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.

In an opinion with as many acronyms as the Dallas Cowboys have draft-pick detractors, a California federal court in Center For Biological Diversity v. Bureau of Land Management, held that the BLM violated the National Environmental Policy Act in its assessment of oil and gas leases on federal lands in California. A “FONSI” – a Finding of No Significant Impact – issued by the BLM was unreasonable in not considering hydraulic fracturing techniques when used in combination with horizontal drilling. The BLM’s conclusion was that the leases would have no significant environmental impact. In challenging a BLM evaluation, a plaintiff must merely raise substantial questions, but does not have to show that significant effects will occur.

The court found that it was unreasonable to conclude that certain non-No Surface Operations leases did not need further study before their sale.

The NEPA requires “significant action”, in terms of context and intensity, to be considered in the evaluation. Those terms are sliced and diced, defined and described, codified and, apparently, deified, in Section 1508.27 of the Act in ways that are too detailed to consider here. In summary, as there are in most federal regulations, there are plenty of bases for a court to void a government action it doesn’t agree with. One example, “ … the significance of an action must be analyzed in several contexts such as society as a whole (human, national), the affected region, the affected interests, and the locality.” And it goes on.

The BLM failed to meet its burden because it relied on older studies and did not take into account the new technology that has made fracking prevalent. The court said it would be reasonable to assume that with today’s technology a lessee would utilize fracking technology to explore for oil.

The court said that it was “unreasonable for BLM not to at least consider reasonable projections of drilling in the area that include fracking operations, or else limit its sale to leases with NSO provisions that would permit it to prohibit all surface disturbances until more specific information becomes available.” By failing to consider fracking the BLM failed to properly assess at least three “intensity” factors in its FONSI.

In a well-timed op-ed piece, the Wall Street Journal compared the economies of Texas and California, two of the country’s most resource-rich states. The WSJ compares the success of Texas to the troubles in California by looking at the differences in their approach to fossil fuels and economic develoment in general.

Thanks to Brooke Sizer for her contribution to this entry.

If it ain’t broke, don’t fix it. Or, as said by the Pennsylvania Supreme Court, “A rule of property long acquiesced in should not be overthrown except for compelling reasons of public policy or the imperative demands of justice.”  There were no such imperatives in Butler vs. Charles Powers Estate, in which the Court upheld the “Dunham Rule” in Pennsylvania oil and gas law.

The Dunham Rule, stated simply:

It is a rebuttable presumption that if in connection with a conveyance of land there is a reservation or an exception of “minerals” without any specific mention of natural gas or oil, then the word “minerals” was not intended by the parties to include natural gas or oil. The presumption may be rebutted by a challenge through clear and convincing evidence that the intent of the parties at the time of the conveyance was to include natural gas and/or oil.

The high court reversed an appellate court ruling that remanded the case to a trial court for an evidentiary hearing including expert testimony on whether (1) the gas within the Marcellus Shale is “conventional natural gas”; (2) shale is a mineral, and (3) the entity that owns the rights to shale beneath the property also owns the right to the gas within that shale.

The winners:

  • Title examiners
  • Clients of title examiners
  • Anyone who has taken a lease on a tract where there has been a mineral reservation
  • Anyone who benefits from stability of land titles

The losers:

  • Those who thrive on chaos and uncertainty
  • Those who reserved minerals without mentioning oil and gas, possibly thinking, if they were outsiders, that Pennsylvania is like most other places, where minerals includes oil and gas

To say Dunham was “longstanding’  says a lot. Butler interpreted a deed from 1881, and the Dunham Rule itself dates back to 1882.

Kudos to counsel for the Powers Estate (identified on the docket sheet as Thomas Meagher III of the Law Office of Michael Giangrieco) for creativity.  Arguing the proposition that “he who owns the shale owns the gas” (referring to another Pennsylvania case), they likened the Marcellus Shale to Coca Cola and the shale gas as the “fizz” emanating therefrom. No court, said the appellee, could ever reason that the “fizz” is separate and apart from the Coke. 

A concurring opinion, agreeing with the result because the law was long- settled, criticized the rule as contrary to the law of virtually every other producing state and characterizing the rule’s “19th century rationale” as “cryptic, conclusory and highly debatable.”  Read the opinion and you will understand what he means.

That’s George Jones at the top of the entry.  This week can’t pass without a tribute to the Possum – the saddest voice in country music:

 http://www.youtube.com/watch?v=d6okqsgJbRg  

http://www.youtube.com/watch?v=VExw77xJsBQ

 The Texas Railroad Commission is going through the Sunset review required every 10 years for all state agencies. If approved, the pending legislation (House Bill 2166) would:

A New Name

• Change the name of the agency to the Texas Energy Resources Commission.

Campaign Finance Reform

• Limit the ability of commissioners and candidates to accept campaign contributions except at certain times near elections.

• Limit contributions from parties with contested cases before the commission and requires the commission to maintain a list of contested cases and the parties to each case, and to ensure that hearing notices contain information about prohibited contributions.

• Require the resignation of a sitting commissioner upon announcement of candidacy, or upon becoming a candidate, in any election for office other than commissioner, so long as the commissioner’s unexpired term is more than 18 months. The candidacy or announcement of candidacy will serve as an automatic resignation.

An End to Ex Parte Communications

• Instruct the commission to develop a policy prohibiting ex parte communication between hearings examiners and commissioners, or between hearings examiners and technical staff of the commission who has participated in a hearing, including prohibiting a commissioner from communicating with a hearings examiner other than in a formal public hearing.

A Focus on Safety

• Instruct the commission to adopt guidelines for determining the amount of penalties for pollution under Sec. 81.0531 of the Natural Resources Code.

  • There must be differing penalties for differing violations based on seriousness of the violation and hazard to health or safety of the public resulting from the violation.
  • Adds the number of times a permittee’s certificate of compliance has been canceled to the list of items that the guidelines must take into account.

• Require the commission to adopt an enforcement policy that employees must follow that pertains to safety and prevention or control of pollution. The policy must include:

  • a specific process for classification of violations based on the seriousness of any resulting pollution and any resulting health and safety hazard
  • standards on which violations may be dismissed upon coming into compliance and which must be forwarded for enforcement. Employees must take into account violation history.

• Allow the commission to establish fees to pay for the pipeline safety costs.

• Grants pipeline damage prevention jurisdiction over interstate and intrastate hazardous liquid and CO2 pipeline facilities.

• Establishes a $30 million cap on the oil and gas regulation and cleanup fund.

Help for Mineral Owners

• Permit the commission to, upon request of interested party, with approval of other interested parties (maybe there isn’t that much help after all), hold a hearing on a forced-pooling application in or near the county of the proposed unit or allow participation by telephone.

Some of these changes are significant. This is not the final product; the bill has been amended since being introduced and the legislature has time to react to “input” from interested parties.  

 

This post is not from a global warming denier. But I do appreciate even-handed assessments of the situation. Here are two reports that fit the bill. 

In the London Telegraph, Geoffrey Lean says that recent research suggests climate change might not be as catastrophic as the gloomiest forecasts. But he warns that it will be decades, if not centuries, before the full consequences of today’s emissions of CO2 become clear.

Rapid temperature increases in the 1980’s and ‘90s have dramatically slowed for the past decade even as CO2 emissions have continued to increase. But he does not agree with skeptics who say that global warming has stopped. As an example, he cites that eight of the nine hottest years on record have all occurred since 2000. His point is that CO2 may be less potent than has been thought in heating the planet, and soot or “black carbon” may be more to blame.

Recent papers from different, well established scientists, suggest that the rise of temperatures may be closer to the 1.5º C than the 4.5º C range of increase in global temperatures estimated by the IPCC.

The Economist reports that there is “a mismatch between rising greenhouse gas emissions and not-rising temperatures, which is a big puzzle to scientists.”

They also warn that this does not mean that global warming is delusion. Flat as they are, temperatures in the first decade in the 21st century are 1º C above their level in the first decade of the 20th century. They offer several scenarios: Perhaps the 1990s when temperatures were rising was the anomalous period, and not 2000 through 2010. Or the climate may respond differently to higher concentrations of CO2 in ways that are not properly understood.

An unpublished report by the Research Council of Norway (not yet peer reviewed), a government-funded body using a method different from the IPCC’s, believes that the most likely effect of doubling CO2 omissions would be a rise of 1.9º C. This is consistent with projections from other research projects. The IPCC estimates the answer to be about 3º C.

There is a discussion of several different models using several approaches to predict the effect of climate change, which is too much science for a lawyer.

They also agree that soot, or black carbon (from diesel and Third-World cooking fires), may be more to blame than CO2.

Finally, several lines of evidence show that observed trends are pushing temperature predictions down, whereas compter models are pushing temperature predictions up.

And a bonus from the Financial Times and Lawrence Soloman:  A report on the change of heart by some journalists on the subject, based in part on the Economist’s stance. 

Is it Really 4,000?

Here is an introduction to the rest of this post. 

Have you heard that 4,000 scientists from 130 countries support the IPCC’s conclusions about climate change? According to Energy Probe the “consensus” is not as it seems. The work of “2,500+ scientific expert reviewers, 800+ contributing authors, 450+ lead authors from 100+ countries” is not really that. The numbers total 3,750, which is rounded up to 4,000. By elimination of duplications, exaggerations, and input not relevant to the result, Energy Probe whittles down the list of true backers of the IPCC report to approximately 60.

Read the articles and decide for yourself.

Co-author Jonathan Nowlin

I learned to drive on an old, black, stick-shift, straight-six, no-radio, no-A/C automobile manufactured the year after the AAPL’s first  Form 610 – Model Form Operating Agreement was created.  The ’57 Chevy is now considered a classic. Not so with the 1956 Model Form, which is generally considered a relic. Clovelly Oil Co., LLC  v. Midstates Petroleum Co. shows that while the 1956 Model Form might be old, it is still alive and dangerous. In Clovelly, the Supreme Court of Louisiana busted a 242-acre hole in the operator’s Unit Area (as the Contract Area was then called) by ruling that the 1956 Model Form, without more, does not apply to leases acquired after the JOA was executed. What could that “more” be? See below.

Through a series of assignments, Clovelly and Midstates became parties to the JOA. In 2008, Midstates secured a new oil and gas lease that covered acreage in the Unit Area. Clovelly claimed the lease was covered by the JOA, and as such, it was entitled to its working interest described in the JOA and, as operator under the JOA, the right to operate the new lease.

Relying on the language of the JOA, the court held that the original parties entered into the JOA with the intent to explore and develop only the leases and unleased mineral interests owned by the parties at the time they signed the JOA. The ’56 Form used present-tense language when referring to the leases to which the JOA applies. For example, the preamble referred to leases and unleased mineral interests of which the parties “are owners” in the land described, and the parties agreed “to explore and develop these leases and interests.” Also, the JOA defined “oil and gas interests” as “unleased fee and mineral interest in tracts of land lying within the Unit Area which are owned by the parties.”

The court reasoned that holding otherwise would create an absurd result: If all new leases automatically became subject to the JOA, then the parties would be required to share in the costs for those leases—without having the option to elect whether the leases should be subject to the JOA.

If you’ve ever questioned the need for an AMI in an exploration project, ignore Clovelly at your peril.  The rationale could apply to other situations. The court noted that the parties could have easily avoided this problem by including an Area of Mutual Interest provision, an “agreement between or among parties to a JOA by which the parties attempt to describe a geographical area within which they agree to share certain additional leases or other interest acquired by any of them in the future.” The court also noted that an AMI is often established by parties to the AAPL Model Forms when the parties desire to maintain their proportionate interest in newly acquired leases.

What would be the result with the later forms? Find out in a later post.

While you wait for the next post, a musical interlude.

Co-author: Travis Booher

Valid Description? We don’t need no valid stinking description!

Actually, in May v. Buck, a Texas Court of Appeals says you do.  The need for a sufficient property description in a oil and gas transaction seems like an easy-enough and fundamental concept to grasp, but its application has escaped many a contracting party.

Question: Is “ … a 100 acre spacing centered around the David Morris Gas Unit #1 in Leon County, Texas” a valid description? Read on for the answer.

The Facts

 May and Buck entered into a Letter Agreement in which May would cquire certain acreage. Buck was to assign “all the minerals and a 100 acre spacing centered around the David Morris Gas Unit #1 in Leon County, Texas.” The agreement also stated, “[t]he acreage referred to within this agreement is better described in Exhibit A attached to this agreement and made a part of this agreement.” Unfortunately, after May provided the capital for the leases, Buck did not assign the interests, and the parties ended up in the courthouse. Buck defended by asserting that May’s claim was barred by the statute of frauds because of an insufficient description.

May’s Problem

No document existed identifying the “100 acre spacing centered around the David Morris Gas Unit #1” and there was no information about the shape or boundaries of the 100 acres. Exhibit “A” described 563.465 acres described in four tracts and included specific references to instruments filed in Leon County. The 563.465 could be identified, the David Morris Gas Unit could be identified, but both May and Buck’s experts at trial identified several configurations for the 100 acre tract. To make matters worse, the experts disagreed whether the “David Morris #1” reference was to the unit or the wellbore.

The Result

 The court reiterated the well settled rule: “To be sufficient, the writing must furnish within itself, or by reference to some other existing writing, the means or data by which the land to be conveyed may be identified with reasonable certainty.” Because several different configurations were possible, one could not identify the 100 acre tract with reasonable certainty. As a result, May came away without his land and his money.

The Takeaway

 A letter agreement to convey an interest in real property is subject to the statute of frauds (The rule is not limited to deeds and leases). As a result, identifying the subject land should not be like digging for gold, where “X” marks the spot. The agreement must identify the lands with reasonable certainty. If the location of the lands is open to multiple interpretations, the agreement will be invalid.

Valuable Trivia

“We don’t need no stinking badges” is one of the most commonly misquoted lines in movie history.