sponsor (the power generator Edison International) and the Plan's fiduciaries violated their duty of care by not monitoring the mutual funds that the Plan offered and swapping less expensive choices for the existing ones.

Summary judgment

The district court granted the motion of Edison and the other defendants for summary judgment on the ground that the six-year statute of limitations expired before plaintiffs sued. It allowed the Tibble plaintiffs to argue that the Plan's fiduciaries should have conducted a review of investment options within the limitations period but rejected their argument, holding that Tibble and the others "had not met their burden of showing that a prudent fiduciary would have undertaken a full due-diligence review of these funds as a result of the alleged changed circumstances." Tibble, slip op. at 3. The Ninth Circuit affirmed. Tibble v. Edison Int'l, 729  F.3d 1110 (9th Cir. 2013).

Try again

The Supreme Court unanimously disagreed with the courts below. Per Justice Stephen Breyer, the Court concluded that the district court and court of appeals had applied too stringent a test for when a change in circumstances triggers a fiduciary's duty to review the investment options of plan participants.

Justice Breyer noted that, "under trust law, a fiduciary normally has a continuing duty of some kind to monitor investments and remove imprudent ones." Id. at 6. The Ninth Circuit erred by not "considering the nature of the fiduciary duty" and by failing to "recognize that under trust law a fiduciary is required to conduct a regular review of its investment with the nature and timing of the review contingent on the circumstances." Id. at 5.

Because the Ninth Circuit required proof of a "significant" change in circumstances before a duty to reevaluate investment choices arose, the Court vacated the decision and remanded to the Ninth Circuit "to consider petitioners' claims that respondents breached their duties within the relevant 6-year period under 1113, recognizing the importance of analogous trust law." Id. at 7.

Take-away

Last May, the Court ruled against another defendant who complained about the tardiness of a lawsuit. In Petrella v. Metro-Goldwyn-Mayer, Inc., 134 S. Ct. 1962 (2014) (post here), the Court held that a laches defense cannot override Congress's judgment to allow suits under copyright law to collect damages for a three year "look-back" period.

The outcomes in Tibble and Petrella support the view that the Court gives narrow play to procedural defenses like limitations.

Limitations defenses present especially thorny issues for plaintiffs. The plaintiff may take the case all the way to verdict before she learns that limitations bars her claim. Plaintiffs should prefer to get that over soon, before they've spent a lot of time and resources on the case. Delaying judgment day on limitations thus may end up doing more harm to the plaintiffs -- and their contingent-fee counsel -- than good.

Barry Barnett

Fifth Circuit Upholds $25 Million Contingent Fee

Keys to the court house 

The contingent-fee option enables a claimant who has a valuable claim but can't afford hourly fees to hire a lawyer. He pays with a promise to share his recovery with the lawyer in return for the lawyer's sharing the many risks of pursuing a claim -- including the risk of losing (or winning too little), of not collecting from the defendant, and of the effort's costing a lot more than you expected. 

People with plenty of money can agree to pay on contingent-fee basis, too -- and they often do.

A client that won't abide by the contingent-fee agreement represents another kind of danger for the lawyer. A recent decision by the Fifth Circuit will help keep that danger in check, to the benefit of almost everyone.

Family fight

The case that produced the ruling arose from disputes over the fortune of Texas oil legend H. L. Hunt.

Hunt's great-grandson Al Hill, III, and his wife Erin engaged two law firms to represent them in more than a dozen lawsuits. The cases concerned the Hills' claims to assets of two trusts that H. L. Hunt and his wife had set up during the 1930s in the name of their daughter Margaret, who later married Al Hill, Sr., and Haroldson, the oldest son.

The Hills agreed in the engagement letters to pay the law firms full hourly rates for all of their work plus 15 percent of the Hills' "Gross Recovery". But because the Hills did not have the means to pay the hourly fees on a current basis, the contracts allowed them to defer payment until "financially practicable".

Fee fight

A year later, the law firms asked the Hills to pay $3.2 million for their hourly work. The Hills refused. They then fired the firms, which in turn brought arbitration against the Hills under the fee contracts. 

The trust lawsuits at length settled on a basis that yielded $188 million to the Hills.

An arbitration panel heard evidence on the law firms' fee claim for nine days. The panel rejected the Hills' "unconscionability" defense, among others, and awarded the firms their full fees -- $3.2 million for the hourly component and a little more than $25 million for the contingent-fee part.

But when the firms asked the U.S. District Court in Dallas to confirm the award, it refused. The court ruled that Texas ethical rules would deem collecting an hourly fee plus a contingent one unconscionable:

In plain language, this is not simply a contract that was ill-advised when signed, but it is one in which Plaintiffs will receive something for nothing. The contingency fee is a guaranteed fifteen percent payment, on top of the generous hourly rate, for no additional work or risk of nonpayment. The court finds this type of contingency fee particularly troublesome and contrary to well-established Texas precedent. The contingency fee provision therefore results in a windfall that Texas public policy cannot countenance.

Campbell, Harrison & Dagley, L.L.P. v. Hill, No. 3:12–CV–4599–L, 2014 WL 2207211, at *13 (N.D. Tex. May 28, 2014).

The law firms appealed.

Fifth Circuit upholds fee agreement

Reversing, the Fifth Circuit reinstated the arbitration award. Campbell, Harrison & Dagley, L.L.P. v. Hill, 782 F3d 240 (5th Cir. 2015). It held:

The district court misapplied that standard. In particular, it rejected the arbitrators' determination that “the prospect of recovery [was] plenty uncertain”, finding instead that “[t]here was nothing contingent about [the firms'] recovery of their attorneys' fees”. . . . The court specifically rejected the total-fee amount based on its inclusion of the contingency-fee portion. As the court interpreted the fee agreement, the contingency fee constituted an “unearned payment” in the light of the non-contingent nature of the hourly-rate fees, and, as a result, made the fee agreement unconscionable. . . .

 

The arbitrators, on the other hand, specifically determined: recovery of any fees was uncertain; a reasonable attorney could find the fee arrangement reasonable; and the total fee was not unconscionable. (“There is nothing about a relatively high hourly rate schedule, uncertain to time of payment, and/or a relatively low contingent percentage, when the prospect of recovery is plenty uncertain, that should be offensive to a competent lawyer, a reasonable client, or an overall traditional public policy of fairness.”). This determination likewise comports with the plain language of the fee agreement, which allows for payment of the hourly-rate fees “as soon as is financially practicable ”. (Emphasis added.)

 

In rejecting the arbitrators' determinations regarding the uncertainty of recovery, the reasonableness of the total fee, and unconscionability, the court “substitute[d] [its] judgment for that of the arbitrators merely because [it] would have reached a different decision”. . . . As a result, it erred in vacating the contingency-fee-portion of the award and related awards (for the arbitration, the firms' attorney's fees, other fees, expenses, and arbitrators' compensation; and pre-judgment interest on the contingency-fee portion).

Campbell, Harrison & Dagley, L.L.P., 782 F.3d at 245-46 (citations omitted).

Significance

The outcome enhances confidence in contingent-fee agreements and therefore lowers the collection risk that law firms face when entering into contingent-fee arrangements with clients.

That should save clients who live up to their contracts money. Lower risk of collection will translate into contingent-fee percentages that reflect a premium for sharing risk of recovery on the client's claim but do not build in an additional premium for the lawyer's risk of enforcing the fee deal.

Everybody wins. Except of course the defendant.

Hottest Oil & Gas Claims, Part 7: Surface Damage

Surface damage – what must operators do to accommodate existing uses of the surface estate?

Today we conclude Blawgletter's seven-part series on the Hottest Oil & Gas Claims for 2015, a paper we co-wrote for the 66th Oil & Gas Law Conference in Houston. This last piece deals with maybe the hardest claim to make out -- a claim by the surface owner against an oil and gas lessee for interfering with pre-existing uses of the property.

Legal backdrop

Common-law states like Texas give the owner of minerals that underlie a tract of land priority over the owner of the tract’s surface. The mineral owner thus has the “dominant” estate, the surface owner the “subservient” one. Louisiana law likewise infers a right of the mineral owner -- or, much more often, the lessee under an oil and gas lease -- to make reasonable use of the surface. See, e.g., Caskey v. Kelly Oil Co., 737 So.2d 1257, 1262-63 (La. 1999).

In rare instances, the surface owner may get damages for an oil and gas operator’s abuse of its dominant position. The surface owner must prove that the operator’s use of the surface completely precludes or substantially impairs her existing use of the surface, she has no reasonable alternative way to continue the existing use, and the operator could accommodate the existing use by employing a reasonable and customary method that the oil and gas industry accepts. Merriman v. XTO Energy, Inc., 407 S.W.3d 244, 249 (Tex. 2013) (holding that rancher failed to carry burden of showing that “he had no reasonable alternative means of maintaining his cattle operations” on a 40-acre tract); see Key Operating & Equip., Inc. v. Hegar, 435 S.W.3d 794, 799 (Tex. 2014) (holding that lessee’s “implied surface easement extends to the surface of [a] pooled area”).

What options do surface owners have when they believe an operator has overstepped its right to use the surface?

Plaintiff's claim

Although difficult to establish, a claim for misuse of the surface will involve these factors: 

• History of using the surface of the lease area for a specific profit-seeking purpose;

• Excessive or indiscriminate damage to or occupation of the surface; and

• Substantial loss of income due to interference with the existing use.

Wrap up

We appreciate your interest in the Hottest Oil & Gas Claims for 2015 series. You can read the rest of it by clicking on the links below.

• Hottest Oil & Gas Claims, Part 1: Busting Leases
• Hottest Oil & Gas Claims, Part 2: New Technology
• Hottest Oil & Gas Claims, Part 3: What Counts as a Well?
• Hottest Oil & Gas Claims, Part 4: Flaring Gas
• Hottest Oil & Gas Claims, Part 5: Exculpatory Clauses
• Hottest Oil & Gas Claims, Part 6: Unreasonable Expenses

Something new

Blawgletter will have a surprise for you in the next couple of weeks. Please stand by.

Hottest Oil & Gas Claims, Part 6: Unreasonable Expenses

Short-payment of royalties – when do post-production costs cross the line into unreasonableness?

This next-to-last entry in Blawgletter's seven-part series on the hottest oil & gas claims for returns to the theme of royalty owners who receive less than they believe the lease entitles them to. Part 6 addresses what happens when the operator deducts post-production expenses that it paid to its affiliates rather than independent entities. May the royalty owners sue to bar deduction of affiliates' "unreasonable" charges and recover shortages on earlier royalty payments due to those unreasonable charges?

Legal backdrop

Royalty owners often complain when operators agree to compute royalties (per the lease) “at the mouth of the well” but then deduct costs that arise downstream. They may feel even more unhappy if the leases (in which they reserved their royalty interests) provide something like “the royalty shall be free of all costs related to the exploration, production and marketing of oil and gas production from the lease”. 

Under Texas law, even an express bar on post-production costs may have no effect. See Potts v. Chesapeake Expl., L.L.C., 760 F.3d 470 (5^th Cir. 2014) (applying Heritage Resources v. NationsBank, 939 S.W.2d 118 (Tex. 1996), to declare no-deduct clause surplusage); Warren v. Chesapeake Expl., L.L.C., 759 F.3d 413 (5^th Cir. 2014) (same); but see Chesapeake Expl., L.L.C. v. Hyder, 427 S.W.3d 472, 477 (Tex. App. – San Antonio 2014, pet. granted) (“[W]e interpret the parties’ agreement as the royalty clause excluding all costs and expenses of production and post-production, including post-production costs and expenses incurred between the point of delivery and the point of sale.”)^* (emphasis in original). Even in jurisdictions that, like Texas, permit deduction of post-production costs despite clauses that appear to prohibit the practice, might the royalty owners still have a claim for short-payment?

The Fifth Circuit in Warren left open the issue of the impact of sales to affiliates. The panel noted that “the parties have not argued or briefed, and this opinion does not consider, the relationship among affiliated Chesapeake entities or the impact, if any, that relationship might have on matters at issue regarding the payment or calculation of royalties.” Warren, 759 F.3d at 419. The non-decision raises the question of whether a royalty owner mount a claim that the operator, through its affiliates, charged more than a reasonable amount for post-wellhead costs (such as expenses to gather, compress, treat, process, and market oil and gas).

Plaintiff's perspective

The traits that a good royalty-owner claim would have include these: 

• Large production from the lease area during the (statute of limitations) look-back period;

• Benchmark comparisons that show substantially lower charges for the post-production services that the operator’s affiliates provide and charge for;

• Evidence of a large gap between the affiliates’ costs of providing post-production services and the charges to the operator; and

• High market prices during the look-back period.

Final installment

The series for the 66th Annual Oil & Gas Law Institute comes to an end next week, when we'll address landowners' claims for damage to the surface.

Your comment

The hottest oil & gas claims series reflects industry conditions as of early 2015. Has the passage of three months affected the sorts of claims that industry participants have made? With the price of West Texas Intermediate rising from around $48 per barrel to almost $57, has pressure on contracts eased? What effects have resulted from the ongoing slump in natural gas prices, which have fallen below $2.55 per mmBtu from over $2.80 in January 2015?

Let us hear your thoughts.

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The Supreme Court of Texas granted review in Hyder and heard argument in the case on March 24, 2015. See Chesapeake Exploration L.L.C. v. Hyder, No. 14-0302 (Tex.). You can see video of the argument here.

Hottest Oil & Gas Claims, Part 5: Exculpatory Clauses

Blawgletter's seven-part exposition of the hottest oil and gas claims for 2015 (which we co-wrote for the Institute for Energy Law's 66th Oil & Gas Law Conference in Houston) moves into an area that plaintiffs hate and defendants love -- the exculpatory clause. Specifically, the ones that the American Association of Petroleum Landmen put in the AAPL's standard-form joint operating agreements, or JOAs.

Changes in the JOA from the 1977 and 1982 forms to the 1989 version present the question of whether the exculpatory clause excuses breach of contract and, if so, which kinds of breach. We'll address that before turning to what fact patterns make avoiding the preclusive effect of JOA exculpatory clauses more likely.

Legal Backdrop

Since 1977, the dominant model for JOAs has excused the operator from “losses sustained or liabilities incurred” unless they “result from gross negligence or willful misconduct.”¹ But what if the operator broke a  promise in the JOA itself? Does the non-operator still have to show gross negligence or willful misconduct to win a claim of breach?

The answer may depend on which version of the model JOA applies. Under the 1989 form, the Supreme Court of Texas held in Reeder v. Wood County Energy, LLC, 395 S.W.3d 789 (Tex. 2012), a party to a JOA does have to prove a higher degree of fault even for a simple contract claim.² The Court pointed out that 1977 and 1982 models spoke of “operations” by the operator but that the 1989 form dealt, in contrast, with “activities under this agreement”.³ As the Court explained:

Reading the clause as written, we conclude that the model form transformation is significant, as the change in language broadens the clause’s protection of operators. . . . The agreed standard exempts the operator from liability for its activities unless its liability-causing conduct is due to gross negligence or willful misconduct.

Id. at 795. The Court thus held that the clause barred Reeder’s liability for failing (negligently) to repair oil wells. Id. at 797.

The older clauses, on the other hand, do not apply to pure claims for breach of the JOA, the Tenth Circuit has held, contrary to a 1992 ruling by the Fifth Circuit. In ⁴Shell Rocky Mountain Production, LLC v. Ultra Resources, Inc., 415 F.3d 1158, 1171 (10^th Cir. 2005), the court declined to require gross negligence or willful misconduct for a claim that the operator mishandled “administrative and accounting duties”.⁵ A district court in Houston reached the same conclusion under Texas law, noting that Reeder had the effect of overruling a contrary Fifth Circuit decision. MDU Barnett Ltd. P’ship v. Chesapeake Expl. Ltd. P’ship, No. H-12-2528, 2014 WL 585740, at *1 & *7 (S. D. Tex. Feb. 14, 2014) (holding that 1982 exculpatory clause did not cover claims for breach of JOA and rejecting Stine v. Marathon Oil Co., 976 F.2d 254, 260-61 (5^th Cir. 1992), under Reeder).

Plaintiff perspective

In contrast to the other issues this paper addresses, the question of what effect a JOA exculpatory clause may have presents a challenge more for the plaintiff than for the defendant. What factors will aid a plaintiff whose defendant claims a contractual right to exculpation for wrong-doing less culpable than “gross negligence or willful misconduct”?

• Absence of contractual privity between the plaintiff and defendant under the JOA (e.g., the plaintiff or defendant did not become a party to the JOA and does not qualify as a third-party beneficiary);

• Applicability of a pre-1989 JOA form – and therefore a narrower exculpatory clause – to some or all of the damage-causing conduct (as a result, for instance, of conduct occurring at a time or place to which an older JOA form applies);

• For JOAs using the 1989 form, the source of injury to the plaintiff does not involve the operator’s “activities under this Agreement” or concern its role “as Operator”;

• For JOAs using the 1977 or 1982 form, the harm to the plaintiff does not relate to the operator’s “operations on the Contract Area” or its behavior “as Operator”; and

• Big damages.

Looking ahead, and back

We have two more topics to cover yet. For those who missed the first four parts, you can check them out here:

• Hottest Oil & Gas Claims, Part 1: Busting Leases

• Hottest Oil & Gas Claims, Part 2: New Drilling Technology

• Hottest Oil & Gas Claims, Part 3: What Counts as a Well?

• Hottest Oil & Gas Claims, Part 4: Flaring Gas

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¹ For a brief history of the Form 610 JOA since its advent in 1956, see “The 1989 JOA: Horizontal Modifications and Other Crucial Updates”, Oil and Gas Law Digest, Sept. 17, 2014 (available as of Jan. 21, 2015 at http://www.oilandgaslawdigest.com/newscaselawupdate/the-1989-joa-horizontal-modifications-and-other-crucial-updates/).

² The 1989 clause (with our emphasis) speaks of “activities” rather than only “operations”, as follows:

Operator shall conduct its activities under this agreement as a reasonably prudent operator, in a good and workmanlike manner, with due diligence and dispatch, in accordance with good oilfield practice, and in compliance with applicable law and regulation, but in no event shall it have any liability as Operator to the other parties for losses sustained or liabilities incurred except such as may result from gross negligence or willful misconduct.

³ The 1977 and 1982 clause provided as follows (with our emphasis):

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

⁴ The Fifth Circuit ruled that the 1977 and 1982 language applied to contract claims in Stine v. Marathon Oil Co., 976 F.2d 254, 260-61 (5th Cir. 1992) (applying Texas law). At least one court has noted the split between the Fifth and Tenth Circuits on the issue. See Forest Oil Corp. v. Union Oil Co. of Am., No. 3:05-cv-0078, 2006 WL 905345, at *3 (D. Alaska Apr. 7, 2006) (adopting Ultra Resources holding and rejecting Stine’s) (applying Alaska law).

⁵ The court cited its decision in Amoco Rocmount Co. v. Anschutz Corp., 7 F.3d 909, 923 (10^th Cir. 1993) (noting that clause may cover “tortious acts related to the performance of the contract” but did not apply to “actions taken deliberately and . . . in breach of the contract involving shifting costs between the contracting” working interest owners) (applying Colorado law).

 

Hottest Oil & Gas Claims, Part 4: Flaring Gas

Blawgletter offers the fourth installment in the seven-part series on the Hottest Oil & Gas Claims for 2015. This time, we address whether flaring gas qualifies as "use" on which the operator must pay royalties.

Legal backdrop

Royalty clauses typically require payment of royalty for oil and gas “produced from the Leased Premises and sold or used on or off the Leased Premises”. Chesapeake Expl., L.L.C. v. Hyder, 427 S.W.3d 472, 481 (Tex. App. – San Antonio 2014, pet. granted) (emphasis added).* A compensable “use” includes burning “gas for fuel or other operations”. Id. at 482.

In the Bakken shale area (and other “new” production areas that may lack gathering lines and other infrastructure), “the oil contains significant amounts of natural gas, and because of the geological manner in which the gas is commingled with oil in deposits, operators cannot produce the oil without releasing the gas simultaneously.” Kelly A. Williams and Joshua B. Cannon, Frontier Flaring: Science & Economics, Politics & Regulation – the Future of Flaring, 60 RMMLF-INST 5 at 3-4 (2014).** Does the need to produce gas in order to get oil to the surface make flaring the gas “use” of it for purposes of the royalty clause?

Claim economics

A viable claim for royalties arising from flaring of gas will likely include these traits:

• Physical necessity of extracting gas to produce oil from the formation;
• Loss of substantial quantities of gas through flaring;
• Absence of contractual, regulatory, or statutory language authorizing gas-flaring or restricting remedies; and
• High wellhead prices during the relevant look-back period (e.g., the length of the statute of limitations) and into the future.

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^* On January 30, 2015, the Supreme Court of Texas granted review in Hyder and set the appeal for argument on March 24, 2015. See Chesapeake Expl., L.L.C. v. Hyder, No. 14-302 (Tex. Jan. 30, 2015).

^** A flaring claim under a standard royalty clause may exist apart from other theories. North Dakota law, for instance, requires a producer that flares gas without an exemption to “pay royalties to royalty owners upon the value of the flared gas”, N.D.C.C. § 38-08-06.4, but the statute grants a right only to pursue relief before the North Dakota Industrial Commission, Hansen v. Hunt Oil Co., No. 1:14-cv-00021 (D.N.D. May 14, 2014), aff’d sub nom. Sorenson v. Burlington Resources Oil & Gas Co., L.P., No. 14-2407 (8^th Cir. Aug. 19, 2014).  The Louisiana Department of Natural Resources takes the view that “[r]oyalty must still be paid upon the flared/vented gas even with the  Dept. of Conservation approval for flaring.” Royalty Payments Frequently Asked Questions, La. Dept. of Nat. Resources (available at http://dnr.louisiana.gov/index.cfm?md=pagebuilder&tmp=home&pid=406) (as of Jan. 20, 2015). “Not surprisingly, the states have adopted differing approaches to assessing royalties on flared gas, and state policies fall somewhere on the continuum between charging royalties for all gas flared on state leases (e.g., Texas) and charging no royalties for gas legally flared (e.g., Utah).” Frontier Flaring, 60 RMMLF-INST at 10.

 

Frack Ban Doesn't Extend Lease, High Court Holds

Oil and gas and the Empire State

Does a state's years-long ban on the fracking of oil and gas wells extend the "primary" term of a lease until the ban ends, allowing the frackers who couldn't frack more time to come back and frack?

This week, the highest court of an important commercial state that seldom speaks on oil and gas industry matters took up the question. Although in 1882 New York became "the number one oil-producing state in the nation", New York courts have long since ceded authoritativeness in oil and gas matters to "out-of-state 'oil' jurisdictions". Beardslee v. Inflection Energy, LLC, No. 44 (N.Y. Mar. 31, 2015). But the Court of Appeals' thumping answer -- in favor of landowners and against what it called "energy companies" -- may open cracks in the fracking legal landscape across the U.S.

The leases

The dispute pitted owners of land in upstate New York (Tioga County) against those "energy companies", which had entered into oil and gas leases. Each of the leases contained "an identical term clause, also known as an habendum clause, which establishes the primary and definite period during which the energy companies may exercise the drilling rights granted by the leases." Beardslee, slip op. at 3 (footnote omitted).

The primary term ran out, per the lease language, after "FIVE (5) years from the date hereof". Id. A "secondary term" would kick in if, but only if, "said land is operated by Lessee in the production of oil or gas." Id. (emphasis added).

As the energy companies had drilled no wells on the landowners' property, the leases would have expired at the end of the primary term -- unless something somehow extended them.

Here comes the ban

Possible rescue arrived in the guise of the Governor of New York. As alarm about fracking rose, Governor Paterson put a state-wide hold on new permits for the fracking of wells pending a study of environmental and other effects. The lessees responded by sending the landowners notice that "New York's government action constituted a force majeure event under the leases, which purportedly extended the leases' terms." Id. at 5. They cited a clause that stated as follows:

If and when drilling . . . [is] delayed or interrupted . . . as a result of some order, rule, regulation, requisition or necessity of the government, or as the result of any other cause whatsoever beyond the control of the Lessee, the time of such delay or interruption shall not be counted against Lessee, anything in this lease to the contrary notwithstanding.

Id. at 6 (emphasis added).

The landowners sued the lessees in the Northern District of New York. They sought a judgment declaring that the leases "had expired by their own terms" when the primary terms ended with no drilling or production.  The district court granted summary judgment on the ground that the force majeure clause had "no effect on the habendum clause and the lease terms because the energy companies did not have an obligation to drill" during the primary term. Id. at 7. Citing gaps in the spotty fabric of oil and gas law in New York, the Second Circuit certified questions to the Court of Appeals for a definitive ruling. The Court accepted.

The decision

The outcome of the case depended on whether the force majeure clause did, or did not, apply to the "primary term" part of the habendum clause. The Court concluded that it did not, holding both that "the habendum clause is not expressly modified or enlarged by the force majeure clause" and that "the language in the force majeure provision does not supersede all other clauses in the leases, only those with which it is in conflict." Id. at 10 & 11.

The Court went on:

Moreover, the second sentence in the force majeure clause, which deals exclusively with governmental regulations, pertains only to the energy companies' express or implied covenants -- the lessee's obligations. As the energy companies made no express or implied covenants applicable to the primary term (other than to pay delay rentals, which are not at issue here), the force majeure clause must relate to only continuous drilling/production operations during the secondary term of the leases . . . . Furthermore, this latter sentence in the force majeure clause expressly indicates that the subject clause deals with lease termination, not lease expiration. The corresponding habendum clause provision is its secondary term, which also addresses the conditions under which the leases would terminate, whereas the primary term deals with lease expiration.

Id. at 11-12 (citation omitted). The force majeure clause, in other words, (a) did not apply to the lessee's obligations during the primary term (mainly to make bonus and rent payments but not to drill) and (b) did apply to the lessee's duties in the secondary term (after the commencement of drilling operations) but did not affect the outcome of the case because the leases never got beyond the primary term.

Upshot

The outcome generally spells bad news for oil and gas companies/lessees and good news for mineral owners/lessors. The former would like to hold onto potentially valuable leases, at little or no cost, until a fracking ban goes away and market prices go back up (having dropped by more than half in the case of oil since mid-2014 and 40 percent in the case of gas). The latter (landowners/lessors) would also prefer that prices rise again, but in the meantime they do not want the deadweight of a lease that produces no income or even any prospect of income while the lessees wait out the moratorium and the recession in market prices.

The tougher question will have to do with the effect of the fracking ban on leases in the secondary term, which does not start until production begins. The Court noted that the force majeure clause does address "the conditions under which the leases would terminate" -- the principal one involving failure to produce oil or gas in paying quantities. See "Hottest Oil & Gas Claims, Part 1: Busting Leases"; "Hottest Oil & Gas Claims, Part 2: New Drilling Technology".

Will the moratorium on fracking extend the secondary term of a lease in New York (and elsewhere)? In a time of sub-$50 a barrel of oil and $2.65 an Mcf for gas, is it worth fighting over? Under what circumstances?

What do you think?

Hottest Oil & Gas Claims, Part 3: What Counts as a Well?

Short-payment of royalties

Today we come to number three in Blawgletter's seven-part series on The Hottest Oil & Gas Claims for 2015, a paper that we presented at the 66th Annual Oil & Gas Conference in Houston. The third topic describes an area of legal uncertainty around a common oil and gas term -- "well" -- that no longer means a vertical hole in the ground.

Legal backdrop

New techniques for drilling, completion, and conducting other operations have the potential for disrupting oil and gas law. Horizontal drilling offers a case in point.

With conventional (vertical) drilling, “well” more or less refers to the wellhead, the place where the basically up-and-down wellbore connects to the surface. Drilling sideways, by contrast, typically taps into oil and gas deposits at multiple “takepoints” or “drain holes”.  See Springer Ranch, Ltd. v. Jones, 421 S.W.3d 273, 289 (Tex. App. – San Antonio 2013, no pet.) (holding that contract between adjoining landowners required apportionment of royalties according to “the ratio of the productive portions of the SR2 well on [the landowners’] respective properties to the entire length of the well, multiplied by the one-eighth lease royalty”); Browning Oil Co. v. Luecke, 38 S.W.3d 625 (Tex. App. – Austin 2000, pet. denied) (discussing allocation of production for purposes of computing royalty under lease that restricted pooling).

The definition of “well” may thus blur. What consequences follow?

Plaintiff's perspective 

A claim over what constitutes a “well” will likely (if not necessarily) involve a contractual relationship, as in the Springer Ranch case, between the plaintiff and the defendant. But that may not present much of a barrier; relationships like that abound in the oil and gas industry.

The standard-form joint operating agreement, for instance, uses “well” dozens of times but does not define it. Oil and gas leases also speak of “wells” but seldom give the word a specific meaning. Landowners or lessees whose tracts adjoin may also work out supplemental lease terms that allow pooling or enter into “production sharing agreements” that provide for horizontal wells crossing two or more tracts. See Clifton A. Squibb, The Age of Allocation: The End of Pooling as We Know It?, 45 Tex. Tech. L. Rev. 929, 940-41 (2013).

What would a good claim over what constitutes a well look like? The factual setting may include these features:

• Large production from and reserves in actual or potential communication with the horizontal wellbore (enhancing the value of any "well" that lies along the wellbore);

• Absence of contractual language defining “well” (making its meaning debatable);

• Contractual language that bars or limits pooling, entitles the mineral owner to royalties or other payments with respect to production from any “well”, or otherwise bases payments on the existence or number of "wells"; and

• High wellhead prices during the relevant look-back period (e.g., the length of the statute of limitations) and into the future.

Enough value?

Recall that the basic economics of pursuing claims (whether in a lawsuit, arbitration, or otherwise) will make some claims more viable than others. In general, the same traits that render a claim attractive to a contingent-fee lawyer will determine whether the potential gain supports risking your own resources (e.g., hourly fees plus expenses) in the endeavor -- a good liability case, provable damages, and a wrong-doer that can afford to pay.

The series

You can see the first two posts at Hottest Oil & Gas Claims, Part 1: Busting Leases and Hottest Oil & Gas Claims, Part 2: New Drilling Technology.

Next time, we'll look at whether flaring gas qualifies as "use" for purposes of computing royalties.

Hottest Oil & Gas Claims, Part 2: New Drilling Technology

Breach of covenant to administer lease -- must the operator use the latest drilling and completion technology?

Today Blawgletter continues our seven-part series from the 66th Annual Oil & Gas Law Conference in Houston with part 2. We turn now to an issue that had more resonance when high prices dominated and made a call for using high-cost drilling and completion techniques more plausible. Those claims may remain economic for look-back periods in spite of the recent drop in prices, but those who have them ought to act promptly to avoid statute of limitations concerns. 

Legal backdrop.

The lessee under an oil and gas lease has a duty “to manage and administer the lease”, and within that broad charge arises an obligation to “use successful modern methods of production and development.” Amoco Prod. Co. v. Alexander, 622 S.W.2d 563, 567 & n.1 (1981) (quoting R. Hemingway, The Law of Oil & Gas § 8.1 (1971)). These days, “successful modern methods of production and development” plainly include unconventional techniques like horizontal drilling and hydraulic fracturing.

Indeed, a half-century ago, the Oklahoma Supreme Court held that an operator’s failure to use “sandfracing” on wells in part of a 90-acre tract supported cancellation of the lease as to that acreage. Crocker v. Humble Oil & Refining Co., 419 P.2d 265, 274 (Okla. 1965) (“The defendant cannot offer any reasonable excuse in its failure to utilize the sandfracing process for further development of the cancelled portion of the lease.”).^* And “the tight, homogeneous nature of shale rock makes development somewhat like a mining operation” that involves far less geological risk than in other kinds of formations. David E. Pierce, Implied Covenant Law and Horizontal Development 7-14 (Nov. 9, 2012). An operator who fails to employ these and other potentially gainful methods may thus face a claim for breach of the implied covenant. But how far does the duty go?

Plaintiff perspective.

Because all implied lease covenants stem from a single duty of the lessee to act in good faith as a reasonable and prudent operator, Krug v. Helmerich & Payne, Inc., 320 P.3d 1012, 1022 (Okla. 2012) (quoting Owen L. Anderson, Oil and Gas Law and Taxation 402 (4^th ed. 2004)), the reasonably prudent operator test will determine whether or not a lessee’s failure to use unconventional methods complied with its duty to administer the lease.

A strong claim for failure to use the latest drilling technology would include some or all of these circumstances:

• Large reserves, preferably the proved and producing kind, within the lease area;
• Successful use of production-maximizing techniques in the relevant formation on or near the acreage;
• Pipeline access from the tract to points of sale; and
• High wellhead prices during the relevant look-back period (e.g., the length of the statute of limitations) and into the future.

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Next time we'll deal with whether each drain hole or takepoint in a horizontal well counts as a well and the consequences of a yes answer.

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^* The Supreme Court of Texas held in Coastal Oil & Gas Corp. v. Garza Energy Trust, 268 S.W.3d 1, 14 (2008), that a landowner cannot sue another landowner “for oil and gas drained by hydraulic fracturing that extends beyond lease lines” into the first landowner’s property. The ruling lowered the risks of, and therefore had the effect of encouraging, aggressive horizontal drilling campaigns.

Hottest Oil & Gas Claims, Part 1: Busting Leases

The collapse in oil prices since June 2014, and the significant drop in those for natural gas, have put tremendous pressures on relationships in the industry. The stresses -- between operators and non-operators, lessees and royalty owners, principals and contractors, investors and investees, among others -- make legal disputes both more likely and harder to forgive.

In light of the strains within the oil and gas industry, what sorts of claims can you expect to see in 2015? In this series -- which originated as a paper for the 66th Annual Oil & Gas Law Conference in Houston -- Blawgletter will offer the top seven answers.

We start with Busting leases – when does failing to produce in paying quantities entitle the lessor to kick the lessee out?

Why bust a lease

Let's start with the why -- what could prompt a party to a lease to want to bring it to an end. The answer generally has to do with the terms of the lease or with the parties' course of performance under it. The minerals owner -- the lessor -- will prefer a higher royalty rate (25 percent, say) over a lower one (12.5 percent, for instance) because the higher percentage means more money to her. The lessee, on the other hand, will want to pay as a smaller percentage. And all kinds of difficulties and breaches may make either party unhappy with the contractual relationship and therefore anxious to end it.

Legal backdrop 

The ability of a well to produce oil or gas “in paying quantities” generally will extend the lease until the quantities will no longer pay a profit, even a “small” one. Clifton v. Koontz, 160 Tex. 82, 325 S.W.2d 684, 690-91 (1959). “Whether there is a reasonable basis for the expectation of profitable returns from the well is the test.” Id. at 691; see, e.g., T.W. Phillips Gas & Oil Co. v. Jedlicka, 615 Pa. 199, 42 A.3d 261, 276 (2012) (applying Cliftonstandard). Several factors may enter into the analysis, including what constitutes “a reasonable period of time under the circumstances” for turning a profit. Clifton, 325 S.W.2d at 691.

The capacity to produce at a profit holds the lease whether or not profitable production in fact occurs, but the well must flow without additional equipment or repair. See, e.g., Anadarko Petroleum Corp. v. Thompson, 94 S.W.3d 550, 557-58 (Tex. 2002); Pack v. Santa Fe Minerals, 869 P.2d 323, 326-27 (Okla. 1994) (stating that “the lease in the case at bar cannot terminate under the terms of the habendum clause because the parties stipulated that the subject wells were at all times capable of producing in paying quantities”). Even if a well no longer pays but still produces some oil or gas, a second prong of the test may save the lease anyway. In that situation, the party seeking to end a lease must show also that a reasonably prudent operator would not have continued operations for the purpose of profit rather than mere speculation. EnerQuest Oil & Gas, LLC v. Plains Expl. & Prod. Co., 981 F. Supp. 2d 575, 597 (W.D. Tex. 2013) (citingCannon v. Sun-Key Oil Co., Inc., 117 S.W.3d 416, 421 (Tex. App. – Eastland 2003, pet. denied)). A total cessation of production may also permit termination of a lease. Cannon, 117 S.W.3d at 421-22.

Changes in market prices of course affect whether or not a well can produce in paying quantities. A large price rise may make low-producing wells capable of paying, while a plunge in price may turn profitable wells into losers. In the pricing climate of early 2015 – when crude oil prices in the U.S. had fallen from more than $100 per barrel (in June 2014) to less than $45 and gas had gone from over $4 per MMBtu (with a $6 spike in February 2014) to below $3 – some lessors and lessees who want to break leases may have a chance.

Claim economics

The basic economics of pursuing claims (whether in a lawsuit, arbitration, or otherwise) will make some claims more viable than others. In general, the same traits that render a claim attractive to a contingent-fee lawyer will determine whether the potential gain supports risking your own resources (e.g., hourly fees plus expenses) in the endeavor. On a lease-busting claim by a lessee for failure to produce in paying quantities, favorable characteristics will include these:

• Large non-producing reserves within the lease area (making the future bright for whoever controls the minerals);
• Successful use of production-maximizing techniques in the relevant formation on or near the acreage (tending to enhance the revenue stream);
• Demand for but failure of the operator to employ the successful techniques or perform repairs, including as a result of financial distress (putting the equities on the lessor's side);
• Unfavorable lease terms from the lessor’s perspective (e.g., below-market royalty rate);
• Pipeline access from the tract to points of sale (improving the ability to obtain market prices); and
• Low wellhead prices due to temporary oversupply (possibly implying a speculative motive on the part of the operator for holding the lease).

These features suggest a situation in which an operator may have sacrificed the lessee’s interest in maximizing current production (and therefore royalties) at the altar of saving money during an industry downturn. They also indicate a potentially large upside for the mineral owner, who without the existing lease could enter into a more favorable one or develop the minerals herself.

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Next in the series -- the obligation of operators to use the latest technology for drilling and completing wells.