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Oil prices are much in the news, especially in Texas. As oil prices continue to decline, the effect on Texas’ economy is settling in. And with all the talk of oil prices, OPEC is again the focus of much news coverage. What will OPEC do? How much does OPEC really control oil prices? What effect are the low prices having in the OPEC countries themselves?

Here are some interesting websites about OPEC:

OPEC’s own website. It publishes a monthly report, available online, in English.

According to OPEC, its members have 81% of the world’s oil reserves (click to enlarge):


This site, Peak Oil Barrel, with charts of historic production by all OPEC countries.

Note how Saudi Arabia has increased its production, and the increased production from Iraq:


Here is a graph from the Energy Information Administration article, “What Drives Crude Oil Prices?”

EIA on Crude Prices

An article from Rigzone predicting that OPEC will hold the line on prices.

An article from Fortune predicting that oil prices could go to $20/bbl next year.

An article from Bloomberg speculating on why Indonesia, which consumes twice as much oil as it produces, has rejoined OPEC.

It seems pretty clear that, as long as Saudi Arabia wants to hold down oil prices, it can do so.



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Oklahoma oil and gas regulators are scrambling to deal with increasing seismic activity. The Oklahoma Corporation Commission ordered six wastewater disposal wells shut down after the state’s strongest earthquake since 2011, a magnitude-4.7 quake near Cherokee, close to the Kansas border. The quake was felt from Dallas to Kansas City. A second 4.0- quake was centered near Crescent, close to Oklahoma City. There were a total of eight earthquakes. The Commission also ordered the owners of 23 other wells to reduce injection rates by 25 to 50 percent.

Oklahoma regulators have now conceded that earthquakes there are caused by disposal wells, after much earlier debate. Oklahoma is now the most seismically active area of the country. The state has had more than 790 quakes of magnitude 3 or greater this year, compared to 585 last year.

Cherokee is in Alfalfa County, where 225 million barrels of waste water was disposed of last year, more than 10 times what was injected in 2010. It sits over the Mississippi Lime, an oil play that requires disposal of 10 barrels of water for every barrel of oil produced.

Meanwhile in Texas, the Texas Railroad Commission has yet to concede that injection wells cause seismic activity. After scientists at Southern Methodist University published a study earlier this year connecting earthquakes near Azle, Texas to two injection wells in the vicinity, the RRC held hearings to determine whether those wells, operated by XTO and Enervest, should be shut in or restricted. After the hearings, the RRC concluded that there was not sufficient evidence to connect the quakes to the injection wells and declined to modify the injection well permits. Separately, a study group formed as a result of a law passed by the Texas legislature last year to investigate quakes in Texas should have its report ready by the end of this year. The study is being led by the UT Bureau of Economic Geology in collaboration with other Texas universities.

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Three amicus briefs have been filed in support of the Hyders, opposing Chesapeake’s motion for rehearing of the Texas Supreme Court’s decision in Chesapeake v. Hyder.

An amicus brief was filed by the City of Fort Worth and others who have filed suits against Chesapeake and Total to recover additional royalties on production in the Barnett Shale area:  City of Fort Worth Amicus Brief

An amicus brief was filed by a group of royalty owners represented by Dan McDonald, a Fort Worth attorney who has filed 430 separate suits against Chesapeake, representing more than 20,900 royalty owners in Johnson and Tarrant Counties: Barnett Shale Royalty Owners Amicus Brief

Our firm, on behalf of Texas Land & Mineral Owners’ Association and the National Association of Royalty Owners-Texas, filed an amicus brief supporting the Hyders: TLMA and NARO Texas Amicus Brief

Chesapeake lost its appeal to the Texas Supreme Court in a 5-4 decision and has asked the Texas Supreme Court to reconsider its decision. Amicus briefs supporting Chesapeake’s motion for rehearing have been filed by the Texas Independent Producers and Royalty Owners’ Association (TIPRO), the Texas Oil & Gas Association (TXOGA), Sandridge Exploration & Production, BP America, Devon Energy, EOG Resources, EXCO Resources, Shell Western E&P, Trinity River Energy, Unit Corp. and XTO Energy.

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From Fuelfix:

New federal data shows that the Energy Department expects drillers in the Permian Basin to push oil production in the shale play above 2 million barrels per day for the first time ever this November.

The U.S. Energy Information Administration’s monthly Drilling Productivity Report released Monday, which covers seven of the biggest shale plays in the country, projects production in the Permian to jump by 17,000 bpd this month. That increase would bring the play above the 2 million bpd mark. In December, the EIA expects the play to grow again by 11,000 bpd.

But the Permian is one of the outliers — the only other play expected to grow over the next two months is the Utica in the Appalachian region. Combined with the other five plays — the Eagle Ford, Bakken, Haynesville, Marcellus and Niobrara plays — oil output overall is projected to fall to 4.95 million bpd the end of the year. That would be a fall of nearly 560,000 bpd from an April 2015 peak of 5.51 million bpd.

The Eagle Ford in South Texas has had the biggest impact on overall U.S. production growth. The EIA projects output in the Eagle Ford to fall 436,000 bpd by December from a peak of 1.71 million bpd in March.

(click to enlarge)



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These two graphics from the Energy Information Administration (click to enlarge):

The first shows increased re-fracking of existing wells, and reduction in time needed to drill a horizontal well:



The second shows how production has held up, despite decreased drilling activity:

rigs vs. crude production

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From the Energy Information Administration:

The General Dynamics shipyard in San Diego delivered the world’s first liquefied natural gas (LNG) powered containership to TOTE Maritime on October 16. The 764-foot long Isla Bella is the first of the Marlin class, a new class of container ship built in the United States, making it Jones Act-qualified for shipments between U.S. ports. The ship was built by the National Steel and Shipbuilding Company, a division of General Dynamics.

Tote Maritmime Container Ship

(Click to enlarge)

Delivered nearly two months ahead of schedule, the Isla Bella will operate out of Jacksonville, Florida, providing service to and from San Juan, Puerto Rico. The second ship of the class, the Perla del Caribe, will be delivered in early 2016 and will service the same trade route. These ships join a small group of LNG-powered ships, which currently number fewer than 100, excluding LNG tankers, according to data from DNV GL Maritime. They are the first in the largest category of vessels–container ships, numbering in the tens-of-thousands–to be built with dual-fuel propulsion intent on employing LNG as the primary fuel.

Continue reading →

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Recent earthquakes near Cushing, Oklahoma have caused a seismic shift in the state’s response to induced quakes in that state. The reason – Cushing is a major hub in the U.S. for storage and shipments of crude. Below is a snapshot of some of the giant storage tanks just outside the town (click to enlarge):


Some of these tanks are large enough to hold a Boeing 747. Cushing’s storage can hold more than 10 million barrels of oil; it is the largest commercial storage depot in the U.S.

A flurry of quakes have recently hit near Cushing. On October 10, a quake measuring 4.5 on the Richter scale hit about three miles from the town.  Scientists have linked increased seismic activity in Oklahoma to increased waste water injection.  3.3 billion barrels of waste water were injected under Oklahoma from 2011 through 2013.

The Oklahoma Corporation Commission, which regulates oil and gas in the state, was originally skeptical of any connection between waste water injection wells and induced quakes. But Oklahoma has now become the most seismically active state in the U.S., surpassing California, and state regulators have begun to take action.

Last month the OCC ordered injection wells within three miles of Cushing to shut down and wells within six miles to reduce their volume injected by 25 percent. And it has put all operators of injection wells within ten miles of Cushing on notice that they may be next.

Recent Bloomberg article on Oklahoma quakes here.

The U.S. Geological Survey recently issued a report concluding that the rise in quakes in Oklahoma is likely the result of water injection. Article here.

Recent quakes in Karnes and Atascosa Counties in Texas, article here. The Texas Railroad Commission recently held hearings on whether two injection wells in North Texas were the cause of quakes in the Barnett Shale.

The Oklahoma Supreme Court recently reinstated a suit by Jennifer Lin Cooper against waste injection companies for personal injuries she says were caused by induced earthquakes.

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The Texas Supreme Court asked the Hyders to respond to Chesapeake’s motion for rehearing in Chesapeake v. Hyder, after the court’s recent 5-4 decision in favor of the Hyders. Several amicus briefs (“friend of the court” briefs by entities not parties to the case) were filed in support of Chesapeake’s motion for rehearing. Exploration companies are clearly unhappy with language in Chief Justice Hecht’s majority opinion and asking the court to modify its language. The amicus briefs made the San Antonio Business Journal’s “Eagle Ford Shale Insight” feature.

I’ve written about this case before, and our firm filed an amicus brief in the case before the court issued its opinions, on behalf of Texas Land & Mineral Owners’ Association and the National Association of Royalty Owners-Texas.

So far, on rehearing, the following parties have joined in amicus briefs criticizing the court’s majority opinion:

  • Texas Oil & Gas Association
  • Texas Independent Producers and Royalty Owners Association
  • BP America Production Co.
  • Devon Energy Production Co. LP
  • EOG Resources Inc
  • EXCO Resources Inc
  • Shell Western E&P Inc
  • Trinity River Energy LLC
  • Unit Corp.
  • XTO Energy Inc
  • SandRidge Exploration and Production LLC

The Texas General Land Office, joined by Longfellow Ranch LP and Wesley Ranch Minerals, LP have filed an amicus brief supporting the court’s opinion. The GLO and SandRidge are engaged in a separate suit that concerns a lease provision in the Texas Relinquishment Act lease form and Sandridge is concerned that the court’s opinion could impact its case, prompting its interest in Hyder.

The issue in Hyder is the meaning of a clause that grants the Hyders an overriding royalty on horizontal wells drilled on adjacent leases from locations located on the Hyder property. The lease provision granting the overriding royalty calls for “a perpetual, cost-free (except only its portion of production taxes) overriding royalty of five percent (5%) of gross production obtained” from wells bottomed under neighbors’ land.” The parties dispute whether, in paying the Hyders this overriding royalty, Chesapeake can deduct post-production costs. The court held that it cannot. “Cost-free” includes post-production costs, according to the majority opinion.

One might think it curious that Texas Independent Producers and Royalty Owners Association (TIPRO) would file an amicus brief supporting Chesapeake’s reading of the lease. How can an organization purporting to represent royalty owners advocate a position detrimental to their interests? The San Antonio Business Journal quotes TIPRO’s President Ed Longanecker’s press release on its support of Chesapeake:

TIPRO believes the Court’s erroneous interpretation of the overriding royalty interest (“ORRI”) at issue will affect thousands of ORRIs in the state of Texas, many of which have been in existence for decades. If allowed to stand, the ruling that the ORRI prohibits the deduction of post-production costs will result in substantial unintended windfalls for ORRI owners. It may also call into question the commercial viability of marginal wells, leading to the possible plugging of wells across the state and thus less production and royalty revenue.

One might think that, if an oil company agreed to pay a “cost-free” overriding royalty, that payment – free of post-production costs – would not constitute an “unintended windfall” to the royalty owner. Perhaps TIPRO should reconsider its name.

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I recently wrote about two appellate opinions dealing with retained acreage clauses in oil and gas leases. A retained acreage clause requires the lessee to release acreage not assigned to a producing well at the end of the primary term, or at the end of a continuous drilling program conducted after the primary term. One commentator has said that the purpose of a retained acreage clause is to “replace the lessor’s need to utilize the implied covenant of reasonable development as the sole means to see that its  acreage is fully developed.”  Bruce M. Kramer, Oil and Gas Leases and Pooling: a Look Back and a Peek Ahead, 45 Tex. Tech L. Rev. 877, 881 (2013).

A retained acreage clause should be included in any oil and gas lease that covers a significant amount of acreage – more than 100-200 acres. Below is a retained acreage clause, from the TLMA lease form. TLMA is the Texas Land and Mineral Owners Association. I prepared the lease form, and TLMA provides it to all of its members:

Upon expiration of the Primary Term, or upon cessation of “Continuous Drilling Operations” (as hereinafter defined), whichever is later, this Lease shall terminate as to all the lands and depths then covered thereby except lands and depths then designated by Lessee, in accordance with the requirements of this Paragraph, to be within a “Production Unit” (as hereinafter defined) assigned to each well then producing in paying quantities on the Leased Premises or lands properly pooled therewith.

  • Continuous Drilling Operations. Lessee shall be considered to be engaged in “Continuous Drilling Operations” at the end of the Primary Term for purposes of this Paragraph if Lessee is engaged in Drilling Operations on the Leased Premises or lands pooled therewith at the end of the Primary Term, or if Lessee has completed or abandoned a well within ninety (90) days prior to the end of the Primary Term; and Lessee shall be deemed to be engaged in Continuous Drilling Operations for as long thereafter as Lessee conducts Drilling Operations on the Leased Premises or lands pooled therewith with due diligence and with intervals of not more than ninety (90) days between the date of completion or abandonment of one well and the date of commencement of actual drilling of the next well. If Lessee is engaged in Continuous Drilling Operations at the end of the Primary Term, then such Continuous Drilling Operations will be deemed to have ceased when Lessee fails to commence actual drilling of a well within ninety (90) days after the completion or abandonment of the preceding well, and this Lease shall thereupon terminate except as to Production Units assigned to wells then producing in paying quantities from the Leased Premises or lands pooled therewith, as provided in this Paragraph.
  • Production Unit. A “Production Unit,” for purposes of this Lease, is a designated area of land around a well having the minimum amount of acreage necessary to obtain a regular permit for the drilling of a well, as required by the field rules of the Railroad Commission of Texas applicable to the field from which such well is producing. Each Production Unit shall be limited in depth to one hundred (100) feet below the deepest perforation in any well on such Production Unit.
  • Maximum Sizes of Production Units. Notwithstanding any density rules applicable to any well, however, no Production Unit assigned to any well shall exceed the following sizes:
    • If the well is classified as a vertical oil well under the Rules and Regulations of the Railroad Commission then in effect, the maximum size of the Production Unit shall be __________ acres [if the well is producing in whole or in part from formations less than __________________ feet beneath the surface, and ___________ acres if the well is producing from formations located wholly below ___________ feet beneath the surface].
    • If the well is classified as a vertical gas well under the Rules and Regulations of the Railroad Commission of Texas then in effect, the maximum size of the Production Unit shall be __________ acres [if the well is producing in whole or in part from formations less than __________________ feet beneath the surface, and ___________ acres if the well is producing from formations located wholly below ___________ feet beneath the surface].
    • If the well is classified as a horizontal well (whether oil or gas) under the Rules and Regulations of the Railroad Commission then in effect, then the maximum size of the Production Unit shall be determined by the following formula: A = 40 + .____ X L, where A = the area (in acres) of the Production Unit and L = the length (in feet) of the horizontal lateral component of the drainhole of the well, from the first take point to the last take point.

If at the time Lessee must designate Production Units in accordance with this Paragraph there is a well or wells on the Leased Premises producing from a field for which no field rules have yet been adopted, then Lessee shall designate a Production Unit complying with the size requirements listed in (i), (ii), or (iii) above, as applicable, and Lessee shall, if and when requested by Lessor, proceed with diligence to apply for field rules for such field; and when such field rules are adopted by the Commission, if such field rules provide for proration units smaller than the maximum Production Unit sizes provided for above, Lessee shall designate a Production Unit for such well complying with such field rules, and shall release the lands no longer included in the Production Unit for such well or wells; provided, however, that Lessee may maintain this Lease as to such excluded lands if Lessee commences Drilling Operations on such lands within sixty (60) days from the final adoption of such field rules, and continues such Drilling Operations with no cessation of more than sixty (60) consecutive days until production is established, in which event Lessee shall designate Production Units and this Lease shall remain in force as to the units so designated as provided in this Paragraph.

  • Configuration of Production Units. Insofar as possible, taking into consideration the productive limits of the producing interval and the configuration of the Leased Premises, the lands included within the Production Unit for a well shall be in the form of a square or rectangle. Every effort shall be made in designating Production Units to avoid releasing small or irregularly shaped portions of the Leased Premises, or portions not contiguous with other released portions. Acreage assigned to wells producing from different zones may overlap, and shall overlap when necessary to comply with the requirements of this Paragraph. If a well is producing from more than one formation, its Production Unit’s size and configuration shall conform to the Railroad Commission rules applicable to the well which provide the largest Production Unit (subject to the size limitations stated above). If all or a portion of the Leased Premises is included in a pooled unit, then for purposes of this Paragraph all the lands within the pooled unit shall be considered a part of the Leased Premises, and the size and configuration of the pooled unit must conform to the requirements of this Paragraph for a Production Unit.
  • Maintenance of Lease after Designation of Production Units. As to acreage and depths which are included within a Production Unit, this Lease may be held in force after the termination of the Primary Term or cessation of Continuous Drilling Operations, whichever is later, only by Operations conducted (as provided in this Lease) on such Production Unit (or lands pooled therewith), with no cessation of operations of more than sixty (60) consecutive days; and Operations conducted on one Production Unit (or lands pooled therewith) will not maintain this Lease in force as to any other acreage included within any other Production Unit, but such production or Operations will maintain this Lease only as to the acreage within the Production Unit or Production Units upon which such Operations are being conducted.
  • Recordable Release. Upon termination of this Lease as to any portion of the Leased Premises, Lessee shall deliver to Lessor a plat showing the designated Production Units around each well (and designating the depth) and a partial release designating such Production Units in compliance with the requirements of this Paragraph, suitable for recording. Such release shall include a release of the depths below 100 feet below the deepest perforation of the well with paying production in each Production Unit, respectively.

Some comments:

The term “production unit” is used to distinguish it from pooled units and proration units. The three are quite different.

The time between completion and commencement of wells for “continuous drilling operations” is negotiable. Definitions for commencement of Drilling Operations and Completion of a well should be provided.

The definition of a Production Unit includes a depth limitation. How that depth limitation is defined may be the subject of negotiation. For example, the lease could require release of depths above and below the producing formation in each Production Unit.

The maximum size of Production Units is negotiated and may be different for oil and gas wells, different depending on depth of completion, and different for horizontal wells. Note that the size of Production Units for horizontal wells is the same for wells classified as oil or gas wells.

The maximum size of a Production Unit for a horizontal well is based on a formula: 40 + ____ X L, where L is the length of the lateral, from first take point to last take point. A take point is a perforation in the casing from which oil and gas is being produced. If the parties agree that the Lessee may have a 160-acre production unit for a well with a lateral length of 5,000 feet, then the formula is 40 + .024 X L.  To derive the number that goes in the blank based on the desired size of the Production Unit, use the formula (A – 40)/L, where A = the desired size of the production unit for a well with a lateral length of L. For example, if the parties agree that a well with a 5,000-foot lateral will have a maximum Production Unit size of 320 acres, then the fraction to use in the formula is (320-40)/5000 = .056. Using this formula, if the well has, say, a 7,000-foot lateral, then the Production Unit for the well can be up to 40 + .056 X 7,000 = 432 acres.

After continuous drilling operations have ceased, each Production Unit in effect becomes a separate lease. Production from one Production Unit will not keep the lease in force as to any other Production Unit.

There are many other variations on retained acreage clauses; the above clause is only one example and does not address every issue that might be negotiated in such clauses. A retained acreage clause should, however, address each of the elements that is the subject of each of the paragraphs of the clause copied above.

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The Texas Supreme Court heard arguments yesterday in the fight between the City of Lubbock and Coyote Lake Ranch over whether the accommodation doctrine applies to severed water rights. Here is a good article from the Texas Tribune summarizing the arguments. The oral arguments can be viewed on the Texas Supreme Court website, here.  My earlier discussion of the case can be found here.

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