July 18, 2014

What Happens When You Don't Use a Lawyer to Review Your Oil & Gas Lease?

Not all Texas folks consult an attorney to prepare a will or to review an oil and gas lease or a pipeline easement they have been offered. Maybe they think lawyers are expensive and only for the wealthy or maybe they don't want to take the time. Fortunately, there are affordable attorneys for virtually all situations, including those who review oil and gas leases. In fact, there are instances where it is critically important to consult a lawyer, and the legal fee for a specific service is often a fraction of what people end up losing by signing boilerplate legal documents without understanding the the documents or the implications those documents may have for their family’s future.

A recent case from Florida highlighted this problem. The case is James Michael Aldrich vs. Laurie Basile et al from the Supreme Court of Florida. The case involved the will of Ann Aldrich. In 2004, she made a will using an “E-Z Legal Form”. The will left her property to her sister, and if her sister died before Ann did, then to her brother. Ms. Aldrich’s sister died first, so her brother was the sole heir to her estate according to the will. However, this “E-Z Legal Form” didn’t have a residuary clause. Ms. Aldrich also left a written note after her sister died leaving her possessions to her brother, except for certain bank accounts that were to be left to this brother’s daughter. But the document only had one witness, which made it invalid as a will under Florida law.

When Ms. Aldrich died, two nieces sued to receive part of the estate. These nieces were the daughters of a different brother of Ms. Aldrich, who had also already died before Ms. Aldrich. Even though these two nieces are not mentioned anywhere in the will, the Florida Supreme Court decided in their favor in a decision written by Justice Peggy Quince. Since the “E-Z Legal Form” did not have a residuary clause, Ms. Aldrich only intended for the property specifically mentioned in the will to be distributed. The Court found that all other assets, such as money acquired after the will was signed in 2004, had to be distributed under the laws of intestacy, which is the law that covers the distribution of property of someone who does not have a will.

Justice Barbara Pariente concurred, and discussed Ms. Aldrich’s will as a cautionary tale. She wrote: “While I appreciate that there are many individuals in this state who might have difficulty affording a lawyer, this case does remind me of the old adage ‘penny-wise and pound-foolish.’” She went on to say that “(a)s this case illustrates, that decision can ultimately result in the frustration of the testator’s intent, in addition to the payment of extensive attorney’s fees—the precise results the testator sought to avoid in the first place.”

This cautionary tale involves a will, but people call me all the time about oil and gas leases they have signed without consulting a lawyer, or even reading it themselves, and then are dismayed to learn how much money they’ve lost or that their land is damaged by oil and gas operations that are authorized by the lease. For important legal documents, having an attorney review it is not expensive, may save you significant money, and may spare you future heartache.

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July 11, 2014

Texas Mineral Owners: Don’t Sign a "Standard" Oil & Gas Lease Form for Oil and Gas Leases

A recent case that was decided by the Texas Court of Appeals in San Antonio illustrates the problems when mineral owners sign a "standard" form for their oil and gas lease and why they should consider getting the opinion of an experienced Texas oil and gas attorney before they sign. Failing to do so could end up costing you money every month.

The decision is Chesapeake Exploration, LLC v. Hyder. The Court, in a unanimous decision written by Justice Sandee Bryan Marion, ruled that, despite the claims of the well operator, post-production costs could not be deducted from the mineral owner's royalties, based on the specific language of the lease before the Court. This particular lease was most definitely not a standard form and appeared to have been carefully drafted by the Hyder's attorney.

The Hyder lease was executed on September 1, 2004 with another oil company, and then the lease was assigned to Chesapeake Exploration LLC. The leased premises consisted of two tracts of 1,037 acres and 948 mineral acres in Johnson County and Tarrant County. The lease allowed Chesapeake to drill from existing well sites adjacent to the leased premises, as well as within the leased premises itself. For the wells on the leased premises, the Hyders were paid a precentage royalty. For wells outside the leased premises, the Hyders were to be paid a specified percentage as overriding royalties.

As of December 2011, Chesapeake had 22 wells on the leased premises and seven wells on the adjacent land. Chesapeake deducted certain costs from both kinds of royalty. The Hyders alleged that the deduction of costs from either royalties or overriding royalties was a violation of the lease. Chesapeake counterclaimed to recover royalty overpayments. In spite of a pretty clear and specific clause in the Hyder lease that prohibited deduction of any costs, Chesapeake argued that, as to the regular royalties, the lease authorized the deduction of the Hyders' share of post-production costs and expenses between the point of delivery of the oil and gas and point of sale, and that the overriding royalty clause for the wells adjacent to the leased premises also allowed them to deduct the Hyders’ share of post-production costs and expenses from the overriding royalties.

The trial court awarded the Hyders a $1 million judgment against Chesapeake for breach of the royalty and overriding royalty clauses, attorney’s fees and interest. The Court of Appeals affirmed. Justice Marion wrote in the decision, "[w]hile we acknowledge an overriding royalty is normally subject to post-production costs, we also acknowledge Texas law allows the parties to modify this default rule." The opinion noted that in the Hyder lease, the following language appears: “[Royalty owners] and [Chesapeake] agree that the holding in the case of Heritage Resources, Inc. v. Nationsbank, 939 S.W.2d 188 (Tex. 1996) shall have no application to the terms and provisions of this Lease.” (The Heritage case described a rule for cost deduction based on the language in that particular lease). The Court also pointed out the specific phrases "no deduction of costs" and "cost-free" in the Hyder lease.

The Court of Appeals confirmed the ruling of the trial court on a second issue involving damages. The Hyders wanted reimbursement for a quantity of gas that was apparently lost and thus unaccounted for. The Court held that since the unaccounted-for gas was neither sold by Chesapeake nor used at the leased premises (the two situations where the lease said that royalty was due), the Hyders could not be reimbursed for it.

The kind of hairsplitting that was the basis of Chesapeake's arguments made me embarrassed for them. Chesapeake's financial woes of have been reported on in the media for many months. I can only guess that Chesapeake ordered its accounting department and attorneys to seek out recovery of costs wherever they could, even if it meant advancing somewhat specious arguments in court.

This case illustrates that the language of the lease is critical, and since post-production costs can be quite substantial, the language of the lease can have a large impact on the amount of royalties that a mineral owner gets. Elimination of post-production costs clauses in an oil and gas lease is something that the oil company almost never offers; it really has to be negotiated. It generally requires an experienced oil and gas attorney to get the most favorable cost provisions given the mineral owner's particular circumstances.

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July 4, 2014

Oil and Gas Benefits and Challenges for Texas

More Texas oil and gas companies are expanding. In January 2014 Brenham Oil and Gas Inc. announced the purchase of a 100% and 74% revenue interest in the 332 acre Inez field prospect. This prospect is located in Victoria County, Texas. Brenham plans to drill a well to regain the potential of the Yegua, where a well was originally drilled in 1990 by Ken Petroleum Corp. Reserves in the well are estimated at four bcf of gas and 160,000 bbl of condensate. In the new well, Brenham plans to explore several intervals in the Jackson shale to conduct a petrophysical study. Brenham believes it can drill three to four new wells on the Inez lease.

Late last year, FieldPoint Petroleum Corp. and Riley Exploration Group signed a joint exploration agreement to horizontally drill in the Serbin field, which is 50 miles east of Austin, Texas. The Serbin field lies in Lee County and Bastrop County. FieldPoint will have a 25% interest and Riley a 75%. The two companies will pool their lease interests and drill 12 new horizontal wells in 2014. FieldPoint already has a working interest in 72 producing oil and gas wells in this field.

All of this has been continued good news on the growth of the oil and gas industry in our state. Last year at the annual meeting of the Permian Basin Petroleum Association, the Speaker of the Texas House of Representatives, Joe Straus, said, “Every Texan should be grateful for the success of the state’s oil and gas industry. Every child in public school, every family that visits a state park, every business that transports personnel or equipment over roads.” He credited much of Texas’ successful economy and job creation to the oil and gas industry. Speaker Straus noted that all the success and booming economy had created some challenges. In the last decade, Texas’ population has grown by 6 million people, enough people to fill a whole other city the size of Houston.

As growth continues, there will be increased demand for things like water, electricity, roads and schools. But Speaker Straus believes Texas is meeting the challenges, and cites recent increases in funding for public schools and universities. The state government has also allocated $450 million for roads in the oil and gas corridor that has seen such an increase in traffic. So while the US Congress is reviled with a less than 10% approval rating, the Texas Legislature has a 53% approval rating and is trying to find viable solutions to these challenges, particularly in areas like education, water, and transportation. These are core areas Speaker Straus says the government should focus on. While the booming oil and gas sector has brought challenges, Speaker Straus said “(w)e cannot address our most serious issues without a healthy, vital oil and gas sector.”

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June 20, 2014

US Supreme Court Decision Important for Texas Land and Mineral Owners

The United States Supreme Court recently issued an opinion that effects many Texas property and mineral owners. Specifically, the Court decided the case of Marvin M. Brandt Revocable Trust v. United States in an 8 to 1 decision. The Court determined that certain rights-of-way for railroads revert to private property owners following the railroad's abandonment of the right-of-way easement. The ownership of the easement may carry with it ownership of the mineral estate. Where it does, and when the easement covers many acres, the mineral interests could be very valuable.

This case is significant for Texans because there are many railroads and railroad rights-of-way throughout Texas. The decision, written by Chief Justice John Roberts, addressed this central question: what happens to the ownership of the right-of-way easement when a railroad abandons its right-of way. In this case, the right-of-way was granted to the railroad under the General Railroad Right-of-Way Act of 1875. This Act gives railroads the right-of-way through public lands in the United States. The land at issue in this case was a ten-mile strip in Wyoming, upon which the right-of-way was created in 1908. Subsequently, in 1976, the federal government conveyed the land to Marvin and Lulu Brandt. The railroad later abandoned the right-of-way, and by 2004 all the track had been removed. In 2006, the U.S. government requested a judicial declaration of their title. The Brandts' deed (which was a land patent) didn’t specify what would happen if the railroad gave up the right-of-way. Mr. Brandt argued that the right-of-way had been an easement, and that once it was abandoned, it was terminated and the easement area belonged to him. The U.S. government argued that after abandonment, title to the right-of-way land reverts back to the government. The U.S. District Court awarded title to the U.S. government and the Tenth Circuit Court of Appeals affirmed.

Chief Justice Roberts reversed the lower courts’ rulings. The Supreme Court’s majority opinion found that the right-of-way was terminated at the time of the abandonment, and that the Brandts owned the property. The Court found that the language, legislative history, and subsequent administrative interpretation of the 1875 Act supported this decision. The Court cited Great Northern Railway Co. v. United States, decided in 1942, in support of its decision. In that case, also decided that under the 1875 Act, the U.S. government granted the railroad only an easement, not fee simple title in the easement property, and therefore, the easement disappeared once it was abandoned. The Court found that in the Brandts' case that the railroad abandoned the easement in 2004 and the government did not have any interest in the land after. Title to the easement property reverted to the Brandt Revocable Trust as the current owners of the land.

Justice Sonia Sotomayor was the only dissenting justice in the case. She stated that there is a judicial precedent for the concept that when Congress granted land to railroad companies, they did not intend to have these land grants end up in private hands. Justice Sotomayor would have decided that, even if this was an easement under the 1875 General Railroad Right-of-Way Act, it was not an ordinary easement and it should have been determined in favor of the United States. Luckily for property owners who have abandoned railroad rights-of-way on their land, Justice Sotomayor's view did not prevail.

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June 13, 2014

EPA Reconsiders 2013 Cellulosic Biofuel Quotas

In October 2013, the American Petroleum Institute and the American Fuel & Petrochemical Manufacturers (AFPM) submitted information to the Environmental Protection Agency (EPA) asking the EPA to lower the 2013 cellulosic biofuel quota because oil refiners would be forced to buy millions of dollars in unnecessary "credits" for cellulosic biofuel because the actual biofuel was unavailable.

In a very helpful (and surprising) turn, on January 23, 2014, the EPA announced that it would reconsider the 2013 quote due to this new information. The EPA determined the information was relevant and met statutory requirement for granting a reconsideration.

The government has hoped that cellulosic biofuel would replace ethanol, which has caused complaints over driving up prices of corn and the damage to engines. However, costs in producing cellulosic biofuels have delayed production, and so production hasn’t kept pace with government quotas. AFPM President Charles Drevna pointed out that the 2013 quota for cellulosic biofuels was six million gallons, which is absurd when only one million gallons were produced. Since they obviously cannot buy biofuel that doesn’t exist, EPA requires oil refiners to buy "credits" instead. API estimated that buying these credits would cost oil refiners $2.2 million in 2013. Mr. Drevna explained that in March 2013 the EPA set the 2012 quota at zero. In reality, these credits are a penalty for not complying with a law that is impossible to comply with!

A spokesman for the biofuel industry said: "These blending targets are based on expected output from a very small number of companies. A short delay, not uncommon for any new refinery, can change the landscape with regard to compliance." Another spokesman for the industry admitted developing cellulosic biofuel has had setbacks and delays but stated the industry would be back on track.

That doesn’t change reality for today, though. Both oil and gas trade organizations received a letter (that you can read here) from EPA Administrator Gina McCarthy. The letter states that the EPA will commence a notice and comment period on the issue of the cellulosic biofuel standards. The letter also stated: “Other objections to the cellulosic biofuel standard noted in your petition may be raised in the context of this future rulemaking if you continue to believe they are relevant. We will respond at a later date to components of your petition for reconsideration of the 2013 RFS rule that are related to matters other than the cellulosic biofuel standard.”

API’s Bob Greco, to whom the letter was addressed, called it “refreshing” that the EPA was willing to reconsider its public policy mandating biofuels that don’t actually exist. He told reporters: “We continue to ask that EPA base its cellulosic mandates on actual production rather than projections that—year after year—have fallen far short of reality. For 4 years running, biofuel producers have promised high cellulosic ethanol production that hasn’t happened.” AFPM President Charles T. Drevn agreed with Mr. Greco and applauded the EPA’s decision: “The agency’s optimism for cellulosic biofuel appears to have been tempered by reality. EPA used common sense when making this decision and we believe common sense should also prevail in resetting the 2013 cellulosic RVO, which would mean that our members will not be required to purchase credits for a fuel that does not exist.” said Mr. Drevna.

The bottom line is that the purchase of unnecessary government mandated "credits" because refiners can't buy a product that does not exist will result in higher prices for fuel. This impacts consumers directly, at the gas pump, as well as indirectly due to increases in the cost of goods and services. These price increases will disproportionately impact lower and middle class consumers and older persons on social security. This is one more example of how the Obama administration puts its political agenda ahead of the welfare of people.

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June 6, 2014

Texas Oil & Gas Operator Fracing Without Fresh Water in Drought Area

Areas of Texas and the western states where much of the U.S. oil and gas potential is located have been hit by drought in recent years, causing worries about water supplies and the use of water in hydraulic fracturing. Fracing takes a lot of water! But Apache Corporation has created a system to frac in the Wolfcamp shale in west Texas without using fresh water. This is an important shale area: just a few months ago Scott Sheffield, the CEO of Pioneer Natural Resources Co., said: "The Wolfcamp could possibly become the largest oil and gas discovery in the world.”

This new approach couldn’t come at a better time, since Texas has been in a drought since 2010 and in November 2013 Texas voters approved Proposition 6, which allocates $2 billion from the Economic Stabilization Fund to the new Texas Water Implementation Fund.

Apache is working with a closed loop system that only uses brackish and recycled water in the Barnhart project area in Irion County. This water is taken from the Santa Rosa Formation in the Dockum Aquifer and treated to remove substances that could damage pipelines and pumping equipment. The treated water is then stored in retention ponds and then can be pumped directly into drilling sites in the area. There is a significant amount of water that returns to the surface after fracing. The U.S. Environmental Protection Agency estimates between 10% to 70% of the injected water, depending on the geologic formation, is returned to the surface. Reusing water that is produced and recovered from fracing conserves fresh water for drinking and agricultural use, and it also saves Apache money since they don't have to haul water in and out. That in turn reduces wear on local roads, and eliminates the need for a used water disposal facility. Greg Hicks, Apache’s production engineer manager, said: “It’s a win-win situation for the environment and us.”

canyon-1434840-m.jpg The Wolfcamp shale is a big area for Apache, which holds 345,000 acres in the area and figures this holds about 347 million barrels of hydrocarbons from 971 identified drilling locations. Apache is not only applying this water-saving technique in the Wolfcamp but also at vertical wells drilled in its Garden City project near Midland and its Andrews project near Odessa.

The first company to get a permit for such a fracing water recycling system was Fountain Quail Water Management, and Apache is now one of their customers. Fountain Quail has two types of semi-mobile water treatment units that can process the recycled water and brine on site. Their Chief Operating Office Brent Halldorson said the Texas Railroad Commission has recently removed some barriers to water recycling by eliminating the need for permits from the Commission and also by reforming some rules to make them more compatible to this technique. A new law was passed in May 2013 that allows producers to take water they recycle and sell it to another company. Before that law, companies were not willing to sell recycled water because of potential liability, but now the liability transfers to the company that buys the water. Mr. Halldorson said he is excited and feels like the oil and gas water recycling industry has finally “broken into the mainstream”.

It is critical for an oil and gas lease or surface use agreement to address (and usually prohibit) the use of your ground water and underground water by an oil company. These new techniques give oil companies a workable alternative to using the landowner's water supply.

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May 30, 2014

Oil and Gas Drilling Boom

As I've discussed before, oil and gas drilling and production benefits Texas mineral owners, but also has a positive impact on the economy as a whole, especially in energy producing states like Texas. There are countless examples in recent years verifying that impact. For example, recently the Manhattan Institute published a report written by Mark P. Mills, a Senior Fellow and founder and CEO of Digital Power Group, entitled, “Where the Jobs Are: Small Businesses Unleash Energy Employment Boom”.

This report indicates that the energy boom, fueled by oil and gas drilling and production, is creating jobs at a faster rate than the economy overall and producing enough wealth by itself to stop a slide back into recession. The report notes that more than 400,000 jobs have been created in the oil and gas sector since 2003. Another two million indirect jobs have been created as well, in transportation, construction and information services in the new shale boom. Oil and gas jobs have grown by 40% since the recession. Other related sectors, like chemical production, manufacturing, steel production, and textiles have also been revitalized due to lower energy costs. In states with oil and gas resources, job creation has greatly outpaced the national average.

While this information is great news, the Manhattan Institute report highlights two key features of the growth that have not been publicized much so far. First, the new jobs are in diverse geographic areas. Sixteen different states have 150,000 or more direct oil and gas jobs. In addition, most of the new jobs aren’t for large oil companies or big multinationals but rather for small businesses. The average oil and gas industry employer has less than 15 employees. These small and medium size oil and gas companies are helping increase jobs not only in direct oil production, but across the economy. These jobs in oil and gas and related industries are also mostly middle-class jobs, not part time or low wage work. Another important point is that this growth reduces the U.S. trade deficit, which is a drag on the economy. Oil and gas produced domestically means less foreign oil and gas is imported, which lowers our trade deficit.

The report noted that the U.S. is the world’s largest and fastest-growing producer of hydrocarbons. In fact, the U.S. has overtaken Russia as the biggest producer of gas.The International Energy Agency even predicts that by 2015, the U.S. will surpass both Russia and Saudi Arabia in oil production.

Almost one million Americans work for the oil and gas industry. The report estimates that 10 million more people are working in jobs related to the industry. The energy boom contributes $300 billion to $400 billion per year to the economy, without which the U.S. might have been stuck in an even deeper recession. The report fairly calls the oil and gas industry “the brightest corner of the economy”.

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May 23, 2014

Changing the Conversation about Well Fracing in Texas

In my law practice, I represent only Texas royalty owners, mineral owners and surface owners, and I do not ever represent oil companies. It is important for both my clients and I to have access to accurate facts, and not emotional arguments, when trying to make the best decisions for a client's property. For that reason, I do pay attention to what oil companies have to say about their operations. From time to time, we might actually learn something!

Clean Fracing Conference

Clearing, the process of hydraulic fracturing, or "fracing" as it is usually called, has been in the media quite a bit. A panel of public relations experts at the Petroleum Connection’s Clean Fracing Conference in Houston, Texas recently argued that the oil and gas industry needs to change the conversation on fracing. For those of us who have been working in this industry, this seems like an obvious statement, but one that badly needs attention. Up until now, critics have been allowed to define the conversation. This debate is particularly important for Texas mineral owners as well as operators since Texas is home to at least three major shale plays that make use of fracing for most wells.

bradford-county-237-140x140.jpg Re-Framing the Debate

The panel argued a change needs to be accomplished by demystifying the fracing process for the public and by highlighting environmental efforts to reduce the impact of drilling and completion. Especially on the environmental issues, we often hear only from opponents of oil and gas development, according to David Holt. Mr. Holt is a spokesperson for the Consumer Energy Alliance and said: “We’re all environmentalists. No one wants to destroy the environment.”

Too often, the entire conversation is driven by fear. Richard Levick, CEO of Levick, a PR firm, noted: “This is not a factual argument. Perception trumps reality 100% of the time.” Mr. Levick suggested getting average people who have benefited from unconventional oil and gas development to share their stories, particularly in videos. He said people are more swayed by peers than by technical experts trying to explain the details of the process. Obie O’Brien from Apache Corporation agreed with the need for nontechnical language to educate the public. He recommended highlighting that frac fluid, which people worry is so toxic, actually contains ingredients found in most household cleaning products, like liquid soap. By way of example, he said: “If I put a bottle of water in front of you and told you it contained 12 oz. of dihydrogen monoxide, would you drink it?” That is actually the chemical name of plain water, but the chemical name confuses people in the same way as trying to explain the chemicals in fracing fluid.

An example of a company trying to change the conversation in a positive way through public dialogue is Cabot Oil & Gas, which is a large producer in the Marcellus Shale. Its spokesperson, George Stark, highlighted the unprecedented, positive response to an annual picnic it began hosting four years ago in the Marcellus Shale region. A few hundred people were expected at the first picnic, but more than 2,500 people showed up. In 2013, they expect more than 10,000 people to come to the picnic. Cabot has also invited community leaders, elected officials, and media reporters to witness fracing jobs to help demystify the process. Hugo Gutierrez, a spokesman for Marathon Oil Corporation, said: “I think we’ve got a good story to tell. But it needs to be simplified and told to a large body of people.”

What some people are not aware of is that the fracing process has been used for almost 100 years. In addition, fracing is an essential process for most wells. In other words, if you can't frac, you can't drill. If drilling isn't possible, a mineral owner will not be able to be receive royalties for their mineral assets. If you are interested, a pretty good nontechnical explanation of the fracing process for a well can be found here and here. Arm yourself with the facts before you decide what you think about fracing.
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May 9, 2014

Tax Consequences of Bonus on Texas Oil & Gas Leases

A decision from the United States Tax Court in December 2013 has interesting implications for Texas oil and gas leases and Texas mineral owners. In Dudek v. Commissioner, the Tax Court examined the characterization of lease bonus and whether bonus is eligible for depletion allowance.

The Dudek decision dealt with three main issues: 1) whether the bonus payment received by the taxpayer pursuant to an oil and gas lease is taxable as ordinary income or as a capital gain; 2) whether the taxpayer is entitled to a depletion deduction; and 3) whether the taxpayer is liable for an accuracy-related penalty under section 6662(a) for a substantial understatement of income tax.

Michael Dudek, the taxpayer and the petitioner in this case, is a certified public accountant and an attorney licensed to practice law in Pennsylvania. In 1996 and 1998, Dudek and his wife, Brenda, bought a total of 353 acres of land. The Dudeks leased the oil and gas rights to EOG Resources Inc., receiving a 16% royalty and a bonus of over $883,000. As many of you know, bonus is consideration for the primary term of the lease and is not contingent on any extraction or production of oil or gas. The Dudeks reported the lease bonus as a long term capital gain on their income tax return.

The Tax Court found that “the receipt of a bonus payment by a lessor pursuant to an oil and gas lease is taxable as ordinary income, not as gain from the sale of capital assets.” The Court cited the U.S. Supreme Court in Burnet v. Harmel, a case from 1932. The Tax Court found that the arrangement was a lease, because the Dudeks retain an economic interest in the property due to the royalty payments as a share of the oil and gas produced. Therefore the bonus was taxable income, not capital gain.

Having lost on the first issue, the Dudeks also argued that even if bonus is ordinary income, they were still entitled to a depletion deduction of $132,488. Section 611(a) of the Tax Code provides that a reasonable allowance for depletion is to be allowed in computing the taxable income derived from oil and gas wells. However, Section 613A(d)(5) provides that percentage depletion for income from oil and gas wells does not apply to “any lease bonus, advance royalty, or other amount payable without regard to production from property.” Since the Dudeks' bonus was not related to extraction or production of oil or gas, they were not entitled to a percentage depletion. Cost depletion is calculated from the taxpayer’s basis for depletion, the amount of the bonus payment, and the royalties the taxpayer expects to receive. In this case, no evidence was presented on the amount of royalties the Dudeks expected to receive, therefore they were not eligible for cost depletion either.

On the last question, whether the Dudeks were liable for the understatement of their federal taxes, the Tax Court found that lack of knowledge on the specific requirement of the tax laws was not a defense. The Dudeks were assessed an accuracy-related penalty.

One of the problems I have with this case is that oil and gas leases, despite their title, are not leases. Instead, they are the simple determinable deeds. While the mineral owner retains a reversionary interest, an oil and gas lease is actually a sale. The bonus is compensation for that sale. Since an oil and gas lease is a sale, it is logical for bonus to be treated as a capital gain. I don't pretend to be a tax attorney, but this outcome seems to be at odds with the reality of an oil and gas lease in Texas. Also note that Internal Revenue Code Section 7463(b) provides that summary opinions like the one in this case may not be treated as precedent for any other case.

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May 2, 2014

Expansion of Texas Oil and Gas Pipeline System

Plains All American Pipeline LP, based in Houston, Texas, is planning to expand its pipeline system in the Permian Basin over the next four years. Parts of that expansion will happen in Texas. These projects bring more money and jobs and exemplify how our oil and gas industry continues to thrive. A healthy oil and gas sector means more royalties paid to Texas mineral owners.

The first of the four projects will be to add pumps to Plains existing 20" Basin pipeline from Jal, New Mexico, to Wink, Texas. This will increase the pipeline’s capacity by 100,000 barrels per day. This first project will also include building a 40 mile long 12" pipeline from Monahans to Crane, Texas, which will supply the Longhorn pipeline and the Cactus pipeline.

The second project is to build 62 mile, 16" and 20" pipelines with a 200,000 barrels per day capacity. This pipeline will go from the South Midland basin in Central Reagan and Central Upton counties in Texas to McCarney.

The third project will be an 80 mile 20" pipeline with a 250,000 barrels per day capacity between Midland and Colorado City, Texas, which would supply connecting carriers like the BridgeTex pipeline.

The fourth planned project will add pumping capacity to the Cactus pipeline to increase Plains expected increase in shipper demand.

All of these projects are expected to be completed in stages throughout 2014 and 2015. They are not Plains only plans. They also have plans for 45 new miles of crude oil pipeline to add to the Mississippian Lime pipeline, which is expected to start service early this year. It will bring the pipeline into Logan County, Oklahoma and Grant County, Oklahoma, to the Plains terminal at Cushing, Oklahoma. Plains also plans to build a 150,000 barrel tankage along the system, as well as have a long-term acreage dedication and storage lease at the Cushing terminal from an area producer.

Pipelines appear to be a safer way to get petroleum products to market, and Texas has a lot of petroleum products to get to market. Plains increased construction of pipelines means that more Texas landowners will be contacted for pipeline easements. Please contact an oil and gas attorney before you sign an easement with Plains or any other pipeline company. It is really the only way to be sure that you protect your land.

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April 25, 2014

Texas Supreme Court to Determine Royalties for Gas Recovered with CO2

The Texas Supreme Court will hear a new case involving royalties on natural gas. Those involved with oil and gas law in Texas will be paying attention, as the case will probably be important. The case is is Occidental Permian Ltd. v. Marcia Fuller French et al, and it is one of the first cases to deal with allocation of the cost of removing carbon dioxide from produced gas following tertiary recovery of that gas with CO2. The appeal was heard by the Eastland Court of Appeals of Texas in October 2012.

The Facts

The Plaintiffs in the trial court, Ms. French and others, were the lessors on two different oil and gas leases in Scurry County and Kent County, Texas. Occidental Permian began injecting wells on these leases with carbon dioxide (CO2) in 2001 in order to boost oil production. As a result, the well produced natural gas that was about 85% CO2. Occidental had the gas treated off site to remove the carbon dioxide and sold the resulting gas. The extracted CO2 was sent back to the well to be reinjected. Occidental paid royalties on the gas after it was treated, and also deducted the treatment costs from the Plaintiffs' royalties.

In Texas, the general rule is that royalties are not subjected to the costs of production, but are usually subjected to post-production costs, including taxes, treatment costs to render the hydrocarbons marketable, and transportation costs. (This can be altered by the language of a specific lease). Ms. French and the other royalty owners alleged that Occidental Permian had underpaid their royalties. They claimed that their royalties should have been paid on all the gas that came out of the well, and not the gas remaining after the CO2 was removed (which was a much smaller quantity of gas). The trial court agreed with the Plaintiffs, and awarded Ms. French and the other royalty owners $10.5 million in compensation.

Eastland Court of Appleals

The Court of Appeals, in a decision written by Chief Justice Jim R. Wright, overturned the decision of the trial court and the $10.5 million judgment. The Court found that the trial court had improperly relied on expert testimony. The expert’s estimate of the market value of the gas at the well was questionable because it was not based on specific past sales of similar gas products that were infused with carbon dioxide. The carbon dioxide levels in the gas in question were far in excess of a level of CO2 as a normal impurity in the gas. The Court of Appeals stated: “Because we have held that it is necessary to render the stream marketable, we also hold that it is a cost of manufacturing that must be deducted in order to determine the net proceeds from the sale, and thus the royalty.”

The Texas Supreme Court

In the Supreme Court, the principal issues are: 1) whether the gas should be valued in its original state, before extraction from the well, or at the wellhead where it is commingled with carbon dioxide; 2) whether removing, compressing, and transporting carbon dioxide should be classified as a production operation; and 3) whether carbon dioxide removal off site for reuse is a production operation. Oral Argument occurred on February 5, 2014, but no opinion has been rendered. You can access the briefs of the parties here.

The decision of the Texas Supreme Court will have a substantial impact on Texas mineral owners who receive royalties from wells where CO2 is used to increase production.

See Our Related Blog Post:

U.S. Supreme Court Case Bears on Texas Land-Use Issues

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April 18, 2014

Ruling Could Prove Important for New Texas Pipelines

A case is winding its way through the courts could be especially important in light of the large number of new oil and gas pipelines being constructed in Texas today. The case was heard by theTexas Court of Appeals in Tyler last year and is currently being heard by the Texas Supreme Court.

The case, Enbridge Pipelines (East Texas) LP v. Gilbert Wheeler, Inc., concerns landowners seeking property damages for the pipeline company's violation of a pipeline right of way easement agreement. There are two main issues. The first issue is whether the cost to restore the property is the proper measure of damages for the breach of contract alleged by the landowners. The second issue is whether the Court of Appeals erred by holding that the landowners waived their claims by failing to submit a jury question on the nature of the property injury.

Factual Background

Gilbert and Katherine Wheeler own a 153 acre tract of land in Shelby County, Texas. The property was wooded and the Wheelers had a cabin where they enjoyed relaxing in the natural surroundings. In 2007, the Wheelers began negotiations for a pipeline easement with Enbridge for a pipeline. From the start, Mr. Wheeler was specifically concerned about maintaining the trees on the property. The easement agreement, drafted by the Wheeler’s son, was signed by both parties and filed with the Shelby County Deed Records. The agreement stated in part that "The Grantee agrees to lay the pipeline by using the boring method and without any excavation on said easement." Alas, when construction began, the Enbridge contractors bulldozed the land, uprooted the trees, and disrupted a stream, all within sight of the cabin! What a nightmare!

Trial Court and Court of Appeals

The Wheelers filed a lawsuit for breach of contract and trespass and sought the cost to restore the property. The trial court found for the Wheelers and awarded them $300,000.00 as costs to restore the property. The Tyler Court of Appeals, in a decision written by Chief Justice James T. Worthen in February 2013, reversed the trial court’s judgment and entered judgement that the Wheelers should recover nothing. The primary basis for this ruling was that the jury was not asked to determine whether the injury to the Wheeler's land was temporary or permanent.

In connection with the damages issue, the Court of Appeals noted existing Texas law:

"Where land is found to have been permanently injured, the landowner is entitled to recover the difference in the value of the property before and after its injury or, in cases where there is no reduction in market value, the landowner may recover intrinsic value damages. See Yancy, 836 S.W.2d at 340; see also Porras v. Craig, 675 S.W.2d 503, 506 (Tex.1984) (discussing recovery of intrinsic value damages arising from destruction of ornamental vegetation). On the other hand, where the injury to the land is found to be temporary, the plaintiff can recover the amount necessary to place it in the same position it occupied before the injury, i.e., the cost to restore. See Trinity & S. Ry. v. Schofield, 72 Tex. 496, 10 S.W. 575, 576-77 (1889); Weaver Constr. Co. v. Rapier, 448 S.W.2d 702, 703 (Tex. App.-Dallas 1969, no writ)". In this case, if the injury was permanent, the Wheelers could be awarded the cost to restore their land. If the injury was temporary, they could recover the diminution in market value due to the destruction, or the intrinsic value of the destroyed trees, vegetation and stream. Because of an omitted jury question, they got nothing. This is an incredibly unjust result.

Texas Supreme Court

Now these issues will be examined by the Texas Supreme Court. Oral argument took place February 27, 2014. No opinion has been published so far. The parties briefs can be accessed here. Whichever way the Texas Supreme Court decides will have repercussions for both landowners and pipeline companies.

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