Oil and Gas Lawyer Blog

Published on: October 29, 2019

Arkansas Case On Post-Production Costs

A U.S. District Court in Arkansas decided a case in 2016 that a client sent me, Whisenhunt Investments, LLC v. Exxon Mobil Corp., 2016 WL 7494266, No. 4:13cv00656 JM, Eastern District of Arkansas, Western Division, raising an interesting issue on post-production costs.

Arkansas has forced pooling. The forced pooling statute provides that

One-eighth (1/8) of all gas sold … from any such unit shall be considered royalty gas, and the net proceeds received from the sale thereof shall be distributed to the owners of the marketable title in and to the leasehold royalty and royalty …. Payment of one-eighth (1/8) of the revenue realized from the sale of gas as provided in this section shall fully discharge all obligations of the operator and other working interest owners with respect to the payment of one-eighth (1/8) leasehold royalty or royalty … Nothing contained in this section shall affect the obligations of working interest owners with respect to the payment of royalties, overriding royalties, production payments, or similar interests in excess of the one-eighth (1/8) royalty required to be distributed under this section.

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Published on: October 16, 2019

Study Concludes Some Earthquakes in West Texas Likely Caused by Fracing

By John McFarland

A study released by TexNet concludes that “some earthquakes in west Texas are more likely due to hydraulic-fracturing than salt-water disposal.”

TexNet is a seismic monitoring program run by the University of Texas and funded by the legislature as a result of unusual earthquake activity in several areas of Texas where oil and gas drilling has spiked in the last few years. Previous studies had linked earthquakes to saltwater injection, resulting in increased regulation of water injection wells by the Texas Railroad Commission.

This year TexNet has detected 209 earthquakes across Texas, with the strongest at 3.8 magnitude, near Snyder on October 1, already surpassing the total quakes in 2018 of 192.

Published on: October 14, 2019

When is a contract provision a liquidated damages clause, and when is a liquidated damages clause an unenforceable penalty?

By John McFarland

Two recent court of appeals cases address the enforceability of liquidated damages clauses: TEC Olmos, LLC v. ConocoPhillips Company, and Fairfield Industries v. EP Energy E&P Company. The Texas Supreme Court requested the parties in TEC Olmos to file briefs on the merits but recently denied review. In EP Energy, the court denied EP’s petition for review, but EP has filed a forceful motion for rehearing and the court has requested a response. In the meantime, the case has been stayed because of EP Energy’s bankruptcy.

A liquidated damages clause is a provision in a contract specifying a dollar amount (“liquidated damages”) to be paid by a party if the party breaches the contract. Such clauses are common in all types of contracts, particularly in the oil and gas industry. If a contractor promises to complete construction of a building by an agreed date and fails to do so, the contract may provide for a payment of an agreed amount for each day completion is delayed. If a party promises to drill a well in a lease or farmout agreement, the parties may agree that, if the well is not drilled, the defaulting party will pay an agreed amount as damages. If a lessee promises to keep a ranch gate closed, the parties may agree on a liquidated damages amount for each time the lessee leaves the gate open.

Texas courts have imposed judicial restraints on the enforceability of liquidated damages clauses. In 2014, the Texas Supreme Court summarized these restraints in FPL Energy v. TXU Portfolio Management Co.: Continue reading →

Published on: October 7, 2019

Cimarex v. Anadarko – Is a lease held by production if the lessee does not participate in the well and there is no operating agreement?

By John McFarland

Last March the El Paso Court of Appeals decided Cimarex Energy v. Anadarko Petroleum, No. 08-16-00353-CV. The facts are these:

Cimarex leased a 1/6th interest in 440 acres in Ward County. Anadarko leased the remaining 5/6ths. Cimarex asked Anadarko to let Cimarex participate in wells on the leases under a joint operating agreement, but Anadarko refused. Anadarko drilled two wells, carrying Cimarex as a non-consenting co-tenant. Cimarex sued for an accounting. The parties settled, Anadarko agreeing to an accounting and to pay Cimarex its share of net profits from the wells. Cimarex paid its royalty owner for its share of production “according to the terms of its lease, dating back to the date of first production.”

But at the end of the primary term of the Cimarex lease – December 21, 2014 – Anadarko stopped paying Cimarex, claiming its lease had expired. Anadarko took a new lease from Cimarex’s lessor. Cimarex sued Anadarko for breach of the settlement agreement. The trial court held that Cimarex’s lease had expired and dismissed its suit. On appeal, the Court of Appeals affirmed. Cimarex has now filed a petition for review in the Supreme Court.

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Published on: October 2, 2019

Produced Water Supersystems

By John McFarland

H2O Midstream recently announced its acquisition of “produced water infrastructure” from Sabalo Energy in Howard County – 37 miles of pipeline, nine salt water disposal wells, four Ellenburger salt water disposal well permits, and other assets. This brings H2O Midstream’s produced water network up to a combined “supersystem” for handling produced water of up to 435,000 barrels per day, 190 total miles of pipeline, and 40,000 barrels per day of recycling capacity. The deal includes a 15-year “acreage dedication” of Sabalo’s leases to provide produced water gathering, disposal and recycling services to Sabalo. H2O Midstream is funded by EIV Capital and its institutional partners.

H2O is one of several companies trying to create supersystem produced-water handling systems in the Permian and the Eagle Ford. Like H2O’s deal with Sabalo, these acquisitions typically involve transferring produced water infrastructure assets to the company and dedication of the seller’s leases to the system – a commitment to pay an agreed amount to the company for produced water disposal services.

From landowners’ point of view, this development presents some interesting questions and challenges.

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Published on: September 18, 2019

Texas Supreme Court Opines on Consent-to-Assign Provision

By John McFarland

In 2017 I wrote about consent-to-assign provisions in oil and gas leases, and I commented on a case decided by the Tyler Court of Appeals that year addressing such provisions, Carrizo Oil & Gas v. Barrow-Shaver Resources, 2017 WL 412892. In December last year, the Texas Supreme Court wrote on that case, No. 17-0332, Barrow-Shaver Resources v. Carrizo Oil & Gas. The court split 5 to 4. Although the consent-to-assign provision in the case was in a farmout agreement, it sheds light on how such provisions in oil and gas leases would be treated by the courts.

The facts of the case are these: Carrizo owned an interest in an oil and gas lease covering 22,000 acres in north-central Texas. It entered into a farmout agreement with Barrow-Shaver under which Barrow-Shaver was granted the right to drill wells and earn assignments of the lease, with Carrizo retaining an overriding royalty. The farmout agreement contained the following provision:

The rights provided to [Barrow-Shaver] under this Letter Agreement may not be assigned, subleased or otherwise transferred in whole or in part, without the express written consent of Carrizo.

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Published on: September 10, 2019

Chesapeake v. Bell – Another Decision Construing an Express Drainage Offset Clause

By John McFarland

Last March the San Antonio Court of Appeals handed down its decision in Bell v. Chesapeake Energy, No. 04-18-00129-CV. Chesapeake has asked the Texas Supreme Court to review the case. The facts bear a resemblance to Murphy v. Adams, decided by the Supreme Court last year. Both involve construction of an express offset clause in an oil and gas lease.

A typical express offset clause provides that, if a well is drilled within a certain distance from the lease boundary, the lessee must either drill an offset well or pay compensatory royalty based on the production from the adjacent well. The lessor is not required to show that the adjacent well is actually draining the leased premises. In Murphy v. Adams, the issue was what constitutes an “offset well.” The Supreme Court held (in a 5 to 4 decision) that, in the context of horizontal drilling in the Eagle Ford formation, any well drilled on the leased premises, regardless of its location, may satisfy the lessee’s obligation to drill an offset well.

In Bell v. Chesapeake, the issue is what amount of compensatory royalty Chesapeake must pay. The wells drilled on tracts adjacent to Chesapeake’s leases were not drilled parallel to the lease line, but a portion of the adjacent wells’ horizontal wellbore was within the minimum distance from the lease line to trigger the offset-well obligation. The lessors contend that Chesapeake must pay compensatory royalty based on 100% of the production from the adjacent well. Chesapeake argues that it should have to pay compensatory royalty only on the portion of the adjacent well’s production coming from perforations or “take points” that are within the minimum distance from the lease line specified in the lease.

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Published on: August 30, 2019

Unit-Line Allocation Wells

By John McFarland

We’ve recently seen several requests for royalty owners to sign a production sharing agreement for a unit-line or lease-line allocation well. Such a well would be drilled along the boundary of two existing leases or pooled units. So, unlike most allocation wells, production can’t be allocated based on the portion of the well’s productive lateral length on each lease or pooled unit. Instead, the production sharing agreement may propose to allocate production between the two leases or units in one of two ways – 50-50 to each unit, or based on acreage.

Allocating production between the two leases or units for such a well presents at least two problems: first, the actual drilled wellbore cannot actually be drilled exactly down the boundary line between the two leases or units. The wellbore will deviate, sometimes significantly, from a straight line. Second, the well may not actually be drilled down the unit line, but might be on one side or the other of the unit line, but too close to the unit line to avoid drainage or a special Rule 37 spacing permit. In addition, the wellbore might extend beyond the boundary into another lease or unit. Wellbores are getting longer and longer.

So I think the better practice is to allocate production for a unit-line allocation well based on acreage. In effect, it is the same allocation that would result if a pooled unit were created for the well.

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Published on: August 26, 2019

Energy – the Big Picture

By John McFarland

I recently heard a presentation by Dr. Scott Tinker, head of the Bureau of Economic Geology at the University of Texas. He is the founder of the Switch Energy Alliance, about which I’ve written before. Switch Energy Alliance is “a 501(c)(3) dedicated to inspiring an energy-educated future that is objective, nonpartisan, and sensible.” It produced a documentary called Switch, and is working on another called Switch On. Switch can be viewed and downloaded on SEA’s website.

A premise of Dr. Tinker’s work is that rational decisions about energy and CO2 emissions and global warming can’t be made without understanding the role of energy in the world and the challenges facing efforts to wean ourselves of fossil fuels.

Here are just a few of the powerpoint slides from Dr. Tinker’s presentation (click on image to enlarge):

Sources and uses of energy in the US. Note the huge amount of “rejected energy” – wasted energy:

Global sources of energy:

A look at electricity. Electricity generation by region (note Asia Pacific): Continue reading →

Published on: August 14, 2019

North Dakota Supreme Court Decides for Royalty Owner on Post-Production Costs

By John McFarland

In a short opinion, the Supreme Court of North Dakota decided a case brought by Newfield Exploration against the North Dakota Board of University and School Lands to determine how royalties on gas should be calculated under the State’s leases to Newfield. The case illustrates how post-production costs can sometimes be hidden in “percentage-of-proceeds” or “POP” contracts for the sale of gas. Newfield Exploration Company v. State of North Dakota, No. 2019088, 2019 WL 3024639, decided 7/11/2019.

Newfield sold its gas to Oneok. The opinion describes this contract as follows:

Title to the gas passes to Oneok when it receives the gas from Newfield, but payment to Newfield is delayed until after Oneok processes the gas into a marketable form and sells the marketable gas. The price Oneok pays to Newfield for the gas is calculated based on 70-80% of the amount received by Oneok when Oneok sells the marketable gas. The 20-30% reduction of the price for which the marketable gas is sold accounts for Oneok’s cost to process the gas into a marketable form and profit.

The lease royalty clauses provided:

Lessee agrees to pay lessor the royalty on any gas, produced and marketed, based on gross production or the market value thereof, at the option of the lessor, such value to be based on gross proceeds of sale where such sale constitutes and arm’s length transaction.

All royalties on … gas … shall be payable on an amount equal to the full value of all consideration for such products in whatever form or forms, which directly or indirectly compensates, credits, or benefits lessee. Continue reading →