Co-author Jason Emmitte

The Texas Railroad Commission has clarified and strengthened Rule 13, relating to requirements for drilling, putting pipe down, and cementing wells. The amendment will go into effect on January 1, 2014.

Generally, the revisions govern the casing and cementing of all wells, unlike previous versions.  Highlights are:

  • New and more precise definitions, for example, “hydraulic fracturing”.
  • Transfer from the Texas Commission of Environmental Quality (TCEQ) to the Groundwater Advisory Unit of the Oil and Gas Division of the RRC of responsibility for determining at what depth usable-quality water must be protected.
  • The authority to require a better quality of cement mixture to further protect groundwater that could be harmed by a poor casing job or the use of below-grade cement.
  • A cementing report must be filed with the RRC within 30 days of completion of a well or within 90 days of cessation of drilling, whichever is earlier.
  • Operators will be required to pressure-test well casings to the maximum pressure expected, monitor the annular space for pressure changes that could indicate a casing leak, verify the mechanical integrity of surface and intermediate casing when drilling time exceeds 360 hours, and seek prior approval before setting surface casing deeper than 3,500 ft.
  • Additional testing on wells less than 1,000 ft below usable groundwater
  • Use of air- and water-based drilling fluid until surface casing is cemented.
  • New requirements for well control measures and blowout preventers.
  • Additional cementing when an injection or disposal well is within a quarter mile.

The effect of the amendment is to more clearly outline the requirements for all wells, consolidate the requirements for well control and update the requirements for drilling, casing, cementing and fracture stimulation.

These revisions are timely, amid the debate over whether there should be  federal rules governing hydraulic fracturing.  Here is an article in Scientific American offering arguments for and against federal fracking rules. 

  

Co-author Travis Booher

The regular session of the 2013 Texas Legislature is over and now it’s time to assess the damage. Bills significant to the oil and gas industry, and their fate, are as follows:

HB 100 – Forced unitization: Failed. Regardless of your opinion of the merits, this was no surprise.

SB 108 – Allowing adverse possession of property by a cotenant heir after 15 years: Failed. That was a good thing. The bill would have created adverse possession of  lands from a cotenant who is also a family member (hence, a “cotenant heir”). The bill may have intended to clear title to land in which numerous heirs own an interest because of intestate succession, but it surely would have created conflict at family reunions. Texas already has a method to adversely possess lands, and having numerous affidavits claiming that lands have been successfully adversely possessed (as allowed by the bill) would create title uncertainty.

SB 873 – Permitting process for oil and gas wells and use of water: Failed (left pending in committee).

SB 1747 – Transportation reinvestment zones: Passed.

See our May 14 entry  for comments on these last two.

HB 2166 – Railroad Commission’s sunset bill: Failed. “Touchy” parts (as in strongly resisted by those with something to lose, to wit, some or all of the RRC commissioners) of the bill were new ethical requirements for the commissioners, including resigning before running for another statewide office, prohibitions on campaign contributions, and reporting of contributions from parties having business before the commission.

SB 219 – The Texas Ethics Commission’s sunset bill: Passed. The resign-to-run portion of failed HB 2166 found its way into this one. We understand that the rationale for opposition to the resign-to-run requirement was that the same rule would not apply to other statewide officeholders. This bill is awaiting the Governor’s signature.

HB 2590 – Effect of foreclosure sale of property subject to an oil and gas lease: Passed, awaiting the Governor’s signature. This bill, sponsored by a producer, attracted opposition by other producers after the session closed. They promise to ask the Governor to veto it. If you take a lease subject to a deed of trust and the property is later foreclosed, you lose your lease unless you have a subordination agreement. This bill changes that: You wouldn’t lose your lease (if recorded before the security interest or after the security interest but before the foreclosure sale).  You would lose use of the surface, however, and the bill imposes new indemnification obligations on the lessee.

CR 53 – Confirming the pecan pie as the official pie of Texas. Passed.

First, an admission and a regret:  My June 6 post missed the 69th anniversary of an episode as significant as any in our country’s history: D-Day.  I think I know why.  As time passes and the participants in that venture become fewer, there aren’t as many left to tell the story, the celebrations dwindle, and the meaning of D-Day becomes further removed from our collective memory.  (Note to middle schoolers and those who don’t read much: Abraham Lincoln was not the president during WW II).

The pics are of my uncle, Judge Lenton Sartain, then and now. Then he was a 23 year old lieutenant-soon-to-be-captain in the 82nd Airborne Division. On the night of  June 6 he and his troops and their artillery were packed into plywood gliders and cut loose several miles beyond the beaches. From there they helped to blast the advance out from the coast and pressed on to Holland, Belgium and Germany. I could go on but, as you’ve heard, the rest is history.  Now he is 92 years old, in well-deserved retirement, and feeling pretty good.

Now, on to business.

Our co-author today is Alexandra Crawley

Today’s post is about blocking and tackling – no lofty public policy considerations to get the electorate all fired up.  We see a recurring issue with the proportionate reduction clause in leasehold assignments that reserve an overriding royalty interest. The interpretation of these assignments – i.e. who gets the money – hinges on whether proportionate reduction covers the “mineral estate”, the “leasehold estate”, or both. Learn from the following examples:

The Deal

Tiger Drilling takes an Oil and Gas Lease with a lessor’s royalty of 15%. Tiger assigns 50% of its interest in the lease to 12th Man Operating, reserving an ORRI equal to the difference between existing lease burdens and 18%.

The First Scenario: The “Mineral” Estate

The assignment contains the following proportionate reduction clause:

If any lease assigned to Assignee covers less than a full mineral interest or if Assignor’s interest in such lease is less than the full mineral estate, then each overriding royalty interest reserved by Assignor in each such lease shall be reduced proportionately.  (all emphasis is ours)

It appears that 12th Man’s scrivener was not as slick and quick as their pesky quarterback.  Tiger would be credited with an ORRI equal to the difference between existing lease burdens and 18% applicable to 100% of the mineral interest assigned, not an ORRI equal to the difference between existing lease burdens and 18%, applicable to 50% of the mineral interest.

This is because there is no proportionate reduction clause reducing the reserved ORRI to the 50% leasehold interest being assigned. Therefore, Tiger would have the full 3% overriding royalty (18% minus the lessor’s royalty of 15%), all of which burdens 12th Man’s 50% leasehold interest in Subject Lease.

Second Scenario: The “Mineral” and the “Leasehold” Estates

The assignment contains the following proportionate reduction clause:

If any lease assigned to Assignee covers less than a full mineral interest or if Assignor’s interest in such lease is less than the full mineral estate, then each overriding royalty interest reserved by Assignor in each such lease shall be reduced proportionately. If the interest conveyed to Assignee herein is less than the entire leasehold estate, the overriding royalty shall be reduced proportionately to the interest conveyed.

Here, Tiger would be credited with an ORRI equal to the difference between existing lease burdens and 18%, applicable to 50% of the mineral interest assigned, rather than an ORRI equal to the difference between existing lease burdens and 18% and 100% as above. Pay attention to that second sentence. The clause now addresses both the mineral and leasehold estates.

The result is that Tiger would have a 1.5% overriding royalty (18% minus the lessor’s royalty of 15% multiplied by 50%), burdening 12th Man‘s 50% leasehold interest in the lease.

The Lesson

Double-check your proportionate reduction language. Does it reflect the parties’ intentions? If you intend to proportionately reduce the ORRI to the leasehold interest assigned, be sure to include “leasehold” language.

Co-author Chance Decker

Private property rights advocates scored a big victory in a Texas condemnation case in the ongoing battle between pipelines and landowners over the power of eminent domain. (See our last post for a decision with the opposite result). 

An appeals court in Crosstex NGL Pipeline, LP v. Reins Road Farms, Ltd. denied “common carrier” status for Crosstex, who wanted an injunction to prevent the landowner from interfering with Crosstex’s efforts to survey his property for a gas liquids pipeline.

The court found Crosstex was not a “common carrier” with eminent domain power under either the Texas Natural Resources Code or the Texas Business Organizations Code. Crosstex’s pipeline would transport “natural gas liquids” not “crude petroleum” as that term is defined by the Natural Resources Code, and there was evidence the pipeline “will not actually be used by the public,” a prerequisite to common carrier status under the Business Organizations Code.

The Natural Resources Code confers common carrier status on any person who “owns, operates, or manages a pipeline or any part of a pipeline in the State of Texas for the transportation of crude petroleum to or for the public for hire, or engages in the business of transporting crude petroleum by pipeline[.]” The court did not consider “natural gas liquids” to be “crude petroleum” under the statute.

The finding on the public use question is important to landowners opposing condemnation. Crosstex’s public use T-4 permit from the Railroad Commission did not automatically confer common carrier status. A landowner is still entitled to dispute a pipeline/condemnor’s common carrier status despite the issuance of a RRC T-4 permit. This is consistent with the Texas Supreme Court’s 2012 decision in Tex. Rice Land Partners, Ltd. v. Denbury Green Pipeline-Tex., LLC.

Prior to Denbury, about all the pipeline had to do for common carrier status was fill in a box in its RRC permit application. It’s not that easy anymore.

There are several ways the songsmith could view this case, in the unlikely event that condemnation law is his muse.  One is from this particular pipeline’s perspective. (Landowners who weren’t as lucky as here should like the reference to the six-gun). Another is through the eyes of the landowner.  That’s a stretch here. Nobody accuses the landowner in our case of being in such a tough spot.

Co-author Chance Decker

Two recent cases from the same Texas court reflect the ongoing uncertainty over the threat to private property rights posed by the Keystone XL and other pipelines. Is there a theme, a common thread, running through law on this subject? Not in Texas. Today we discuss one of these decisions, Next time we review the other.

In Re Texas Riceland Partners, Ltd., confirmed TransCanada Corp’s common carrier status and affirmed its right to immediate possession of landowners’ property in Jefferson County for the Keystone XL pipeline. A consortium of rice farmers alleged TransCanada could not use the power of eminent domain to take over private property because it was not a “common carrier” under the Texas Natural Resources Code. The Code grants common carriers the power of eminent domain, and defines a “common carrier” as someone who “owns, operates, or manages a pipeline or any part of a pipeline in the State of Texas for the transportation of crude petroleum to or for the public for hire, or engages in the business of transporting crude petroleum by pipeline.”

The trial court denied the farmers’ challenge to TransCanada’s common carrier status and upheld the condemnation. The court of appeal upheld TransCanada’s right to possession of the condemned property during the farmers’ appeal. The farmers relied upon the 2012 Texas Supreme Court decision Texas Rice Land Partners, Ltd. v. Denbury Green Pipeline-Texas, LLC that a pipeline owner’s power to condemn must be fully resolved through the judicial process before the pipeline can take possession of private property. The flaw in that challenge was that in Denbury, the court denied common carrier status.

The court found ample evidence — including affidavits from TransCanada employees about the Keystone XL Pipeline’s ownership and planned operations—to find TransCanada a common carrier.

The takeaways: 

  • The pipeline/condemnor need not wait until the end of the seemingly interminable appeal process to take the land and construct its pipeline.
  • Some cases raising “big” policy issues are decided by a mundane examination of the statutes creating the rules, not flowery speeches by one side or the other.

I spent the better part of last week surrounded by foreigners … which is to be expected because I was in a foreign country, the Netherlands to be precise. Looper Reed has joined First Law International, a consortium of select, highly-rated law firms in over 45 countries, assembled to give businesses in one country, the United States for example, access to counsel in other countries who are a known quantity in terms of their talent and ability to address their legal needs.

The excursion was beneficial for several other reasons, one of which was to remind me of the multitude of benefits that result from the private ownership of minerals.  Mr. and Ms. Royalty Owner, next time you’re mad at your lessee, or the previous owner who reserved half the minerals and the executive rights, remember that if you were in many other producing countries you wouldn’t have standing to be dissatisfied. The government would own the minerals under your land.  And your suffering through the noise, truck traffic, dust and other detritus of a drilling operation wouldn’t be soothed by a fat royalty check.

If you are the operator, your ornery lessor would be your own federal govenment. Imagine control over our oil and gas reserves by those who believe that Uncle Sam knows best in all aspects of our economic life, and to whom fossil fuel production is to be discouraged.   

Second, the hydraulic fracturing debate rages in countries other than the United States. For example, it is banned in many places with the promise of bountiful gas reserves, and where it is allowed there is resistance:

France, where fracturing is legal for geothermal energy but not for gas.  

England, where it is legal but opposed by many.

The Netherlands, where the government supports it but others (according to the NewYork Times) don’t.

Where fracking is banned in those portions of Germany that are likely to be productive.

Today’s musical interlude has nothing to do with gas production, but maybe Irish-American relations is on your mind.

The short answer is no, according to the American Petroleum Institute. The API compared oil and gas to other industries in terms of profit margin and effective tax rate. The oil and gas industry-wide profit margin is 7.3%, which is lower than manufacturing (8.6%), computers and peripherals (9.7%), pharmaceuticals (16.0%) and beverage and tobacco products (19.3%).

The effective tax rate of oil and gas companies is 44.6%, which is greater than healthcare (34.9%), utilities (32.6%), S&P industrials (30.0%), banks and insurance companies (29.3%), computers and peripherals (25.6%), pharmaceuticals (21.3%).

That “Big Oil” is against the common man is promoted by many detractors of the oil and gas industry.  But ownership of oil and gas companies is not dispersed like you might think. According to the API, pension funds own 31.2% of oil and gas companies, individual investors own 21.1%, and IRAs own 17.17%. Institutional investors (“Wall Street”?) own only 6.6%.

Go to http://www.api.org/tax for more information on the oil and gas industry and taxes.

The Next Question: What would happen to independent producers if proposals in Congress to repeal tax treatment of domestic companies are successful?

According to a Texas Society of CPA committee report, congressional proposals to repeal tax treatments of domestic oil and gas E&P would be detrimental to the industry, and not particularly beneficial to the federal government.

Among the facts the report notes are:

• 95% of the nation’s oil and gas wells are drilled by independent producers, who employs on average, no more than 12 people each. Note to Congress: The tax repeal proposals are not about “Big Oil”.

• The Administration’s FY 2014 budget proposal estimates that repealing the provisions would generate over $90 billion in tax revenue through 2023. This extra money will come from somewhere, to-wit, the pockets of independent oil and gas producers.

• 50 largest independents reinvest 150% of their cash flow back into new domestic production.

• Oil and gas businesses pay $100million per day in taxes.

Among the tax benefits the Administration wants to eliminate are:

• Deduction for IDCs

• Percentage depletion

• Domestic production activities deduction

• Deduction for tertiary injectants

• Amortization of geological and geophysical expenditures

• Use of LIFO method to account for inventories

• Exception to the passive loss limitation rules for working interests

The report explains the benefit of each of the deductions and the how elimination of each might affect the oil and gas industry.

Without rapid recovery of drilling expenses, investors face a high-risk venture with, at best, a long-term return of their investment. The overall impact of these deductions is to match up current deductions with current risks. This encourages investment in the business (a policy this Administration does not favor). In the case of IDCs, the report notes that permitting the deduction upfront has no effect on long term revenues; the government will collect the revenue sooner or later.  

 A musical interlude which, if you’ve been here before, is totally predictable.

A Louisiana lessee does not owe its lessor royalties based on hedging profits, said a federal district court in Cimarex Energy Co. v. Chastant. Cimarex, the lessee, hedged its gas contracts and didn’t pay its lessor, Chastant, earnings from the hedge.

As the court described it, hedging involves buying and selling financial positions as a strategy to avoid the risk of a price fluctuation. The hedging party uses financial transaction derivatives to minimize the risk if/when the price of the commodity drops below a certain level. 

Cimarex Memorandum in Support of Motion for Summary Judgment is a good description of the hedging process and its value to oil and gas producers.

The question for the court was whether additional royalties must paid on amounts the lessee generated by a separate, purely financial, transaction from the sale of the oil and/or gas at the property.  The answer is “no”.

Chastant’s royalty clause provided for payment by Cimarex, on gas, of 1/8 of the market value at the mouth of the well and on oil, 1/8 of the price received f.o.b. the leased property.  In Louisiana, a royalty is the “landowner’s share of production, free of expenses of production.”

Chastant argued that since Cimarex calculated the hedge price in filings with the SEC, the hedge price constitutes “market value” under the lease. Chastant cited Frey v. Amoco Prodcution, a 1992 case where the Louisiana Supreme Court held that royalties were owed on a take-or-pay case settlement because the the take-or-pay payments were part of the “amount realized” under the terms of the lease. Therefore, said Chastant, any benefit derived by the lessee because of oil and gas production, even separate transactions, should be included in the calculation of the royalties due to the lessor. 

Cimarex argued that the lease royalty provisions are in keeping with well-established Louisiana principles in which “market price” is based on the market price at the well or field for the oil and/or gas. Therefore, the market price cannot be tied to some future financial transaction because of the oil and gas produced.

The court rejected Chastant’s arguments. To agree with Chastant would overturn decades of Louisiana oil and gas law by holding that standard lease language allows royalties to be based on something other than the price or value of the oil and/or gas. According to the court, such a holding would allow royalties to be based on monies earned by any transaction remotely connected to the oil or gas. Therefore, Cimarex did not owe royalties based on its hedging profits.

Many thanks to Ann Weissman for her contribution to this post.

Jesse Jenkins of the Energy Collective ponders the question. He reports as follows:

  • According to the US Energy Information Administration 27,000 new gas wells were completed in the U.S. in 2011, many of which were horizontal wells implementing hydraulic fracturing.
  • Each well consumes 5 million gallons of water per well for fracking and completion. He quotes FracFocus.org (more about which later), which reports 2 million gallons per frac job, but some wells are fracked more than once and there may be what he calls “some inherent downward bias in the voluntary nature of the FracFocus data set”. Thus, Jenkins uses 5 million.and concludes that fracking in 2011 consumed 135 billion gallons of water.
  • In context, how much is that? Jenkins assumes that in 2005 (latest data available) all freshwater withdrawals total 127,750 billion gallons. Assuming that is a fair baseline, fracking of shale gas wells in the United States in 2011 represented on the order of .1% of total U.S. freshwater withdrawals.
  • Withdrawals do not equal consumption. For example, water used in power plant cooling is discharged back into waterways without contamination or treatment.
  • He concludes that freshwater consumption (either evaporated or contaminated in storage) totaled 43,800 billion gallons. Thus, consumption for shale wells is .3% of total freshwater consumption.
  • Agriculture consumes, by far, the greatest amount of water, totaling 32,850 billion gallons of water annually, which is 243 times more water than fracking for shale gas.
  • Those of you among us who like to spoil an otherwise nice walk in the country might wonder about golf courses. According to the PGA, golf courses consume .5% of all freshwater used in the country.
  • Jenkins emphasizes efforts to commercialize recycling technology to reclaim a portion of frac water flowback that could reduce net freshwater consumption by about 20%. And companies such as GasFrac are working on waterless fracking in a process using Liquified Petroleum Gas gel.

On the other hand, where fracking takes place complicates the equation. CERES , a non-profit organization focusing on sustainability challenges such as climate change and water scarcity”, issued a report, Hydraulic Fracturing & Water Stress: Growing Competitive Pressures for Water”. According to CERES, 47% of fracked wells are in water basins with high or extremely high water stress. In Colorado, it is 92%. Couple this with the U.S EIA prediction that shale gas production will constitute 49% of U.S. gas production by 2035, and the challenges become acute.

 Takeways from the CERES report:

  • State regulators should implement rules that encourage recycling of frac water.
  • Operators in high water-stress areas should get buy-in on water issues from local stakeholders.
  • Mandatory reporting of water use is necessary.
  • Operators and water regulators should conduct sufficient water management planning.   

 My money, if I had any left after two college tuitions, would be on technological and regulatory advances that will mitigate the stress fracking places on our groundwater supplies.

This is a tale of two regulatory schemes.

First, there is the federal way, and I’m not making this up: In my last post we learned that if the BLM, when preparing its PRMP/FEIS (which in some incomprehensible way is different from a PRMP/EIS, but which nevertheless includes an RFD) which is issued by an EA and adopted by a ROD, but which will be subject to further analysis at the APD stage, evaluates a non-NSO lease to be sold along with NSO leases within the HFO boundary pursuant to the NEPA, the MLA of 1920, and the FLMPA, and does not have its FONZI well in hand in analyzing the context and intensity of the proposed action under the factors set forth by the CEQ, then because the activity will affect T&E species, the BLM could be sued in accordance with the APA under jurisdiction imposed by 13 U.S.C. 1331, and be thereby exposed to an MSJ which, if granted as in that case, will result in a SNAFU, which one should expect in these situations, but which could also be a dilatory, hair-pulling, budget-busting, futility-inducing FUBAR. OMG!

And according to Michael Mills, a California environmental lawyer, California legislators are pushing to ban fracking altogether, at least for now.  (Query: When will “now” be over?).  According to Mr. Mills, other bills in the California legislature propose regulation of fracking.

Now the Texas way: One example of a simpler approach to regulation is SB 873 by Senator Glen Hegar, in the Lesiglalture, which is to clarify ambiguities in the permitting process for wells used in oil and gas drilling activities. These wells are regulated by the Railroad Commission and there is confusion about whether fracking is exempt from permitting bythe state’s hundreds of water improvement districts. If fracking is “drilling or exploration”, then it is exempt from permitting. If it is oil and gas “producton”, then a district can require a permit.  The bill clarifes the confusion, allows local control over the permitting process, and will protect water sources. 

Another example: SB 1747 by Senator Carlos Uresti.  This bill allows counties to set up transporation reinvestment zones.  Increased revenues from county property and sale taxes will be dedicated to repair and maintain roads and other infrastucture degraded by increased oil and gas activity.    

These proposals are efficient, focused to address particular problems, and do not impose more bureaucracy on operators.  In contrast, federal regulations appear overwrought, byzantine and bureaucratic. Why, I wonder?  

Consider the recent Wall Street Journal op-ed. Texas embraces development of its natural resources, as does Louisiana.  California  prefers Solyndra and algae.