March 20, 2015

Texas Railroad Commission Oil & Gas Pipeline Permit Rule

Previously I have discussed the revised Texas Railroad Commission (RRC) Rule 3.70 regarding permits for pipelines. You can access my previous blogs here and here. The RRC approved that new rule on December 3. 2014, and it went into effect on March 1, 2015. You can access the text of the new rule here.

There were many comments and suggestions made during the Public Comment period required by Texas law for any new administrative rule. The RRC included a few of these suggestions in the revised rule. However, there were a number of important comments and requests that were neither significantly addressed nor included in the revised rule. These include:

1. The Texas Land and Mineral Owners Association, along with other landowner groups, commented that the new rule does not address the shortcomings highlighted by the Texas Supreme Court in the recent Denbury Green case and that even with the changes, Rule 3.70 still amounts to “registration, not adjudication” and includes no meaningful review of the eminent domain authority. The TLMA suggested adding language for the pipeline company as follows: “Applicant understands and agrees that this registration is not determinative of Applicant’s authority to utilize the power of eminent domain to acquire right of way for the pipeline referenced herein.” They also suggested that the permit should include language stating that: “The RRC is not, by granting this registration, making any determination regarding Applicant’s authority to utilize the power of eminent domain to acquire right of way for the pipeline referenced herein.”

2. Several public comments suggested that the pipeline permit process should include a full investigation of whether the factual assertions in the permit by the pipeline company are correct.

3. A number of public comments indicated that there should be public notice given for a permit as well as a public evidentiary hearing so that affected landowners could have a chance to be heard and so the factual assertions in the permit by the pipeline company could be examined.

The RRC has stated that a pipeline permit is not an authorization to exercise eminent domain for pipeline easements and that the RRC classification of pipelines is used only to determine which RRC regulations apply to specific pipelines. However, when a landowner challenges a pipeline’s common carrier status in court, it is likely that a pipeline company will produce their RRC pipeline permit as evidence of their “common carrier” status. Perhaps the RRC comments to the new rule will eliminate that possibility.

The new RRC pipeline permit rule appears to have significant flaws. In the coming year, we may be able to get an idea of how the new rule functions and whether those flaws will create new problems for landowners.

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January 30, 2015

Texas Supreme Court Decision on Implied Easements

An interesting case that involved easements was recently decided by the Texas Supreme Court. The case is David Hamrick, et al. v. Tom Ward and Betsy Ward and the issue presented to the Court was whether an implied easement of necessity by prior use continues after the necessity has ended. There are two basic types of easements. Express easements, that are created by an agreement (usually written) and implied easements, that arise by operation of the law due to certain specific facts. In Texas, implied easements are split further into a number of subcategories, including easements of necessity and easements by prior use.

grass-landscape-with-road-1440659-m.jpgThe Facts

In 1936 O.J. Bourgeois owned certain property in Harris County, Texas. Mr. Bourgeois gave two acres of the land to his grandson. While the grandson owned this land, a dirt road was built across Mr. Bourgeois' remaining property to allow the grandson access to the public road. Subsequent owners of the grandson's property also used the dirt road for access. Eighty years later, Tom and Betsy Ward were the owners of the grandson’s land and still used the dirt road. The Wards put gravel on the road so they could use it for construction of a new house on their property. The Hamricks owned the land that the dirt road crosses, formerly the property of Mr. Bourgeois. The Hamricks filed a lawsuit asking for a temporary injunction preventing the Wards from using this road. The temporary injunction was granted in April 2006. So as not to delay construction of their new house, the Wards built a new driveway to access the main road. In the suit, the Wards requested a declaratory judgment that they had an implied easement for the dirt road. The trial court granted the Wards motion for summary judgment and the Court of Appeals agreed and held that the Wards had a prior use easement across the Hamricks land.

The Texas Supreme Court Ruling

In a judgment written by Justice Eva Guzman, the Texas Supreme Court reversed the judgment for the Wards and remanded the case. The Court found that the easement was one of necessity, not prior use. Necessity easements have stricter proof requirements than a prior use easement. The Court found that easements for road access for previously landlocked parcels of land must be considered under the necessity easement doctrine. The proponent of the easement must demonstrate a historical necessity for the easement since the time the land was severed and must also show that a continuing, current necessity exists.

The Wards did not plead or offer evidence of an easement of necessity in the first trial. Because this case has been returned to the original trial court, the Wards will have the opportunity to do so.

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January 16, 2015

Fracing Case Goes to Texas Supreme Court

Steve Lipsky and his wife Shyla became famous as Texas landowners who claimed they could set their water on fire--and they alleged this was due to methane contamination from nearby hydraulic fracturing. The couple sued Range Resources who operated a well near their house in Weatherford, Texas. The Lipskys claimed they noticed problems with their water after Range drilled two natural gas wells near their house in 2009.


The Environmental Protection Agency, without any scientific basis whatsoever, concluded that Range had caused or contributed to the water contamination. The Railroad Commission of Texas did actual did scientific testing and determined that the methane came from a shallower rock formation than the one drilled, and allowed production at the wells to continue. Many people do not realize that methane occurs naturally in many water deposits, but is not drawn into the water pump until the water level falls below a certain level. With lots of fanfare, the EPA sued Range Resources in federal court for the alleged contamination. That suit was later quietly dismissed in its entirety.

Range sued the Lipskys and another person, Alisa Rich, for civil conspiracy, aiding and abetting, defamation, and business disparagement over their claims about fracing contaminating their well. The case is In Re: Lipsky. The Lipskys and Ms. Rich filed motions to dismiss all the Range claims. The trial court in Parker County, Texas denied the motions.

The Texas Second Court of Appeals decided that the trial court “clearly abused” its discretion in denying the Lipsky’s motions to dismiss all claims and in ruling that they had no remedy to appeal. The appellate court ordered the trial court to enter an order dismissing Range Resource’s claims based on conspiracy and aiding and abetting. The appellate court left pending Range’s claims of defamation and business disparagement. You can read the appellate opinion here.

The Supreme Court of Texas heard oral argument on December 4, 2014. The issues that will be determined by the Supreme Court are: (1) whether the Texas Citizens’ Participation Act requires heightened proof – clear and specific evidence – of each essential element of a claim under that Act, and if so, (2) whether Range presented clear and specific evidence of defamation and business-disparagement claims.

Given the widespread use of fracing, and the increasing proximity of fraced gas wells to residential areas, this will be an important decision by the Texas Supreme Court. If the Lipskys had a legitimate evidentiary basis for their claims, they should not be the subject of a retaliatory lawsuit. On the other hand, if they did not have a legitimate basis for their claims, then they should be held accountable for any damage their unsupported claims may cause.

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December 26, 2014

Drainage of Oil and Gas in Texas

A federal appellate court decision demonstrates some lessons for Texas mineral owners. That decision was issued by the Fifth Circuit Court of Appeals in the case of Breton Energy, L.L.C., et al. v. Mariner Energy Resources, Inc., et al. The Plaintiffs in this case own and operate an off-shore lease in the Gulf of Mexico that includes an area known as the K-1 sands. The Defendants own and operate an adjacent off-shore lease that covers an area known as the K-2 sands. The Plaintiffs claimed that the Defendants engaged in “unlawful drainage” from the Plaintiffs' lease in violation of federal and state law.

The Facts:

Breton Energy LLC
and Conn Energy Inc. sued International Paper Co. and its successors in interest, consisting of eleven oil companies including Apache Corporation, Chevron and I.P. Petroleum Co. The Plaintiffs claimed specifically that IP Petroleum perforated and drained an oil reservoir under the Plaintiffs' lease on the Outer Continental Shelf in the K-1 sands. The Plaintiffs also claimed that IP co-mingled resources from this reservoir with hydrocarbons from a nearby reservoir, making it impossible for the Plaintiffs to produce oil and gas from its own wells.The evidence showed that I P Petroleum, even though it had been ordered by the federal Minerals Mining Service not to complete wells in both the K-1 and K-2 sands, did in fact complete wells in both areas. There was also evidence that I P Petroleum's production exceeded their estimate by almost 30%, which would make sense if they were producing from someone else's reservoir as well as their own.

The District Court dismissed the Plaintiffs' claims, and they appealed to the Fifth Circuit.

sunrise-series-1446056-1-m.jpg The Opinion

The Fifth Circuit partially vacated the District Court’s order, in part affirmed the order , and remanded part of the case back to the District Court in a decision written by Judge Stephen Higginson. The Fifth Circuit held that the Plaintiffs had pled sufficient facts to state a claim of waste against IP, but not against the other Defendants. The Court also determined that the Plaintiffs had made a plausible allegation that IP contributed to waste from the reservoir, which was enough to pass the pleadings test in the U.S. Supreme Court's decision of Bell Atlantic Corp. v. Twombly. The Court found that the neighboring reservoir had been overproduced and this supported the Plaintiffs' claim that minerals were commingled and that recoverable hydrocarbons had been lost. In upholding the District Court’s dismissal of claims for unlawful drainage against other Defendants, the Fifth Circuit relied on Louisiana law that prohibits landowners from filing claims against neighbors who drain liquids or gases from under their property.(Louisiana law allows production of oil and gas that migrates from other people's properties. Texas has pooling regulations to prohibit one person from benefiting from their neighbors minerals).

Breton Energy called the decision of the Fifth Circuit a “great ruling for us” and said that “(t)he focus from the beginning and the target was IP, because they actually performed the perforation. The other parties were sued on the grounds that they should have been aware of the perforation and done something about it.” Breton Energy and Conn are currently preparing for a new trial in the District Court.

One of the lessons of this case is that it is difficult to successfully prosecute an oil and gas drainage and waste claim. Both parties in this lawsuit retained a lot of expensive petroleum engineering and geology talent to try to prove their side of the case. While the Plaintiffs in this particular case survived a dismissal based on their pleadings, it is not at all clear that they will prevail on the merits. It will be very interesting to see how this case turns out.

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November 28, 2014

Texas Railroad Commission Proposed Oil & Gas Pipeline Permit Rule Amendment

The Railroad Commission of Texas (the RRC) is planning to amend their permit rule for oil and gas pipelines. The section to be amended, section 3.70, involves the pipeline permit procedure. The RRC invited comments on the changes until August 25, 2014. The issue has become a hot topic, especially since Texas already has substantial case law on what constitutes a common carrier.

Current Texas Law

Texas law requires that to be considered a common carrier a pipeline must serve a “public purpose” in carrying products for third parties for compensation, as discussed in the Denbury Green opinion by the Supreme Court of Texas. (You can access my previous blog post about this case here). In the Denbury Green case, the Supreme Court said that when a landowner challenges a pipeline's claim of common carrier status, the burden is on the pipeline company to prove it meets the definition of a common carrier.

Under the RRC rules in effect and discussed in Denbury, a pipeline company merely had to check a box on the permit form indicating that they are a common carrier. This has lead to litigation about whether a pipeline actually qualifies as a common carrier or not.

The proposed amendment intends to allow a private carrier to have common carrier status as long as certain documentation is supplied to the RRC. The documentation would include a sworn statement by the company detailing its common carrier claim. The RRC would then have 45 days to review the documentation. The RRC would have power to revoke the permit if the company violates the law and requires permits be renewed on an annual basis.

The issue of common carrier status is an important one because common carrier status confers the right of eminent domain (also known as condemnation) to obtain easements for the pipeline. If a pipeline that is not classified as a common carrier must negotiate an easement with landowners, much like any other private real estate transaction.

As a Texas lawyer who spend a considerable amount of time negotiating pipeline easements, I'm concerned that the rule change may not be good for landowners. There is a lot of definitive Texas law defining common carrier status, and now the Railroad Commission proposes replacing that law with an administrative determination. There should also be a way for a landowner to challenge the RRC determination that a pipeline crossing that owner's land is common carrier, and that is not included in the proposed change although the RRC claims the ultimate authority to determine common carrier status will remain with the courts. Finally, the landowner has the best incentive to keep the pipeline companies honest by having the ability to challenge common carrier status. This is not to cast any aspersions on the RRC: they generally do a good job. However, there are 426,000 miles of pipeline in Texas, and one wonders where the staff and funds will come from to do a thorough review in this era of diminished budgets.

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November 25, 2014

Texas Railroad Commission Approves Revised Oil & Gas Pipeline Rule

The Texas Railroad Commission approved a substantial amendment to its oil and gas pipeline permit rule on December 2, 2014, and the amendment has major significance for Texas landowners and Texas mineral owners. The rule is Texas Railroad Commission Rule 3.70, and the amended rule goes into effect on March 1, 2015.

The Railroad Commission received a substantial amount of written comment from individuals, oil companies and trade organizations. Comment and testimony was also received at the public hearing on the proposed amendment held in Austin, Texas on September 22, 2014. The amended Rule 3.70 and the discussion of public comments by the Commission's General Counsel can be accessed here.

The amended Rule 3.70 provides that each operator of a pipeline or gathering system (other than production lines or flow lines that are general confined to the leased premises) must obtain a permit from the Commission and renew the permit annually. The permit application must now include the following:

1. the contact information for the person who can respond any questions concerning the pipelines construction, operation or maintenance;

2. the requested classification and the purpose of the pipeline as a common carrier, a gas utility or a private pipeline;

3. a sworn statement from the permit applicant that provides the pipeline operator’s factual basis in support of its requested classification and purpose, including, if applicable, attestation to the applicant’s knowledge of the eminent domain provisions in the Texas property code and the Texas Landowners Bill of Rights published by the Texas Attorney General;

4. documentation to provide support for the classification and purpose being sought for the pipeline and any other information requested by the Commission.

The memorandum to the Railroad Commission from its General Counsel on November 25, 2014, (which you can read here), summarizes many of the written and verbal comments about the proposed amended rule. Many commentators wanted the Commission to take a more active role in the route of a pipeline and in the determination of whether a pipeline was a common carrier pipeline or not. In Texas, whether a pipeline is a common carrier pipeline is hugely important. A common carrier pipeline has the right of condemnation (or “eminent domain”) if they cannot reach a pipeline easement agreement with the landowner. Other types of oil and gas pipelines do not have this power.

The comments in the memorandum by the Railroad Commission General Counsel make clear that the Commission does not believe it has authority to adjudicate whether a pipeline is a common carrier or not. The memorandum also notes that the Railroad Commission has no authority over the routing of a pipeline nor do they have authority to become involved in private property rights, including pipeline easement negotiations.

On the other hand, the amended rule provides that the Railroad Commission will make a determination of the “sufficiency” of the information provided with the permit application. What will constitute “sufficient” documentation of common carrier status remains to be seen. In addition, the Commission's press release about the amendment states that: "Texas Railroad Commissioners have unanimously adopted pipeline permit rule amendments designed to clarify how a pipeline operator may be classified by the Commission as a common carrier." That statement makes it sound as if the Commission is making a "common carrier" determination!

Readers may recall that in 2012, the Texas Supreme Court, in the case of Texas Rice Partners Ltd. vs. Denbury Green Pipeline, 363 S.W.3d 192, held in part that the fact that a pipeline permit applicant checked a block on the permit application that indicated that it was a common carrier pipeline did not in fact make the pipeline a common carrier line. That case is still good law. The amendment to Rule 3.70, while not providing for a forum or process for determination of whether a pipeline is a legitimate common carrier or not, will still be helpful to landowners who are negotiating a pipeline easement. The information that the Railroad Commission requires a pipeline operator to supply with its permit application should be the first thing that a landowner or their oil and gas pipeline attorney looks up when negotiating a pipeline easement.

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November 14, 2014

Important Gas Royalty Case for Texas Mineral Owners

Recently the Fifth U.S. Court of Appeals issued an interesting decision in the case of Warren et al. v. Chesapeake. This very important case for Texas mineral owners is based on a lawsuit against Chesapeake Exploration for what the Plaintiffs claimed was the wrongful deduction of post-production costs from the Plaintiffs' gas royalty payments.

The Facts

The Warren case involves three oil and gas leases in Texas. Charles and Robert Warren entered into leases with FSOC Gas Co. Ltd. Those leases were then assigned to Chesapeake, who used an affiliate, Chesapeake Operating, to drill and operate the wells. Chesapeake deducted post-production costs from the royalty payments to the Warrens as well as from royalties to Abdul and Joan Javeed who joined the case as plaintiffs later. Chesapeake claimed that the leases authorized the deductions. The Plaintiffs asserted that Chesapeake breached the leases because the deductions did not comply with the lease provisions on calculating royalties. The complaint also included class action allegations on behalf of other royalty owners with similar leases with Chesapeake Exploration.

The U.S. District Court Proceedings

The Plaintiff based their claim in part on the previous decisions of the Texas Supreme Court in Heritage Resources, Inc. v. NationsBank and Judice v. Mewbourne Oil Co.. The District Court dismissed the claims of all four Plaintiffs with prejudice. That court held that since the leases contained “at the well” royalty provisions, Chesapeake was authorized to make post-production deductions in determining the income on which royalties would be based despite the provisions in the Warren leases that the royalty would be free of certain post-production costs.

The Fifth Circuit Decision

The Plaintiffs appealed their case to the Fifth Circuit Court of Appeals. The Warrens claimed that their leases contained two sets of obligations owed by Chesapeake. The first involved the costs of exploration, production and marketing of gas, including the costs of compression, dehydration, treatment, and transportation. The second are shared obligations such as costs incurred subsequent to production. The Warrens claimed the deducted expenses fell under the first set of obligations and so were the obligation of Chesapeake alone. The Fifth Court of Appeals did not agree with this argument and upheld the District Court’s dismissal with prejudice on this issue. The Fifth Circuit held that the language of the lease expressly provides that the lessor will bear a proportionate part of the expenses of delivering marketable gas to a sales point other than the mouth of the well.

The next issue the Court addressed concerned the leases of both the Warrens and the Javeeds. The Javeeds lease contained differently worded royalty provisions than the Warren leases, but the appellate briefs to the Court focused on the Warrens’ leases, not addressing the differing provisions. The District Court had treated the Javeeds leases as “functionally equivalent” to the Warrens. For the first time in the reply brief before the Fifth Circuit the Plaintiffs addressed the differences, but these arguments were waived because they were asserted too late. The Fifth Circuit determined that the Javeeds claim should be dismissed without prejudice anyway because it was apparent from the face of the complaint and its attachments that they could not conceivably state a cause of action.

This case illustrates that language in oil and gas leases concerning the calculation of royalty can be technical and complicated. It is essential for a mineral owner to fully understand the terms of an oil and gas lease and what may or may not be deducted from royalties before it is signed. Take the time to consult an attorney before signing. It will save money and stress later.

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October 24, 2014

Gas Royalties Case Decided by Texas Supreme Court

As readers of this blog know, we have been following the case of Marcia Fuller French, et al. v. Occidental Permian Ltd., which is an important Texas case involving gas royalties. You can read our previous blog post here. The case was heard by the Supreme Court of Texas on February 5, 2014 and the The Texas Supreme Court has issued its decision.

As you may recall, Martha Fuller French and the other Plaintiffs were royalty owners and lessors on two oil and gas leases in Scurry County and Kent County, Texas. One lease is referred to in the decision as the “Fuller Lease”, which was executed in 1948, and the other lease is referred to as the “Cogdell Lease”, which was leased 1949.

In 2001, Occidental Permian began injecting wells on these leases with carbon dioxide to boost oil production. As a result, the natural gas produced from these leases contained about 85% carbon dioxide. Occidental then treated the gas to remove the carbon dioxide and sold the remaining gas, sending the carbon dioxide back to be reused at the well. Occidental paid Ms. French and the others royalties on the gas after it was treated and then deducted treatment costs from the royalties.


In Texas, the general rule, which can be modified by the language in a lease, 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. Ms. French and the other Plaintiffs claimed that they should have received royalties on all gas produced, that Occidental should not have deducted post production costs, and since these costs were deducted from their royalties, they were underpaid by Occidental. The trial court agreed with them and awarded them $10.5 million in compensation. The case then went to the Texas Court of Appeals in Eastland, Texas, which overturned the judgment of the trial court and vacated the $10.5 million award.

In the Texas Supreme Court, the principal issues were: 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.

In a decision written by Chief Justice Nathan Hecht, the Texas Supreme Court affirmed the decision of the Court of Appeals. The decision held that carbon dioxide removal is a post-production expense that royalty owners share with the field operator. In the leases in this case, the Plaintiffs gave Occidental the right and discretion to decide whether to reinject or process the casinghead gas (which is gas produced with oil in oil wells, which is different from gas produced in a gas well) and since the Plaintiff royalty owners benefited from that decision, the royalty owners must share the cost of carbon-dioxide removal. The Court pointed out that the Fuller Lease specifies that the cost must be considered when determining the market value of the gas, and it is this figure that the royalty is based on. The Cogdell Lease provided that the cost of off-site manufacturing of the natural gas liquids and residue gas is deducted from royalties.

This decision contains two important lessons. First, an oil and gas lease may last for decades. Secondly, whether or not costs are deducted from your royalties can make a substantial difference in the amount of your royalty check. This case illustrates once again how critical it is to have an experienced oil and gas attorney review the fine print before you sign an oil and gas lease.

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September 26, 2014

Texas Property Owners Receive Large Award in Fracing Nuisance Claim

An interesting case was in the news recently and oil and gas attorneys have been following it with interest. The case is Lisa Parr, et al. vs. Aruba Petroleum, Inc., et al.; County Court at Law No. 5, Dallas County, Texas; Cause Number: CC-11-01650.

The Background

The Parrs have a 40 acre ranch in Decatur, Texas which is about 60 miles northwest of Dallas, Texas. The ranch sits on the Barnett Shale. Robert and Lisa Parr and their 11 year old daughter Emma alleged that they started having health problems in 2008, including migraine headaches, dizziness and nausea. By 2009, Lisa Parr said: "(m)y central nervous system was messed up. I couldn't hear, and my vision was messed up. My entire body would shake inside. I was vomiting white foam in the mornings." She claimed that her husband and daughter had nosebleeds, vision problems, nausea, rashes and blood pressure issues.

The Lawsuit

The Parr family filed a lawsuit against Aruba Petroleum and a number of other well operators with wells in the area in 2011, requesting $66 million in damages. Aruba Petroleum had 22 natural gas wells within two miles of the Parr’s land, with three wells close to the Parr’s house: the closest well was 791 feet from their house. The lawsuit claimed that Aruba Petroleum poorly managed the wells and did not have proper emissions controls, leading to a “private nuisance” of air pollution and the family's exposure to emissions, toxic air pollution and diesel exhaust. They claimed they got so sick that they could not work, and sometimes had to stay in Robert Parr’s office to escape the toxic environment.

Aruba claimed that: 1) the Parrs had no evidence that proved that diminished air quality at their home was due to the drilling of its wells; 2) Aruba had eliminated any environmental problems immediately and any contaminants were within air quality standards set by the Texas Commission on Environmental Quality; 3) all operations of Aruba's wells complied with requirements of the Texas Railroad Commission; 4) the operation of the wells complied with all federal law and standards; and 5) any substances released into the air near the wells could not have made anyone sick.

The original lawsuit was not only against Aruba Petroleum, but also other oil and gas companies operating nearby. Halliburton won summary judgment against the Parrs last year. Other companies, including a subsidiary of ConocoPhillips Co., settled with the family.

The Judgment

In April 2014 the jury in the Dallas County Court of Law No. 5 awarded the Parr family $3 million dollars in a five to one jury verdict. The jury found that Aruba Petroleum took intentional steps to substantially interfere with the Parr family’s use of their home. The jury did not find that Aruba acted with malice however, and so the Court dismissed the Parr’s claims for exemplary damages. The award included $275,000 for loss of value to their property, $2 million for past physical pain and suffering of the three, $250,000 for future pain and suffering, and $400,000 for mental anguish. The judgement was signed by Judge Mark Greenberg on July 19, 2014. Judge Greenberg signed an order denying Aruba's motion for new trial on September 10, 2014 and Aruba has posted a supersedeas bond, which prevents the Plaintiffs from collecting the judgement until all appeals are exhausted.

Aruba said that it plans to appeal the decision to the Fifth Circuit Court of Appeals. An Aruba representative said: “There were hundreds of wells drilled in the area. Trying to tie the diminution of property value and the health effects to Aruba alone makes no sense.”

I am all in favor of oil companies paying for whatever damage they may cause. I have to confess that I am a bit mystified as to how the Parrs could prove, by a preponderance of the evidence, that it was only the Aruba wells that caused their problems, when there were dozens of other wells in the area. It will be interesting to see what the Fifth Circuit Court of Appeals does with this case.

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August 22, 2014

The Risk of Signing Something You Don’t Read

As a Texas oil and gas attorney, I often explain to clients how important it is to be smart and review oil and gas leases, contracts and other legal documents before signing anything. So many people sign documents without reading or understanding them first and come to me after the fact, when it is much harder and often impossible to do anything about it--money and peace of mind have already been lost. I recently read a case, Ayala and Chesapeake Exploration LLC v. Soto, that exemplifies exactly this situation.

Natividad Soto is a 75 year old man and land and mineral owner in LaSalle County, Texas. He cannot read or write in English. He was approached by Henry Gilbert Ayala, a prison guard and mayor pro tem of Cotulla, Texas who was an acquaintance of Soto's niece. Mr. Ayala allegedly pressured Mr. Soto into signing what Mr. Soto thought was an oil and gas lease. Mr. Soto actually signed a durable power of attorney to Ayala, giving Ayala authority to sign oil and gas leases and certain other documents for Mr. Soto.. Mr. Soto claims no one explained what the document was and he did not seek assistance from anyone before he signed. Mr. Ayala filed the power of attorney in the county deed records and then signed two mineral leases with Chesapeake Exploration.

A few days later, Mr. Soto consulted an attorney. The attorney prepared and filed revocations of the power of attorney with the county clerk’s office. A few weeks later, Chesapeake sent a check of almost $239,000 as lease bonus to Ayala. Ayala kept the money and claimed that Soto agreed that Ayala could keep the bonus funds as his fee.

The trial court agreed with Mr. Soto and entered summary judgment on Soto's claims to quiet title and cancel the lease. The court declared the lease and memorandum of the lease null and void. Chesapeake and Mr. Ayala appealed the judgment. The Fourth Court of Appeals in San Antonio, in a decision written by Justice Karen Angelini, reversed the trial court’s decision. The Court of Appeals found that the mineral lease with Chesapeake was valid, that Chesapeake was a bona fide purchaser and that Chesapeake never received actual notice of Mr. Soto’s revocation of the power of attorney.

What a sad result for Mr. Soto. Had he just sought out his attorney before he signed the power of attorney, all of this could have been avoided. The case has been appealed to the Texas Supreme Court, but no date for submission has been set yet.

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August 15, 2014

Texas Supreme Court to Decide Oil Royalties Case

The Supreme Court of Texas will be considering an interesting case about oil and gas royalties for a Texas mineral owner. The case is Charles G. Hooks III et al. v. Samson Lone Star L.P.

The case arises from a dispute over oil and gas leases in Jefferson County and Hardin County, Texas. The mineral and land owner is Charles G. Hooks, III, who is also an oil and gas attorney. The Jefferson County lease provided that the lessee, Samson Lone Star LLC pay compensation to Mr. Hooks if drilling occurred within 1,320 feet of his property line. Samson drilled a directional well that bottomed out within that distance, but Samson never compensated Mr. Hooks as the lease required. With the two Hardin County leases, Mr. Hooks gave Samson permission to pool his mineral interests, but Mr. Hooks contended that Samson did not pay him for all production within the pool. Mr. Hooks also claimed that Samson was required to pay both royalties on the sale of oil and gas and on the same oil and gas as it existed in the reservoir, so called “formation production”.

In the trial court, Mr. Hooks was awarded more than $21 million on these claims. The case was appealed to the Houston Court of Appeals, which reversed the judgment of the trial court in a majority decision written by Justice Evelyn V. Keyes in 2012. The Houston Court of Appeals determined that, as to the Jefferson County lease, Mr. Hooks' claim was barred by the statute of limitations and was based on an incorrect interpretation of his oil and gas lease. The Court noted that surveys on file for this well at the Texas Railroad Commission in 2000 and publicly accessible put Hooks on notice of the location of the bottom of Samson's directional well, and as an oil and gas lawyer, Hooks should have been aware of his claim if he reviewed both those surveys. Unfortunately, Hooks did not file the lawsuit against Samson until after the four year statute of limitations that applied to his claim had expired.

On the Hardin County leases, the Court also determined that Mr. Hooks' claim was barred by the statute of limitations. The Court wrote: “We conclude that Hooks knew or should have known of information that would have led to the discovery of the alleged fraud no later than February 2001, as the necessary information was a matter of public record at that time.” In addition, the Court of Appeals determined that Mr. Hooks other claims were based on misinterpretations of the leases.

The appeal to the Texas Supreme Court is set for oral argument on September 17, 2014. The Texas Supreme Court’s summary of the issues states that the principal issue is “whether a mineral-rights owner exercised reasonable diligence, to avoid limitations, by obtaining a copy of the Samson plat filed with the Texas Railroad Commission but not a third-party survey in Railroad Commission records that would have shown the operator’s fraud.” Other issues are whether Mr. Hooks ratified the pooling agreement by accepting royalties from the new unit; whether Samson Lone Star must pay royalties on the “most favoured nation” clause in these leases; whether an agreement for attorney fees is applicable on Hooks' claims when liability and damages were stipulated and not pled; and whether post-judgment interest on royalties paid late should be 18% or the normal Texas judgment rate of 5%.

Whatever the Texas Supreme Court decides, the facts of this case illustrate an important caution: if you think there's a problem with your oil and gas lease, your royalties or the activities of the operator, investigate your suspicions now rather than later. If you wait, the statute of limitations may prevent you from correcting the situation or from recovering damages to which you may otherwise be entitled.

See Our Related Blog Posts:

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August 8, 2014

Oil and Gas Investors: Beware of Oil and Gas Scams!

A recent case decided by the U.S. Sixth Circuit Court of Appeals holds a cautionary tale for Texas investors or any one who may want to invest in oil and gas. The case is United States v. Smith decided on April 15, 2014.

This case involved the Smith brothers, Michael and Christopher, who operated a company called Target Oil. Target conducted speculative oil drilling in several states, including Texas, but also in Kentucky, West Virginia, and Tennessee. The Smiths told potential investors that certain wells were sure-fire investments, but these wells often produced no oil at all. In fact, some of the wells had not even been drilled. Investigators discovered that from 2003 to 2008, Target Oil received approximately $15.8 million from investors, but only distributed royalties amounting to $460,000. Their operation was a classic Ponzi scheme. That means that the Smith brothers paid new investors from the investment funds of previous investors, rather than from the production proceeds from the wells they were supposed to be drilling. As in all Ponzis, for the first few months the investor thinks they've made a good investment. At some point, as in all Ponzis, the fraudsters run out of new investors to scam and the returns to investors stop. The newer investors get nothing at all. These kinds of schemes seem to come out of the woodwork when the price of oil approaches $100 per barrel.

Michael and Christopher Smith were arrested and charged with conspiring with others to defraud investors of millions of dollars. In the trial court, Michael Smith was convicted of conspiracy to commit mail fraud and of 11 substantive counts of mail fraud. He was sentenced to 120 months in prison and ordered to pay $5,506,917 in restitution. Christopher Smith was convicted by the same jury on seven counts of mail fraud. He was sentenced to 60 months in prison and ordered to pay $1,652,075 in restitution. The Sixth Circuit Court of Appeals affirmed the convictions in an opinion written by Justice Ronald Lee Gilman. The Court rejected the Smith brothers’ complaints of insufficient evidence, that the government introduced evidence that effectively amended the indictment, that a defense witness was erroneously excluded, that their sentences were procedurally and substantively unreasonable and that their forfeiture judgment was excessive.

I don't think the sentences were harsh enough! This case involving the unscrupulous Smith brothers is just one example of many oil and gas investment scams, including many that affect Texas residents. It is a vivid reminder of the need to get advice before you invest. A background check by an oil and gas attorney is absolutely critical before making these kinds of investments. A background check is not a guarantee that the investment is not a scam, but it can usually uncover a number of facts that are strong indicators of fraudulent activity. For example, a background check can determine if a company really owns the leases and wells that they say they own.

I get two to three calls each month from people who invested huge sums in Ponzi schemes just like the one run by the Smith brothers and who are trying to get their money back. In a few cases, I am able to do so. In many cases, the criminals have spent the funds and a civil lawsuit would be an empty exercise. Save yourself some heartache and have an attorney do some investigating before you invest! The fee is quite modest and it is just good business to get some independent verification for a substantial investment.

See Our Related Blog Posts:

Is Deep Subsurface Waste Water Migration a Trespass in Texas?

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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.

See Our Related Blog Posts:

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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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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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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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April 11, 2014

Is Deep Subsurface Waste Water Migration a Trespass in Texas?

The Texas Court of Appeals in Beaumont, Texas recently decided a very interesting the case that has huge implications for Texas land and mineral owners: Environmental Processing Systems LC v. FPL Farming Ltd. The Texas Supreme Court recently heard oral argument on this case.

The Facts

As many Texas mineral owners are aware, salt water is often produced by an oil well in conjunction with the oil. Generally, this salt water is required by law to be collected and taken to saltwater injection wells that are licensed by the Texas Railroad Commission. The salt water is then injected back into the subsurface, where it came from. But one cannot always control where the saltwater goes after it is injected.

Environmental Processing Systems ("EPS") operates injection wells in Liberty County, Texas for the disposal of industrial waste water. FPL Farming ("FPL") alleged that waste water from these wells could or did migrate into and contaminate its aquifer. FPL had no present plans for the water in this aquifer, but was concerned that contamination would diminish the value of its land. The injection well itself was 400 feet away from FPL's land, but EPS injected more than 100 million gallons of waste water into the injection well in question, making the underground footprint potentially substantial. There was evidence at trial that salt water already existed naturally at the depth used by the injection wells. This is important because salt water is also considered a waste product that is injected into disposal wells. The aquifer in question was more than a mile below the surface, but FLP alleged that they may want to use that water in the future. FPL did not claim that EPS’s pollutants have migrated to the surface or are affecting drinking water. Apparently, FPL had no evidence that migration had actually occurred: FPL brought suit because they feared "that EPS’s waste plume had or was about to enter the subsurface of its property". FPL claimed that the waste water intrusion, whether threatened or actual, was a trespass and sought injunctive relief and damages for trespass and for negligence and unjust enrichment.

The Rulings

The jury in the trial court found that no trespass had occurred, that EPS was not negligent, and that EPS had not been unjustly enriched. The Beaumont Court of Appeals affirmed the trial court decision and FPL appealed to the Texas Supreme Court. The Texas Supreme Court in FPL Farming Ltd. v. Envtl. Processing Sys., L.C., 351 S.W.3d 306, 308, 314 (Tex. 2011), held that the fact that EPS had a permit from the Texas Railroad Commission for the injection well was not a shield against trespass and damages and sent the case back to the Beaumont Court of Appeals to consider all issues raised by the parties. The main issues were whether a trespass can exist for deep subsurface-water migration; whether a lack of consent must be proven as an element of trespass or whether it is an affirmative defense; and whether the trial court should have issued a directed verdict on the consent issue because FPL could not have consented to a trespass that did not occur.

On remand, EPS claimed that common law trespass does not extend to deep subsurface water migration. FPL contends that Texas landowners own the subsurface water below their land and should be allowed to use Texas trespass law to protect their subsurface rights.

Some oil and gas industry groups have filed amicus briefs supporting EPS. They worry that a decision in favor of FPL could expose oil and gas operators and injection well operators to substantial litigation, even when there is no evidence of migration. For example, a landowner who disagreed with energy development on nearby lands could threaten costly litigation over injection wells in order to obtain a better oil and gas lease. Of course, no one can guarantee that someone won't file frivolous litigation. It happens. However, the possibility of frivolous litigation should never prevent the law from allowing a landowner to protect a valuable property right like subsurface water. This is especially true as water becomes more and more scarce and thus more and more valuable.

There has not yet been a case in Texas that recognizes a trespass via salt or waste water of a deep aquifer. Therefore, the outcome in this case will be closely watched by landowners, injection well operators and oil companies alike. Oral argument before the Texas Supreme Court took place on January 7, 2014. At the hearing, the justices did not show any signs of how they were leaning, except that Justice Paul Green said he had a hard time understanding a trespass that was under tons of rock and earth and noted it would be hard to determine when the trespass took place and how much of the groundwater was damaged.

Actually, the technology does exist to determine at least whether there is migration from an injection well to an aquifer by the use of dyes and radioactive particles. I searched the briefs of both parties (which you can access here), but neither indicated that this kind of testing had been done in this case. Obviously, without testing, it isn't possible to determine if migration from an injection well has occurred.

This case involved waste water injection, not salt water. However, because salt water is so often produced along with oil, because the law requires that it be disposed of properly, and because that disposal often involves injecting it into a well, this case will be of great interest to Texas landowners and the operators of injection wells to see how the Texas Supreme Court decides. Stay tuned.

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March 21, 2014

Texas Supreme Court to Address Use of Surface by Mineral Interest Owner

The Houston Court of Appeals in Texas recently addressed the issue of surface owners rights in the case of Key Operating & Equipment Inc. v. Will and Loree Hegar. The case involves the use of the surface of the Plaintiffs' land by an oil and gas operator. In Texas, the owner of the minerals generally has an implied easement for reasonable use of the surface in order to explore, develop and extract the minerals. In this case, the mineral owner wanted to make continued use of a road on the Plaintiffs' surface estate to access minerals on other tracts, after that surface estate had been severed from its minerals, and after the minerals under the Plaintiffs'' tract and the minerals under the other tracts had been pooled.

The Defendant, Key Operating and Equipment owned mineral rights and operated wells on two tracts of land (the Richardson and Rosenbaum-Curbo tracts) in Washington County, Texas since the late 1980's. The mineral leases allowed for pooling, and in 2002, Key pooled mineral interests in the two tracts, and used the road across the Curbo tract to access their two producing wells on the Richardson tract. At the time of the suit, there was no longer a producing well on the Curbo tract. In 2002, the Hegars bought the surface of the Curbo tract and a 1/4 interest in the minerals. They knew about the lease and the road--which they used themselves to get to their house. They objected, however, when Key drilled a new well on the Richardson tract and used the road more frequently. Mr. Hegar stated, “We’re trying to raise a family and we can’t do it with a highway going through our property.” So in 2007, they sued Key for trespass and asked for a permanent injunction to prohibit Key from using the road. The Hegars claimed that no oil is actually being produced from the Curbo tract and Key only pooled the interests in order to continue to use the access road. Key claimed that the Curbo oil is migrating towards the Richardson tract, and that is why they pooled the two tracts.

The trial court agreed with the Hegars and permanently enjoined Key from using the road “for any purpose relating to the extraction, development, production, storage, transportation, or treatment of minerals produced from an adjoining” tract.

On appeal, Key argued that the both its oil and gas leases and the pooling of the two tracts authorized the use of the road. The Hegars contended that the road could be used only for production of minerals from the Curbo estate but could not be used for the production of minerals from adjacent tracts despite the pooling of the two tracts, since the pooling declaration had been executed after the severance of the surface and minerals of the Curbo tract.The Hegars contended that Key's use of their surface is limited to the rights that existed when the surface and minerals in the Curbo tract were severed, and the severance occurred before the oil and gas leases and the pooling agreements were executed.

The Houston Court of Appeals agreed with the Plaintiffs that the Key leases and pooling agreement were not part of the Plaintiffs' chain of title and did not bind them. However, the Court decided that Key had “the right to use the surface of the Curbo tract to produce oil from beneath the surface, regardless of whether that oil is co-mingled with oil from other tracts.” The Court explained that Key's right to use the road can arise from the usual implied easement of a mineral owner to use the surface, so long as some of the oil is being produced comes from beneath the Curbo tract. The Court of Appeals noted that there was evidence at trial that the oil being produced from the wells on the Richardson tract did not from beneath the Curbo tract. As a result, the Court of Appeals affirmed the issuance of the permanent injunction prohibiting Key's use of the road across the Plaintiffs' property.

This case illustrates the tensions that often arise between a surface owner and the mineral owner. It will be interesting to see what the Texas Supreme Court decides.Oral argument before the Texas Supreme Court occurred on February 4, 2014 but the opinion has not yet been issued.
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March 7, 2014

Fracing Bans Challenge Independent Oil & Gas Producers

Faced with a rising tide of sweeping municipal legislation banning hydrocarbon extraction, mineral owners and oil and gas operators are taking the fight to court. The Independent Petroleum Association of New Mexico, along with an individual landowner and two limited liability corporations, are suing Mora County, New Mexico, alleging that the ordinance passed by the county violates the Plaintiff’s constitutional rights and exceeds the authority of the county council.

The Mora County ordinance, the first of its kind in the United States, is described by the county as a measure to protect the local water sources and the communities that rely on them. However, the ordinance specifically targets oil and natural gas extraction. The suit alleges that the real purpose of the ordinance, rather than protection of natural water sources, is to prevent lawful development of oil and natural gas resources within Mora County. The ordinance prohibits the extraction of water for use in the extraction of subsurface oil or gas, and also prohibits importing water into the county for that purpose. The ordinance further provides that no permits, licenses, privileges or charter issued by any state or federal agencies that violate the ordinance will be valid. The ordinance passed by Mora County is a variation on an ordinance developed by Pennsylvania attorney Thomas Linzey and adoption of similar ordinances is being considered by dozens of communities across the country.

The Independent Petroleum Association argues that the ordinance violates the substantive due process rights of the organization’s members and exceeds the authority of the county council. They further argue that the ordinance violates fundamental property rights, and that the ordinance does not meet the strict scrutiny standard because the ban is not narrowly tailored to serve a compelling governmental interest. In particular, they note that even though the stated purpose of the ban is to protect the water supply, the ban applies only to hydrocarbon extraction while ignoring the agricultural industry, a source of significant water pollution.

In Colorado, voters in Fort Collins and Boulder banned fracing for the next five years, and voters in Lafayette passed a prohibition on new oil and gas wells. Colorado Governor John Hickenlooper is suing to overturn the city of Longmont’s fracing ban, passed one year ago. The Governor, a former mayor of Denver, insists that cities do not have the power to ban fracing. Activists in some states are reportedly planning to seek statewide bans, and there is apparently some public support for a statewide ban in California.

The specific powers of cities and counties vary from state to state and depend on state constitutions and “home rule” provisions. The law regarding whether city or county ordinances are pre-empted by state law also varies from state to state. Attorneys from the Independent Petroleum Association of New Mexico argue that the New Mexico Oil and Gas Act and the Oil Conservation District’s rules create a regulatory scheme so pervasive that the Mora County anti-fracing ordinance interferes with state law.

There are several important issues involved in any fracing litigation. First, it is obviously critical to safeguard water supplies. Water is becoming an increasingly scarce commodity and must be protected. However, to date, the opposition to fracing has been based on hysteria and assumptions, rather than facts. In fact, so far, there has been no research that has definitively tied fracing to any water quality issues. Each of the claims of water contamination due to fracing so far have, upon legitimate investigation, been shown to be unfounded. in addition, consider that the people that own minerals are not usually huge corporations. They are often individuals, including retired persons, who depend on the royalty income to live. Don't these people have the right to use their property in legitimate ways, rather than have their property rights taken away from them for frivolous reasons? They also have a constitutional right not to have their property taken from them, in effect, without just compensation. Protection of water sources is critical, but protection of constitutionally granted property rights is also important.

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February 21, 2014

Texas Oil and Gas Lease Decision from the Texas Court of Appeals

An interesting case involving a Texas oil and gas lease was decided recently by the Texas Court of Appeals in El Paso. The case was Community Bank of Raymore v. Chesapeake Exploration LLC and Anadarko Petroleum Corporation. The issue was whether the lessee's right to extract minerals found deeper than the stratum or level below the deepest producing well in a particular unit terminated when the lease’s primary term expired.

The oil and gas lease in question covered 16,000 acres, split into four blocks, located in Loving County, Texas. In Block 2 of the leased area, Chesapeake Exploration drilled 13 wells, the deepest of which was at 5,672 feet when the primary term of the lease expired on January 26, 2010. Community Bank of Raymore ("CBR") requested that Chesapeake release its mineral rights below the depth of the deepest well, but Chesapeake refused. CBR file suit for breach of the lease.

CBR argued that the Pugh clause applied, which terminates an oil and gas lease at the end of the primary term as to any portion of the leased land which is not being produced. Chesapeake disagreed, relying on the continuous development clause, saying the Pugh clause was thus never triggered because Chesapeake developed Block 2 and paid royalties from existing wells in that block. Chesapeake said that its continued development of Block 2 was “sufficient to maintain the undeveloped, deep-lying formations beyond the primary term and satisfy the lease’s continuous development requirement.”

The trial court decided for Chesapeake and said that “there has been no partial termination of the [lease]” and that the “[lease] . . . remains valid and in effect as to all of the Leased Lands in Block 2 . . . so long as [Chesapeake] engages in a continuous development program with no lapse in the time period provided.”

The Texas Court of Appeals, in a decision written by Justice Yvonne Rodriguez and joined by Chief Justice Ann Crawford McClure and Justice Guadalupe Rivera, affirmed the decision of the trial court. The Court of Appeals reasoned that the Pugh clause never sprung into life, because that clause has no effect until either the end of the primary lease term or the conclusion of the continuous development program. No cessation of the continuous development had occurred, so the Pugh clause never applied. The Court of Appeals found no merit in CBR’s contention that at the end of the primary lease term, the lease’s severance clause was triggered. The severance clause in this particular lease did not apply, again due to the continuous development clause.

This is an interesting case for mineral owners because it shows the interplay between the Pugh clause and the continuous development clause, which, because of the language of this lease, overrode the Pugh clause. It will be interesting to see if this case goes to the Texas Supreme Court, and if so what will be decided, as it could be a significant case for both oil and gas lease lessors and lessees in Texas.

It is critical to remember that the decision in this case was based on the precise language of this particular lease. There is no such thing as a "standard oil and gas lease" in Texas, therefore, the results may differ if this question comes up in connection with your lease. If you are ever presented with this kind of question in connection with your mineral interests, it is wise to seek the input of an experienced Texas oil and gas attorney.

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February 7, 2014

U.S. Supreme Court Reviewing EPA Approach to Greenhouse Gases

In October 2013, the U.S. Supreme Court granted certiorari in the case of Chamber of Commerce et al v. EPA et al. The case will decide the question of “(w)hether the EPA [Environmental Protection Agency] permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit greenhouse gases.”

The grant of certiorari followed Texas Attorney General Greg Abbott’s petition to the Court in April 2013, along with 11 other state attorneys general. The 11 other states involved, in addition to Texas, are Alabama, Florida, Georgia, Indiana, Louisiana, Michigan, Nebraska, North Dakota, Oklahoma, South Carolina and South Dakota. The attorneys general argued in their petition that the EPA violated the Constitution as well as the federal Clean Air Act by “concocting” its greenhouse gas regulations without Congressional authorization. Attorney General Abbot said that the regulations are threatening Texas jobs and employers and the EPA is a “runaway federal agency”. He was pleased the Obama administration would have to defend these regulations before the Supreme Court.

Organizations representing the oil and gas industry were also pleased that the Supreme Court decided to take this case. These organizations include the American Petroleum Institute and the American Petrochemical & Fuel Manufacturers. The issue doesn't effect just the energy and manufacturing industries. Millions of other stationary sources could be affected by strict permitting requirements according to the president of the National Association of Manufacturers, who said that the regulations threaten the global competitiveness of the U.S.

Harry Ng, API’s vice president, applauded the move and said that “(t)he Clean Air Act clearly only requires preconstruction permits for six specific emissions that impact national air quality—not greenhouse gases. That kind of overreach can have enormous implications on U.S. competitiveness and the prices that consumers pay for fuel and manufactured goods.” The General Counsel of AFPM, Rich Moskowitz, echoed that under the EPA’s current regulations the Clean Air Act’s Prevention of Significant Deterioration program would be turned into a “far-reaching regulatory program” that might apply to sources Congress didn’t originally intend and would impose “onerous permitting requirements.” He continued that the “EPA does not have the authority to rewrite specific statutory emission limits in an effort to avoid the absurd results created by its attempt to use GHGs as a regulatory trigger under the PSD program.” The American Chemistry Council also issued a statement in support of the Court’s granting of certiorari, which said in part: “We hope the Court will correct EPA’s egregious misreading of the Clean Air Act, which even the agency concedes leads to ‘absurd results.”

An amicus brief in the case stated the EPA had “opened a pandora’s box” of expansive greenhouse gas regulation that is likely to spread to the entire economy. People across the U.S. should be paying close attention to this case, as it not only affects the oil and gas and manufacturing industry, but the overall health of the economy. The Supreme Court’s decision has the potential to have a big impact.

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October 18, 2013

True Costs of Eliminating Tax Deduction for Oil and Gas Industry

A study entitled "Impacts of Delaying IDC Deductibility" was published recently by Wood Mackenzie Consulting and was commissioned by the American Petroleum Institute (API) to estimate the effects of an Obama proposal to eliminate federal tax deduction of intangible drilling costs used by the oil and gas industry and to instead require that these costs be treated as a capital expense. You can read the entire study here.

The difference between a deduction and a capital expense is huge. A deduction allows you to use the entire amount of the deduction in the year it was incurred. If these costs are treated as capital expenses, only a small portion of the total can be deducted each year over the useful life of the relevant asset. Intangible drilling costs are currently deductible like other operating costs and the deduction allows oil companies to use that saved money immediately for other projects. Intangible drilling costs include costs like wages, fuel and repairs, and accounts for 60% to 90% of costs for a given oil or gas well. Most industries deduct expenses like these in the year they were incurred. The Obama administration, however, wants to single out the energy industry for special treatment (again).

The study looks at the impact if this proposal was effective January 1, 2014. The study estimates that in the first year alone, elimination of the intangible drilling cost deduction would result in the loss of 190,000 US jobs. By 2019, the study estimates 233,000 job losses. Energy investment would be expected to drop by almost $40 billion per year between next year and 2023, for a total investment loss of $407 billion. U.S. oil production would drop by 520,000 barrels per day in the first year and 3.81 million barrels per day by 2023. There would also be 8,100 fewer wells drilled by 2019 and 9,800 fewer by 2023, contributing significantly to the drop in productivity. The study finds that some smaller companies may not be able to invest in drilling and development at all if the change were to take place.

There was a teleconference on this new report on July 11, 2013 and Stephen Comstock, API’s tax and accounting policy director, said, “Repealing the IDC deduction would actually lead to long-term declines in federal revenues, state taxes, and royalty payments to private landowners. If policymakers want to generate more revenue from oil and natural gas production, raising taxes is the wrong approach.”

The study indicates that if the current system of deductions remains in place, U.S. oil and gas production is expected to increase at a steady rate over the same years- adding as many as one million jobs- and that stability in the federal tax code would promote further investment in the industry. Keep in mind that foreign investors in domestic energy projects give great weight to the stability of the tax code in general, and on these deductions in particular, when deciding where to make investments.

As a Texas oil and gas lawyer, the outcome predicted by this latest study seem obvious. Promoting energy investment, energy sufficiency and job growth seem to be outcomes to be desired. Given the unemployment and budget problems the country is facing, this study should provide food for thought on what is the best way forward to promote a healthy energy sector and economy as a whole. I agree with Mr. Comstock when he concluded that “We urge Congress and the President to always approach the tax code with an eye toward fairness, job creation, and American energy security.”

Of course, Obama has long been interested in beating up on the energy industry. The frightening thing is that he often seems unaware of the unintended consequences of proposals like the elimination of the IDC deduction. It's ironic that he has repeatedly said he is seeking ways to minimize the deficit and increase job growth, yet he supports this proposal that would have the opposite effect, and while refusing to allow leasing of federal lands. Go figure.

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October 11, 2013

Oil and Gas Pipelines in Texas

In Texas, and in much of the rest of the country, an oil and gas lease makes use of several different kinds of pipelines. When you are the recipient of a request for a pipeline easement, the kind of pipeline to be installed in that easement makes a night and day difference in how you negotiate the easement.

I recently spoke at a National Business Institute telephone seminar about the negotiation of pipeline easements. NBI provides "on-demand" CLE for attorneys and they have many excellent seminars on a wide variety of legal topics. You can access the audio of the seminar here, or you can register to take the seminar for CLE credit here.

The word "pipeline" can mean a variety of things, because there are several different types of pipelines. First, there are flow lines, which are lines from the well to other equipment on the well site, such as a tank or a heater-treater. Flow lines are located entirely within the well site area. The authorization for these lines is generally contained within the oil and gas lease itself. These lines are not regulated by either federal or state agencies.

Next, there are gathering lines. These are pipelines that transport the produced oil or gas from the wellhead or from a tank to a larger intrastate or interstate transmission line. Like flow lines, these lines are not regulated by any federal or state agency. The authorization for these lines is often found in the oil and gas lease. Hopefully, if the authorization for these lines arises from your oil and gas lease, the lease does not contain a blanket easement for all gathering lines. In cases in which you have substantial bargaining leverage, the location and construction details of these lines should be dealt with specifically, whether in the oil and gas lease or by means of a separate agreement, and the written consent of the mineral owner and landowner to the location of any above ground equipment, the route of the line and some of the construction details (such as depth of the line), should be required.

The most important thing to remember about gathering lines is that they are private lines that use private easements. The grantee of the easement for these lines is generally the operator of a well or wells on your property or property pooled with your property or on contiguous or even noncontiguous property owned by others. The easement for gathering lines is subject to negotiation, just as in any other real estate transaction. The well operator needs to get its oil or gas to market, or to a processing facility and then to market. The landowner, if the landowner is also a royalty owner, also wants the oil or gas to get to market, or they will not get paid royalties. However, even if not a royalty owner, if the landowner is a good steward of their land, they will want to be careful as to the routing of the pipeline, reclamation efforts after construction, depth requirements that are consistent with irrigation equipment, prevention of erosion, possible noise abatement in the case of certain above ground equipment (such as a gas compressor), and numerous other issues. The easement agreement is the place where an accommodation is hammered out with both parties’ goals in mind.

Finally, oil and gas (almost always for gas and sometimes for oil) is often transported through large, usually high-pressure, transmission lines that take the product from a gathering line or storage tank to a processing plant or a distribution center. Intrastate lines in Texas are regulated by the Texas Railroad Commission ("RRC"). Interstate lines are regulated by the U. S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration ("PHMSA"). Many of these lines call themselves “common carrier” pipelines. That designation is significant because only common carrier pipelines can use eminent domain to acquire pipeline easements.

There is a lot to know when you are approached by a company who wants a pipeline easement across your land. You may find that a pipeline attorney representing you in the negotiation will get you a lot better deal than if you do it yourself. My office represents only landowners, surface owners and royalty owners, and never represents oil or pipeline companies. I am experienced in pipeline negotiations and would be glad to talk to you about your property anytime.

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September 27, 2013

Texas Supreme Court and the Implied Covenant to Market Oil & Gas

In 2008, the Texas Supreme Court heard a class action case against Phillips Petroleum Co. The case was Bowden v. Phillips Petroleum Co., in which the Plaintiffs alleged that Phillips had underpaid their oil and gas royalties. The Supreme Court remanded part of the case back to the trial court.

When the case was remanded, the representative of the class, Royce Yarbrough, amended the complaint against Phillips to allege that the company breached their implied covenant to market and that this is what contributed to the underpayment of royalties to the royalty owners. Phillips argued that to add a new claim on behalf of the class required a new class certification motion and hearing. The trial court disagreed and Phillips Petroleum appealed. The Texas Supreme Court considered this issue in Phillips Petroleum Co v. Yarbrough, et al.

The Supreme Court actually reviewed several issues, including res judicata issues from the Bowden case and whether they had jurisdiction over the interlocutory appeal on the decision by the trial court regarding the implied covenant to market. But the most interesting issue for oil and gas lawyers in Texas concerns the substantive issue of implied covenants to market vis-a-vis express covenants to market.

An implied covenant to market is, obviously, “implied,” rather than specifically expressed in the oil and gas lease. It is an agreement to market the oil and gas within a reasonable time and at the best price possible. In the Yarbrough case, some of the class members involved did have express covenants to market in gas royalty agreements they signed that amended their oil and gas leases with Phillips. Phillips argued that these express covenants superseded any implied covenant. Yarbrough argued that an implied covenant in the Gas Royalty Agreement merely amends the express covenants that may exist in some of the leases.

The Texas Supreme Court, in a decision written by Justice Debra Lehrmann, held that the addition of the new implied covenant to market claim required a new request for class certification and remanded the case to the trial court. The opinion does note that the absence of an express covenant in the parties' gas royalty agreements does not automatically impose an implied covenant to market in leases that had an express covenant to market. The Supreme Court found that the effect of these express covenants in the leases of some class members was an issue that was not argued or decided in the previous Bowden case. The Supreme Court thus determined that since this was a significant new issue that had not yet been litigated, and the trial court’s decision to allow this new claim changed the composition of the class. The Supreme Court went on to hold that the trial court abused its discretion in certifying the new class without an analysis of the effect of this new issue on class certification and remanded the case, ordering the trial court to do a proper analysis of the issue.

Cases like Bowden and Yarbrough show why leases and gas royalty agreements can be so complicated for those leasing their mineral rights, and why it is incredibly important to have an experienced oil and gas attorney review a lease before you sign it.

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September 20, 2013

New Accommodation Doctrine Development for Texas Mineral Owners and Landowners

Recently the Supreme Court of Texas issued a decision that is important for Texas surface owners and mineral owners and the Texas oil and gas attorneys who represent them. The case is Homer Merriman v. XTO Energy Inc. I discussed the background of the Supreme Court decision previously, and you can access that article here.


As you may recall, Homer Merriman bought a piece of land in 1996, but he bought only the surface rights, and the deed clearly reserved the minerals. XTO Energy Inc. had previously leased the mineral rights. Mr. Merriman used the land for his cattle business and used the particular tract in question to sort his cattle, with stock panels and electrical fences which he testified were not permanent fixtures. In 2007, XTO wanted to drill a well on this tract, and offered Mr. Merriman $10,000 in compensation for this use, but he refused and the case went to court.

The the trial court granted summary judgment to XTO and said Mr. Merriman did not show that XTO had violated the accommodation doctrine. The Texas Court of Appeals affirmed the trial court decision. In Texas, the accommodation doctrine provides that the mineral rights owner and its lessee must accommodate the surface owner’s pre-existing surface uses, so long as other means of production or extraction of the minerals are available. To obtain relief under this doctrine in Texas, the surface owner must prove that the use by the mineral lessee, in this case XTO, completely precludes or substantially impairs the existing use by the surface owner and there is no reasonable alternative method available to the surface owner by which the existing use can be continued.

The Texas Supreme Court Decision:

The Texas Supreme Court upheld the decisions of the appeals court and the trial court in favor of XTO. The opinion, written by Justice Phil Johnson, affirms the lower court decisions on slightly different grounds. Specifically, the Supreme Court found that requiring Mr. Merriman to consider using other land he leased was an inappropriately high burden to meet in order to demonstrate that a reasonable alternative was available for his cattle operations. The cattle leases on other properties might only be for a short term and so these other lands should not be considered. The Supreme Court also found it was unfair to characterize the surface owner's use as a general “agricultural” use. Instead, the appropriate test is a balancing of the surface owner's cattle operation against the use by XTO.

The Court went on to compare Mr. Merriman’s cattle operations and the proposed drilling by XTO and found no evidence that Mr. Merriman could not complete his sorting of the cattle on a different part of this same 40 acre tract. Mr. Merriman offered no evidence of why the corrals and fences, which were not permanent fixtures, couldn’t be moved. The evidence did show that XTO's activities would impair the use of existing pens and corrals, but Mr. Merriman did not meet his burden of proof to show that there were no other reasonable means of conducting his cattle sorting operation elsewhere on the same 40 acre piece of land.

The message of this decision is clear: a lessee is not violating the accommodation doctrine if the surface owner's use does not involve more permanent fixtures that can be readily and inexpensively relocated elsewhere on the same land. This decision is significant because it further clarifies the accommodation doctrine in Texas for both surface owners and mineral owners.

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September 13, 2013

Texas Mineral Owners Get More Access to Fracing Info

Texas royalty owners should get to know the website, FracFocus. This website provides a list of chemicals and other ingredients in fluids used by oil and gas well operators for hydraulic fracturing of wells both in Texas and across the country. The intent of the website is to allow the public to access this information and to provide objective and accurate data about hydraulic fracturing. FracFocus is managed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission.

Twelve states currently require operators to report their data on FracFocus and eight more states are about to require reporting. The website currently has more than 45,000 records from more than 400 companies.

A new version of the website went online on June 1, 2013 that promises to be even easier to use according to witnesses who testified before the U.S. Senate Energy and Natural Resources Committee during their first natural gas forum. Some of the changes in the new version of the website include the display of data in a format that is easier to aggregate and customize. In addition, the new website will allow a search by the name of a chemical, using the Chemical Abstracts Service number, and a date range.

Environmental groups admitted that the changes to FracFocus were positive. Mark Brownstein from the Environmental Defense Fund said: “(t)he improvements that are about to be made to FracFocus will be a significant help to states. Searchability of information, in conjunction with these risk management systems, can improve regulatory results.” But environmental groups also complained that without a way to verify the data, FracFocus is still not ideal.

Oil and gas companies told the Committee that they have no problem with audits to verify their FracFocus’s data. Charles Davidson, the CEO of Noble Energy Inc., and Jack Williams, President of XTO Energy Inc., both said audits were a good idea, and Mr. Davidson applauded the work that FracFocus has done in keeping the public informed of what is going on with fracing wells, and for making the newest version of the website more user friendly.

Public Disclosure always has to be balanced with the need to keep trade secrets and proprietary information private. For example, a Halliburton executive commented that they have the only frac fluid composed entirely from food material, and if they were forced to make their ingredients public, they would lose all the money they invested in researching, creating and developing their frac fluid. It is the potential for profit that drives the research and experimentation into more environmentally-friendly ways to extract oil and gas, after all. (Actually, many fracing fluids are made of substances like guar gum that are common in foods). Some companies were already thinking ahead, such as Houston based Baker Hughes Inc., which designed its disclosure system to comply with the rules but protect proprietary information.

More new developments can be expected from the organizations that sponsor FracFocus. The groups are working on a Risk Data Management System that is designed to work with 23 industry regulatory programs and eventually to link up with FracFocus. The Risk Data Management System will have a water life-cycle tracker, a component to manage air and water sampling, a feature for iPad and smart phone field inspections, and an oil and gas data gateway to the Energy Information Administration. Both the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission say they are interested in continuous innovation of tools for the public, and indicate that they will continue to review emerging technologies and work with NGOs and universities.

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August 23, 2013

Removing Ethanol from the Renewable Fuel Standard

In April 2013. representatives in the US House of Representatives announced that bipartisan legislation would be introduced in 2014 to take out corn based ethanol requirements in the federal Renewable Fuel Standard

The bill is called the Renewable Fuel Standard Reform Act. Those involved in the oil and gas industry know that the standards involving ethanol can effect the market by conferring an artificial advantage for the so called “renewable” fuels over oil and gas.

The current Renewable Fuel Standard requires 36 billion gallons of renewable fuels to be included in the domestic fuel supply by 2022, and almost all of that is from corn-based ethanol. This requirement uses a massive percentage of America’s corn supply and diverts it to fuel. In 2011, 40% of the nation’s corn went to making ethanol, which is about five billion bushels of corn. Because so much of the corn crop is used for ethanol, there is less for food and for livestock feed. The end result is a substantial increase in the price of corn and everything that has corn as an ingredient, hurting consumers and many small businesses. In addition, ethanol in fuel wrecks havoc on everything from car engines, to lawnmowers to chainsaws. No one has bothered yet to assign a cost for these damages to consumers.

untitled-1416275-m.jpg The Renewable Fuel Standard Reform Act will eliminate the corn ethanol requirements and put a limit of 10% for the amount of ethanol required to be in conventional gasoline. The new bill’s main sponsor, Representative Bob Goodlatte of Virginia, said “Renewable fuels play an important role in our energy policy but should compete fairly in the marketplace. This legislation will bring the fundamental reform this unworkable federal policy needs now.”

While Representative Goodlatte is a Republican, the bill appears to have bipartisan support. Congressional members of both parties from Vermont to California are in favor of this bill for various reasons. For example, California Democrat Representative Jim Costa said that putting food (the mandated corn based ethanol) into fuel is taking food off families’ tables. And bipartisan support of this common sense reform of ethanol standards is gaining ground, with 40 diverse groups now supporting the bill according to Representative Goodlatte. Included among those groups are the American Petroleum Institute and the American Fuel & Petrochemical Manufacturers. At the press conference announcing the Renewable Fuel Standard Reform Act, the president of the American Petroleum Institute, Jack Gerard, noted that renewable fuels do have a place in the energy field, but that, “We cannot allow a mandate for ethanol that exceeds what is safe and that could put upward pressure on fuel prices.” The president of the American Fuel & Petrochemical Manufacturers, Charles Drevna, also weighed in, saying, “The RFS was founded upon baseless assumptions and now, eight years later, the reality is that there is no fix for this broken program, which is why AFPM fully supports the elimination legislation.” Drevna said that betting on the Renewable Fuel Standard is like betting against reality and in the end, those betting on it will lose.

Keep in mind that the Renewable Fuel Standard is a charade is based on the unproven idea that fossil fuels somehow contribute to global warming. There is evidence of global warming, but there is no peer-reviewed science that shows a causative connection between people's use of fossil fuels and global warming. Then again, science and logic have never been very popular in Washington D.C.

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July 26, 2013

Oil and Gas Regulation Best Left to the Texas and Other States

The US House of Representatives Natural Resources Committee has held at least five meetings in the last two years on the problem of federal oil and gas regulations overlapping with existing state regulations. The Committee’s chairman, Representative Doc Hastings, had a common sense solution to this confusion: “There is a simple solution to prevent duplication: Don’t duplicate the states. The ‘one size fits all’ regulatory structure being pursued by the Obama administration is a waste of time and energy.” This issue is particularly significant in light of the increase in hydraulic fracturing, a process that has become increasingly politicized at the national level.

That is exactly the message of three of the witnesses at the Committee’s latest meeting. These three witnesses, all state officials, agreed that states are in a unique position to understand the geological and environmental conditions and issues within their states. The states represented by these three witnesses were Utah, Texas, and Ohio.


Utah’s Lieutenant Governor Gregory Bell told the Committee: “From Utah’s perspective, increasingly national political considerations are unduly influencing land use decisions that are more effectively addressed locally.” He went on to assert that “political jockeying” in Washington within national policy debates hurts local communities, who are better placed to decide what is best for their land. He pointed to the sequester cuts to mineral lease royalty payments, which confuses what royalties are supposed to be- they should be dedicated revenues held in trust, not subject to federal spending rules.

Texas’s General Land Officer Commissioner Jerry Patterson agreed and said that Texas can charge higher lease prices for shorter periods of time because Texas regulators can issue permits much more quickly and efficiently. He said, “Producers are willing to pay more because our terms and time frames are certain.” He noted that it is less cumbersome to deal with state and local authorities than federal authorities and also that federal policies are impeding the development of the energy industry in the states.

Ohio’s Department of Natural Resources Division of Oil and Gas Resources Management’s chief Richard Simmers also firmly agreed that the states are the appropriate and qualified regulators of the oil and gas sector. He told the Committee: “People who believe federal regulations are uniform and consistent, and state regulations are a patchwork of inconsistency, don’t understand how oil and gas regulation works. The states are doing it properly. We’re just doing it differently.” Mr. Simmers highlighted to the Committee that when an accident happens, state officials are the ones best placed on the ground to respond, citing an incident of illegal waste dumping in Youngstown and earthquakes caused by a brine injection well, both of which were dealt with promptly by state authorities.

The goal here should be to do what is best for the country as a whole, the environment and the people who own these resources. States have decades of experience in regulating oil and gas exploration and development. The federal bureaucracy is too far removed from reality, too antagonized toward the energy industry and too politicized to offer any effective regulation.

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July 19, 2013

Texas Leads Oil & Gas Industry Fight Against Overreaching EPA Regs

Due to increasingly onerous regulations, oil and gas industry associations have filed suit in federal court over the Environmental Protection Agency’s (EPA) planned regulation of greenhouse gases from power plants and vehicles. The regulations come from a 2009 EPA finding that greenhouse gases pose a public health threat- the so-called “endangerment finding”.

Last year, a three judge panel at the District of Columbia’s Circuit Court of Appeals upheld the EPA regulations. That same court denied the energy industry Petitioners a rehearing in December, so the Petitioners recently asked the US Supreme Court to review the regulations at issue.

The Petitioners' request explains that the regulations are hurting the economy, that there are clear legal issues that need to be adequately addressed, and that the need for review was particularly acute in light of two articulate dissenting opinions at the Court of Appeals, one by Judge Brett Kavanaugh and one by Judge Janice Rogers Brown.

The Petitioners include four oil and gas associations (the American Petroleum Institute, the American Fuel & Petrochemical Manufacturers, the Independent Petroleum Association of America, and the Western States Petroleum Association), about 20 industry business associations and 12 energy producing states, led by Texas but also including Florida, North Dakota, South Dakota, Georgia, Alabama, Indiana, Louisiana, Nebraska, Michigan, South Carolina, and Oklahoma. The Petitioners also have the support of conservative political groups and about a dozen Republican members of the House, all adding their voices to the request that the Supreme Court hear this case.

The Petitioners' request to the Supreme Court states that the Court of Appeals decision “... adopts an EPA interpretation of the Clean Air Act that the agency concedes produces ‘absurd’ consequences inconsistent with congressional intent, and ... allows the agency to address those consequences by exercising effectively unrestricted discretion to rewrite—on an ongoing basis—separate, explicit statutory directives in order to revise the scope of the statute’s coverage.”

While the Petitioners attack the regulations on many grounds, they all agree with the premise that the Clean Air Act should not be used to regulate carbon emissions. The Petitioners claim that the EPA improperly used the Clean Air Act to regulate greenhouse gases from power plants, when that program specifically applies to only six other air pollutants. One of the business association Petitioners, the American Chemical Council (ACC), issued a statement that “EPA's ill-founded regulations represent a sweeping expansion of its regulatory power under the Clean Air Act and would impose new requirements on potentially millions of stationary sources across the country.”

Those of us interested in overreaching EPA regulations and their impact on the oil and gas industry, particularly in Texas as one of the states most affected by the regulations, will have to wait and see if the Supreme Court decides to take the case or not.

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July 5, 2013

New Panel Will Review EPA’s Well Fracing Research

The Environmental Protection Agency's (EPA) Science Advisory Board, recently announced the creation of a new panel on hydraulic fracturing, generally referred to as "fracing". The formation of the panel comes as the Obama administration is working to revise draft rules for fracing. With new technologies like fracing leading to historic amounts of oil and gas production for the US, this topic is hotter than ever.

The new panel, called the Hydraulic Fracturing Research Advisory Panel, will be made up of 31 experts (see the list of experts here).Among the 31 are several consultants, two government employees, and 21 academics and college professors. To compose the panel, the EPA asked for nominations of recognized scientists and engineers in the field of hydraulic fracturing, which resulted in 144 candidates. That group was whittled down to 31 through checks for financial and other conflicts of interest. There are at least three experts representing each of the following areas: Petroleum/Natural Gas Engineering; Petroleum/Natural Gas Well Drilling; Hydrology/Hydrogeology; Geology /Geophysics; Groundwater Chemistry/Geochemistry; Toxicology/Biology; Statistics; Civil Engineering; and Waste Water and Drinking Water Treatment. The Chair of the panel is Dr. David A. Dzombak, an environmental engineering professor at Carnegie Mellon University in Pittsburg.

This panel of experts will peer review the EPA’s 2014 draft report on the potential impact of hydraulic fracturing on drinking water. It will also provide scientific feedback on the EPA’s research methods. In particular, the panel is expected to provide information on emerging science and technology for the Science Advisory Board. The report itself is the product of a request by Congress that the EPA commenced in 2010. The draft study plan for the proposed report was submitted in March 2011.

The panel will meet in the summer of 2013 to go over initial thoughts and individual feedback from the EPA’s 2012 progress report on the fracing study. At that meeting the public will also have an opportunity to provide information to the panel.

Acting EPA Administrator Bob Perciasepe said, “Our final report on the potential impacts of hydraulic fracturing on drinking water resources must be based on sound science and take into account the latest practices being used by the industry. We have worked to ensure that the study process be open and transparent throughout, and the SAB panel is another example of our approach of openness and scientific rigor.”

I have two big questions about this panel. First, I wonder how truly independent the panel will be in terms of assessing EPA’s standards and research. Already earlier this year, the Bureau of Land Management pulled back a proposed new rule for hydraulic fracturing after negative comments. Over the last few months, the Obama administration has held nine meetings about fracing. Fracing is such a politicized issue, it will be interesting to see how effective this “independent” panel. Secondly, the panel is heavy on academics and extremely light on experts with real world fracing experience. That suggests that the panel's results may be great on theory but missing any truly relevant information. We have enough inexperienced theorists in the EPA as it is, who have no hesitation in pronouncing regulations without any real expertise in the area affected by those regulations. We'll see when the panel's results come out next year.

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June 21, 2013

Changes to the Oil & Gas Industry in Texas, the U.S. and the World?

Recently the IHS hosted CERAWeek in Houston, Texas (you can view the brochure here). CERA stands for Cambridge Energy Research Associates, an organization founded in the early 1980s to consult on energy issues for both the government and private companies, and that hosts the annual event in Houston each year. This year’s event, the 32nd such conference, had about 2,200 participants from the energy industry coming from about 50 countries around the world, including 300 speakers.

This year’s CERAWeek’s conference was called “Drivers of Change: Geopolitics, Markets & the New Map of Energy.” It focused on the profound transformations in the industry and hoped to shed new light on the future of energy and focus on changes in the competitive landscape, the unconventional oil and gas revolution, and new fuels and technologies of the future. Daniel Yergin, the conference’s chairman, said, “All this is leading to a vigorous discussion of how the energy needs of a growing world economy will be met over the next 2 decades and what the mix will be. Will an energy transition unfold over years or over decades?”

386286_houston_skyline.jpg In terms of the US, we are expected to average 7.3 million barrels per day of oil in 2013, up 900 million barrels since just last year. Our oil imports have been declining since they peaked in 2005, because of this growth in production. Tight oil development in the US and Canada has far outpaced any other region of the world, and the question will continue to be one of the pace of growth. Michael Stoppard, managing director of global gas for IHS, said there was a “redrawing” of the global gas map focusing on three supplies- unconventional gas, deepwater gas, and gas from tight oil. He noted that the world demand for gas would continue to grow in the next few years but that the US probably could not export significant light natural gas until 2015. He also predicted a rebalancing of gas prices from their “unsustainably low levels” of today.

Aside from the US, the other country that will be one of the biggest factors in the energy industry is China, which accounted for 40% of global oil demand growth in 2012. IHS’s China energy director, Xizhou Zhou, stated that China’s focus is on diversification and that the new power plants are shifting away from coal and toward fuels such as gas and nuclear. China expects to reduce its dependence on coal, which is now at 80%, to about 50 to 60% by 2025. In Russia and the Caspian, IHS’s staff believes there will be stable growth, after 20 years of instability, due to a stable political and economic environment. Their senior director of Russian and Caspian energy, Thane Gustafson, said the biggest changes, and possible the biggest surprises, will be in the increased pace of Russian development of tight oil, now that Russia and other countries are adopting the US definition of tight oil to include difficult to extract conventional oil.

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June 14, 2013

University of Texas Study on Texas' Barnett Shale Oil and Gas

The University of Texas at Austin’s Bureau of Economic Geology recently released a new study, entitled the Sloan Foundation Shale Gas Assessment Study, funded by the Alfred P. Sloan Foundation, predicting a reliable, although decreasing, supply of natural gas from the Barnett shale until 2030. Barnett shale is the country’s second most productive shale formation.

This new study is believed to be the most thorough yet on the topic of natural gas production in the Barnett shale, and it predicts a total recovery of over three times cumulative production to date. The study integrated engineering, geology, and economics to do scenario testing. The testers studied the actual data produced from 16,000 wells in the play until 2011. Most other studies of Barnett took a “top down” approach, relying on aggregate views of average production. This study, in contrast, took a “bottom up” approach by studying the production history of every well as well as those areas that remained to be drilled in the future, which they believe yielded a more accurate model. The researchers increased the accuracy of the study by identifying and assessing the production in ten different quality tiers and using that information to predict future production even more accurately. Their new method of estimating production for each well was integral and will contribute to future forecasting of production declines in shale natural gas wells. One of the investigators on the project, Svetlana Ikonnikova, an energy economist at the Bureau, said, “We have created a very dynamic and granular model that accounts for the key geologic, engineering and economic parameters, and this adds significant rigor to the forecasts.”


The study also demonstrated the correlation between gas prices and production. It noted that in the early years of drilling, the correlation is weak because it is not very expensive to drill in better quality rock areas, making it efficient even when the prices are low. In later years, when the natural gas is harder and more expensive to retrieve, price becomes the dominant factor.

This paper has already received professional peer review during the research process, but the Bureau of Economic Geology also invited an independent peer review panel, composed of members of government, industry, and academia, to review the study before submitting it to journals. They hosted an “open day” where 100 such experts gave feedback on the project. In special sessions, two of the largest producers in the Barnett shale, Devon Energy and ExxonMobil, gave critical feedback on the methods used by the researchers. Further studies of other shale areas are already in the works. By the end of 2013, the Bureau expects to complete assessments of the Marcellus, the Haynesville, and the Fayetteville shales. Scott Tinker, another investigator in the study and the director of the Bureau, compared the impact of shale gas, especially through unconventional drilling, to the tremendous increase in oil production due to deep-water exploration and drilling in the past decades. The news about the continuing impact of shale gas on the nation’s energy future is definitely more welcome news.

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May 24, 2013

Predictions for Texas and U. S. Oil and Gas Supplies

Forecasts for the oil and gas markets for 2014 were released recently. They predict a somewhat loose market, along with more positive news for those involved in the North American oil and gas industry. These projections were published in the "Short-Term Energy Outlook", a document produced by the US Energy Information Administration. The report says that a “loose market” will result from higher global consumption of oil being offset by the increased global supply of fossil fuels.

The Short-Term Energy Outlook predicts that global liquid fuel consumption will remain stable in 2013 but will pick up again and increase in 2014 due to economic recovery--increasing by about 400,000 million barrels per day. The report predicts that most of the increase in consumption will come from outside the Organization for Economic Cooperation and Development (OECD), a group of the world’s developed countries. In the OECD countries, the report predicts a decline in consumption of 300,000 million barrels per day due to decreasing use of liquid fuels in Europe that is not offset by the modest rise in consumption in North America. In 2014, the OECD overall decline will slow to 100,000 million barrels per day. The increase in the US is expected to be 70,000 barrels per day in 2013 and 60,000 barrels per day in 2014. Most of that increase will be in fuel oil and liquid petroleum gas.

Perhaps the more interesting information in the report pertains to energy production. The members of Organization of Petroleum Exporting Countries (OPEC) are expected to decrease crude oil supply in 2013 by 600,000 barrels per day due to a decline in production in Saudi Arabia. Other OPEC members, such as Iraq, Nigeria, and Angola, will increase production to pick up the slack over the next two years. But most growth in oil and gas production will come from non-OPEC members. The report projects that non-OPEC fuel production will grow by 1.4 million barrels per day in 2013 and 1.3 million barrels per day in 2014. The days of fuel shortages due to OPEC policies like in the 1970s are looking more and more like the distant past. Production in North America alone is expected to account for two thirds of that non-OPEC growth!

The US will increase its crude oil production by 900,000 million barrels per day in 2013 from the 2012 total and then increase by another 600,000 million barrels per day in 2014. The Energy Information Administration predicts that the US imports of liquid fuel will continue to decline in the next two years--falling by eight percent from the 2012 numbers. Gas production will also continue to increase, largely due to growth in shale gas. US inventories of gas were at an all time high this past November, and with increased shale production in regions around the country, there is no reason not to expect continued success in this area of energy production.

All of this confirms the dynamism and potential of the US energy industry and our mounting capacity for energy independence.

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May 17, 2013

Pipeline Construction Financing Issues

Oil and gas pipelines in Texas and throughout the country are needed to bring oil and gas to refiners and to markets, and result in cheaper fuel prices for consumers by lowering transportation costs. With the oil and gas industry flourishing, particularly in areas of the country like Texas, more pipelines are needed to transport increasing amounts of these raw materials. Without enough pipeline capacity, producers have to use trucks, barges, and trains to move oil, gas and condensate to refiners and to the market--all of which cost more than pipeline transport. There are numerous pipelines in the works right now. However, some of these pipelines are still subject to financing issues and face challenges with government approvals (such as with the high-profile Keystone pipeline project).

On the financing issue, the Association of Oil Pipelines (AOPL) has requested that the Federal Energy Regulatory Commission (FERC), the agency that oversees interstate oil pipeline tariffs, step in to fix a dispute that AOPL claims may impair the financing of new pipelines. Financing of pipelines often relies on secured revenue accrued after the pipeline is completed. This is accomplished through contracts setting the rates ahead of time for the delivery of crude oil, gas, condensate, diesel, and other products. Andrew J. Black, President of AOPL, said earlier this month that “(t)hese committed rate agreements give confidence to shippers that the infrastructure they need to deliver their production to market will be there when they need it. They also give confidence to companies and investors ready to fund new pipeline projects that their investments will be repaid.”

The problem has arisen in an ongoing pipeline case being considered by FERC, which includes testimony threatening the mutually beneficial rate contracts agreed upon by energy suppliers and pipeline companies. The case involves the Seaway Pipeline, which goes from Cushing, Oklahoma, to Houston, Texas and is expected to carry 150,000 barrels of crude oil per day initially. AOPL filed a motion asking FERC to confirm its rate contracts and to rule that the contracts are not subject to review during the pipeline’s future rate proceedings. Instead, FERC staff recommended a new rate and rate structure, throwing out the old agreements which were the basis for financing this pipeline. AOPL responded that this action could not only deter new pipeline projects, it could also bring a halt to pipelines currently under construction.

This debate is important, and one that will be followed closely by all those in the oil and gas industry. The pipeline companies believe that the current system is necessary to maintain pipeline construction and growth. On the other hand, oil and gas producers want protection in case the prices for their products experience large increases or decreases, in which event they could be stuck with a long term pipeline contract for an unrealistic price.

There is a 73% increase in expected pipeline construction in the coming year compared with last year, and so these questions will need to be answered sooner rather than later.

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May 10, 2013

Federal Court Vacates Main Component of EPA Biofuels Requirement

In a significant win for reasonable and sensible energy regulation, the DC Circuit Court rejected the Environmental Protection Agency’s (EPA) 2012 cellulosic biofuels projection. It is sad that this is what passes as a “win” for the energy industry however, since the Court simply acknowledged that the EPA’s requirements are based on fiction and require supplies of materials that are not even available currently!

The case being decided involved a challenge by the American Petroleum Institute (API) to the EPA’s regulation. The regulation in question was adopted under the renewable fuel standard program, which requires refiners to blend 36 billion gallons of biofuel with traditional fossil fuels by 2022. That goal has incremental targets leading up to it, and by 2012 refiners were required to blend 10.45 million biofuel ethanol gallons with their gasoline-- an impossibility considering that the entire industry only produced 22,000 gallons of biofuel last year. API argued that these rules forced refiners to buy “credits” for the cellulosic biofuel since this product does not not, and may never, get produced in sufficient quantities to comply with the EPA regulations. API fairly asserted that the EPA should base the biofuel requirement on a realistic assessment of current production levels.

The decision, written by Judge Stephen Williams, stated, “We agree with API that because EPA’s methodology for making its cellulosic biofuel projection did not take neutral aim at accuracy, it was an unreasonable exercise of agency discretion.”

The Court concluded that the EPA exceeded the agency’s statutory authority. Judge Williams noted that the Court had previously ruled that a federal agency is allowed to set a standard on future technology when there is a rational connection between the regulatory target and the potential innovation. However, in those previous cases, the federal government worked with the industry involved to arrive at realistic goals. In this case, what was really going on was that the EPA was giving the biofuels industry the opportunity to profiteer, while imposing a tax on the fossil fuel industry. Judge Williams highlighted this imbalance and commented that the refiners of gasoline cannot either insure or contribute to any biofuel technology success. They would be merely captive consumers of the biofuels industry (which as most of us know, is not doing too well even with lots of taxpayer handouts).

Judge Williams went on the say that “(g)iven this asymmetry in incentives, EPA’s projection is not ‘technology-forcing’ in the same sense as other innovation-minded regulations that we have upheld.” The decision did uphold the EPA’s allowance for importing other sources of biofuels to meet their requirements. Still, the Court explained that the EPA’s arguments did not include any specific information about how much imported biofuel was available, let alone information regarding whether these sources could meet the EPA’s requirements. The case was remanded to a lower court for proceedings consistent with this new decision.

Bob Greco, API’s downstream director, applauded the decision for getting rid of requirements to use a product that does not exist and for relieving refiners from following impossible regulations. He commented: "This absurd mandate acts as a stealth tax on gasoline with no environmental benefit that could have ultimately burdened consumers.” Mr. Greco went on to say, “The Court has provided yet another confirmation that EPA’s renewable fuels program is unworkable and must be scrapped.”

This case is yet another example of our federal government beating up on the energy industry, while subsidizing a "green" industry that has no economic value. The EPA regulation at issue in this case would have driven the price of gasoline up substantially, imposing hardship on all consumers and further crippling our economy. Those of us who follow this situation can only say, thank goodness sense and reason prevailed.

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May 3, 2013

National Benefits of Oil & Gas Development in Texas and the U.S.

More advocates are spreading the message that the energy industry can help our county work though not only its energy needs but its budget shortfalls and economic problems as well. US Chamber of Commerce President Thomas J. Donohue noted in his 2013 State of American Business address that developing American energy can help our fiscal problems, including reducing the trade deficit and bringing more manufacturing jobs back to the US.

He said that he has already seen indications that lower gas prices are attracting businesses back. Donohue stated that to take advantage of these opportunities, more federally controlled land, both on and offshore, must be opened for exploration and development with a predictable and fair regulatory system in place. He also encouraged further development of alternative energy sources, such as nuclear, wind, geo-thermal, and solar. Donohue asserted that the Chamber’s top priorities for 2013 remain creating jobs and increasing economic growth. He said that “(w)e must get this economy moving faster. Growth of 1.5% to 2% is not acceptable.”

Donohue and the Chamber of Commerce are not the only ones optimistic about renewed growth in US manufacturing. Fitch Ratings analysts issued a special report called “Shale Boom: A Boost to Manufacturing but Not to Energy Independence” earlier this month. It states that low gas prices provide an advantage for some industries, including steel, petrochemicals, and other high-energy industries, as well as (to a lesser degree) copper, aluminum, and cement. Shale gas is providing the lower costs that allow this comparative advantage, particularly due to the expanded use of increasingly efficient hydraulic fracturing. The current utilities gas price is $2.50/ mcf, down tremendously from the 2008 average of $8/ mcf. The advantage is most notable in petrochemicals, because natural gas is both an ingredient in the products made by this industry as well as a source of energy to manufacture products. The report states it “appears to be a permanent advantage” in this industry and that America’s gas-run petrochemical industry is more efficient and competitive than Europe’s oil-based industry.

None of this means that the US cannot also export natural gas as well. Another Chamber of Commerce executive, R. Bruce Josten, said that the US has enough natural gas resources to support a growing manufacturing sector as well as to export to the global market. Donohue concluded that “(b)y fully embracing America’s energy opportunity, we can accelerate growth, create millions of new jobs, free ourselves from some less-than-stable global suppliers, and create huge new revenues for government, which will help reduce budget deficits.” If only our politicians would take notice and listen to this sound advice, issued over and over again, the prospects for our country could be a whole lot brighter in 2013.

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April 26, 2013

Texas Oil Company To Use Natural Gas to Power Fracing Jobs

It seems there is an ongoing supply of positive developments in the natural gas field in Texas that are poised to make our country more energy independent. Currently, almost all the fuel used to power hydraulic fracturing is diesel. Hydraulic fracturing is credited with much of the recent dramatic increases in Texas and US oil and gas production, but the industry required more than 700 gallons of diesel last year for this purpose at a cost of about $2.38 billion. If they could use natural gas, it would save the industry up to 70% and would allow the US to import 17 million fewer barrels of oil each year. There is a viable process in the works to make that possible.


Apache Corporation, with headquarters in Houston, Texas but that operates internationally, decided this was worth pursuing. Mike Bahorich, the vice president of technology, reached out to Halliburton and Schlumberger. Both companies told Mr. Bahorich that using natural gas to power hydraulic fracing was possible, but has not been due to the complexity of both the natural gas supply and the infrastructure. Both companies also told Apache that they would do a trial for Apache without cost.

So far, Halliburton is testing with liquefied natural gas. Its new system would build a simple gas line to the necessary engines by using a quick-connect jumper and would also allow for moving the line easily from job site to job site. Schlumberger is testing with compressed natural gas.

One of the biggest challenges is changing the engines that power the fracing, which are currently built to run on diesel. Diesel engines are designed differently than engines powered by natural gas. The companies got Caterpillar Inc. to create an engine that can run on both diesel and natural gas. The new engines are designed to run on diesel when the machine is idling and natural gas when it is running the pump. A senior Apache engineer, Brian Erikcson, said this new dual fuel engine has been critical to moving forward to develop a process to replace diesel with natural gas in the field.

The project has been going well. The three companies tested eight of the new engines at the Granite Wash in Oklahoma with success, and in December they tried with 12 engines near Elk City. The participants expect this new engine to save the companies tens of thousands of dollars in fuel costs. This has the possibility to be yet another significant advance, making hydraulic fracing both profitable and energy efficient.

Mr. Bahorich has been quoted as saying that “(t)his is a real trend and it’s happening now. We’re witnessing a sea change in the industry that will have a great impact not only on how much less oil is imported but also will help keep our air clean.”

Since natural gas is a much cleaner burning fuel than diesel, a change to natural gas would have environmental, as well as economic benefits.

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April 12, 2013

Big Investment in Texas Oil and Gas Wells for 2013

There is new reason to be energized (excuse the pun!) about Texas’ oil and gas industry in 2013. The last several years have been exciting in this field, and Texas has benefited from its substantial natural resources. Now recent reports indicate that oil and gas companies will spend $28 billion in the Eagle Ford shale play alone in the coming year. That money will infuse the Texas economy, create many new jobs and send billions of dollars in tax revenues to local and state government.

The Eagle Ford is the second largest tight oil play in the United States. It is fifth in the country for shale gas production and is projected to account for 15% of US onshore oil production. North Dakota’s Bakken field is still the largest unconventional oil producer. Wood Mackenzie, an energy industry research and consulting firm commonly called “WoodMac”, studied and analyzed the trends to calculate these numbers for the Eagle Ford. Callan McMahon, an upstream analyst, asserted that the Eagle Ford continues to exceed analyst expectations.

165857_the_oil_derrick.jpg The Eagle Ford has already shown impressive growth, going from 100,000 barrels per day of liquids such as natural gas in early 2011, to 700,000 barrels per day by December 2012. This dramatic increase is, according to WoodMac, due to technology and expertise. A lot of the money spent in the Eagle Ford this year will come from three major operators: EOG Resources, BHP Billiton, and ConocoPhilips. All three were early to focus on Eagle Ford’s liquids-rich areas, and have been rewarded. The Eagle Ford represents 38% of EOG’s upstream value, and 20% of BHP Billiton’s upstream value. According to WoodMac, in resource plays the key is core acreage. This certainly seems to hold true in the Eagle Ford. Most operators are realizing the quality of their acreage just recently. The leading companies, like the three above, not only hold core acreage positions but also own large numbers of acres in the key areas. Smaller companies are also getting in on the action by using joint venture and cost carry agreements to maximize their value per acre.

Mr. McMahon stated that the growth will concentrate on areas with crude oil and condensate exposure. He said, “The pace of growth in the Eagle Ford shale shows no sign of slowing down, and our analysis indicates that Gonzalez, DeWitt, and Karnes counties have established themselves as the sweet spots of the play, and now account for over 50% of daily liquids production.” He expects 74% of the new oil rigs to be in these areas.

It looks like the Eagle Ford will continue to be a bright spot leading economic growth in Texas for the foreseeable future. Mr. McMahon noted, "This is apparent in the massive amount of capital being deployed in the play; (in) 2013 the area will represent 27% of the total capital expenditure onshore in the lower 48 states.”

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April 5, 2013

Government Policies May Hinder U.S. and Texas Shale Production

A few months ago, the nonprofit organization Resources for the Future sponsored a seminar entitled “The Future of Fuel: Toward the Next Decade of US Energy Policy.” The seminar highlighted the future of five key fuels over the next decade--oil, coal, natural gas, renewables, and nuclear--as well as the future of energy efficiency. The opening remarks were presented by Phil Sharp, president of Resources for the Future. Kristin Hayes, a Center Manager for Resources for the Future, moderated the event and Michael Schaal of the federal Energy Information Administration gave a presentation on energy projections.

One of the speakers was Alan Krupnick, a senior fellow and director of the Center for Energy Economics and Policy at Resources for the Future, who asserted that restricting carbon emissions could significantly slow growth in US shale gas production.

He said, “Fugitive emissions are the biggest issue, and if they are considered too high, it could reverse the potential gains.” He noted that most regulation of shale gas comes at the state level, so it can vary widely across the country. Even states with a long history of oil and gas production, like Texas, are still working out the kinks with some local governments.

Mr. Krupnick also cautioned against assuming that other countries could be as successful as the United States has been with unconventional oil and gas production. He used China as an example, where an unconventional well costs $12 million to drill. The same unconventional well would cost $1 to $3 million to drill in the US.

Another speaker at the seminar, Frank Verrastro, a senior vice president at the Center for Strategic and International Studies, discussed the political pressure to create oil and gas regulations at the federal level and about the challenges this presents during an era where the US has plentiful oil and gas supplies but possibly decreasing domestic demand. Mr. Verrastro discussed environmental concerns vis-a-vis the high cost to develop unconventional or ultra-deepwater technology, noting that “regulations should be effective, but not overly burdensome. We should seek a balance.”

Mr. Verrastro addressed the uncertainties in the US energy sector. It is not clear at this point that the efficiency of production will continue to increase and whether the necessary capital investments will continue. He noted that these uncertainties are aggravated by governmental uncertainty, because as governments change, so do priorities in Washington and the statehouses. He stated that “(s)ometimes climate is at the top, sometimes economics, and sometimes energy. That’s what makes it so hard ... to be consistent.”

The balance between government regulation on one hand, and the future of the US energy industry on the other, should be a topic of discussion, not just among politicians, but among the public. We all owe it to ourselves to become informed about these issues, and be part of this discussion.

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March 29, 2013

Texas Supreme Court to Decide How Far Texas Mineral Owner's Activity Can Impact Surface Owner

The rights of Texas mineral owners can be complicated, which is why having a Texas oil and gas attorney review your options is important before you sell or lease your mineral rights or before you buy property in which you will own only the surface.

In many cases, a property owner owns both the surface and the minerals below the surface. However, it is possible to split the ownership, so two different persons or entities own the surface of the land on one hand and the minerals beneath it on the other. In Texas, the owner of the mineral rights has a right to the reasonable use of the surface to produce or extract the minerals, without the permission of the surface owner.

This is where the Texas accommodation doctrine comes in, which is an area of law that is still evolving in Texas. The Texas accommodation doctrine cases hold that, in some cases, the owner of the mineral rights must accommodate the surface owner’s pre-existing surface uses, so long as other means of production or extraction of the minerals are available. It is important to note that this doctrine applies only to the existing surface uses, not possible future uses by the surface owner.

1418448_spring_is_soon.jpg Last year, the Texas Court of Appeals in Waco decided the case of Merriman v. XTO Energy. The case involves Homer Merriman, who bought a 40 acre piece of land in 1996. He only bought the surface, however. XTO Energy owned the minerals beneath Mr. Merriman's land. The deed Mr. Merriman received when he purchased the property clearly indicated the existence of an easement for “mining, drilling, exploring, operating, and developing” minerals. Mr. Merriman, a pharmacist and cattle rancher, used the land as a sort of home base among the other properties he owned for his cattle business. Once a year he brought all his cattle to this particular piece of land to sort them, using stock panels and electric fences. He testified at the trial that these fixtures are not permanent to the land. XTO contacted him in 2007 about building a well on this property. Mr. Merriman said it would ruin his cattle business and refused. XTO offered him $10,000 in compensation, but Mr. Merriman still refused.

Mr. Merriman then filed suit to request a temporary and permanent injunction to stop XTO from building or keeping a well on his property. The trial court granted XTO’s motion for summary judgment. The Waco Court of Appeals affirmed the trial court’s grant of summary judgment, stating that XTO had not violated the accommodation doctrine. The Court of Appeal's opinion noted that Mr. Merriman had other reasonable ways to use the surface for agriculture and even other ways to continue to manage his cattle business, none of which were either “impracticable or unreasonable.” The opinion, written by Justice Al Scoggins, states that “Merriman’s current method of working his cattle is preferable and convenient for him; however, the convenience of the surface owner is not the sole issue.”

The end of the story in this case for Mr. Merriman and XTO Energy remains to be seen. The Texas Supreme Court heard oral argument in this case on February 5, 2013. To date, an opinion on the case has not been rendered. It will be interesting to see if the Texas Supreme Court agrees with the lower courts and if the Justices further develop the accommodation doctrine in Texas, perhaps with further limitations for surface owners who believe their surface uses have been infringed upon by the mineral owner.

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March 15, 2013

Elimination of Tax Deduction Will Hurt Texas Mineral and Royalty Owners

Congress is considering whether to eliminate or limit a federal tax deduction for intangible drilling costs. Intangible drilling costs are those costs incurred to develop an oil or gas well other than the costs of the actual well. It includes costs such as surveying, clearing the land for a well pad or storage tanks, drainage modifications, fuel, and workers’ wages. Current US tax law allows oil and gas companies to deduct these operating expenses from their taxes, exactly like other businesses deduct the intangible business expenses incurred in operating their business.

Understandably, the oil and gas industry is quite concerned about the potential elimination of this deduction. Elimination of this deduction would effectively make exploration, drilling and production of oil and gas more expensive. That means that there will be less exploration, drilling and production in Texas, as well as in other states. In turn, that means that some number of Texas mineral owners who hope to lease their minerals, and who may really need the royalty income, may lose that opportunity.

A coalition of 33 national, regional and state oil and gas associations sent a letter to the leaders of two key congressional committees, the House Ways and Means Committee and the Senate Finance Committee, who are dealing with this issue. Groups who signed the letter included the American Exploration and Production Council, or AXPC, the American Petroleum Institute, the Independent Petroleum Association of America and the Western Energy Alliance, as well as ten other national and two other regional associations and 17 state organizations, including some from Texas.

Bruce Thompson, president of AXPC, told reporters that, “Restrictions on the deductibility of these ordinary and necessary expenses would discourage the massive investment that is needed from this industry to deliver the supplies of American energy to American consumers and industry and to promote America’s energy security.” He warned about the adverse effect on job creation and economic growth in the US. The letter specifically addressed investment, highlighting the key nature of the oil and gas industry to the US economy, noting that it accounts for almost 8% of US gross domestic product (GDP).

If an elimination or restriction on intangible drilling costs is passed, the letter states that companies would be forced to “significantly lower” their drilling budgets to compensate, which would mean less oil and gas production and higher oil and gas prices for US consumers. The letter also stressed that this would actually decrease the amount of revenue flowing to the federal government from the industry. It pointed to the $87 million in daily rent, royalties, lease, and tax payments that are currently paid to the federal government that would be greatly reduced to compensate for higher costs to companies without the deduction. The letter also discussed the impact to economic recovery in terms of job growth, stating that during the recession years the oil and gas industry still managed to directly create 119,511 jobs--well paid full time jobs. Oil and gas industry officials note their average wages are 93% higher than the average salaries in the private sector overall.

The letter concluded by encouraging policymakers to oppose any measure to change the current tax structure in relation to intangible drilling costs. For an industry that is growing by leaps and bounds and has proven to be such an engine for job growth and prosperity, the industry’s request to simply allow the current process to work seems entirely reasonable and sound.

The proposal to eliminate intangible drilling costs as a tax deduction smacks of the vindictive politics of the Obama administration. If the Administration was going to be fair, the tax deduction for intangible costs of all businesses should be eliminated. The fact that the oil and gas industry is singled out suggests that Obama is continuing to whip on that industry as if it were some kind of Evil Empire. This kind of approach is not only naïve, it is completely self-defeating. The far left environmentalists might be pleased, but the rest of us are going to suffer.

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March 8, 2013

Enhanced Oil Recovery Can Be Good for Texas and the U.S.

During all of the budget talks in Washington, DC, I was interested to read a recent report entitled "CO2 Enhanced Oil Recovery" by the U.S. Chamber of Commerce regarding how enhanced oil recovery ("EOR") techniques could add significant revenue to the Texas and federal budget, as well as enhance our energy security and benefit the environment!

Enhanced oil recovery is a general term that refers to techniques for increasing the oil that can be extracted from a given oil field. The type of enhanced oil recovery technique discussed in this report is carbon dioxide recovery. It works by pumping carbon dioxide into the reservoir, and the gas improves the flow of the remaining oil. Once the oil-carbon dioxide mixture reaches the surface, the two are separated and the carbon dioxide is recycled back into the reservoir. The U.S. is already leading the world in this technique and it is providing nearly 6% of our onshore oil production.

eor_co2process.jpg The new report was written by the Chamber's Institute for 21st Century Energy. The report notes that the U. S. Department of Energy estimates that enhanced oil recovery could produce 67 billion barrels of oil, which is three times the size of the U.S. current proven oil reserves. If the price is $85/bbl, $1.4 trillion in new government revenue would result directly from these procedures, in addition to billions in private investment.

Karen Harbert, the president of the Institute, also noted that enhanced oil recovery would be better for the environment as well. The technology can take carbon dioxide captured from things like industrial and power plant sources and use it to enhance oil production. Ms. Harbert said, “EOR will increasingly utilize carbon dioxide that would otherwise be emitted into the atmosphere, while generating additional oil production from fields that are in decline.” At the end of the process, the carbon dioxide remains in the oil field, not in the air. It does not affect new lands, since it is used in existing producing oil fields.

Ms. Harbert said EOR could be “one of the next big things in energy production”. Although it should not be seen as a replacement for new production, it could be a valuable tool in helping the U.S. to become energy self-sufficient. Even President Obama seemed to understand this need. In his State of the Union speech earlier this year he highlighted the need to have an “all-out, all-of-the-above, strategy that develops every available source of American energy”. Enhanced oil recovery with carbon dioxide may have a unique place as a win-win technique in which everyone benefits. EOR techniques should play a larger role in the discussions on energy and government revenues. Ms. Harbert was right to point out that “(a)t a time when lawmakers are seeking to avoid falling off fiscal cliffs, increasing energy production and the resulting government revenue, jobs, and economic growth should be at the top of the agenda.”

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February 22, 2013

New Texas-Colorado Oil Pipeline

Recently, NuStar Energy LP announced that they are proposing a new system of oil pipelines to bring oil from the Niobrara Shale in Colorado to Texas’s oil refineries. The Niobrara Shale is a promising play and there is a need to get the oil produced there to refineries that can process the increasing amount of oil. Colorado is set to produce between 42 and 44 million barrels of oil this year, in a growing industry for the state. NuStar is calling this new pipeline project the “Niobrara Falls Project.”

The new pipeline would extend from Niobrara, which is near Platteville and Watkins, to an already existing pipeline in Denver. From there the oil would be transported via Denver to a McKee, Texas pipeline, which has a capacity of about 70,000 to 75,000 barrels per day. From McKee, the project would utilize other existing pipelines to get the oil to refineries in Wichita Falls, Texas. NuStar states that once the oil gets to Wichita Falls, it can be sent to the Nederland-Beaumont, Texas market and the Cushing hub via other third-party pipeline connections in Wichita Falls. This pipeline could also supply refineries such as Suncor Energy’s Denver refinery, Valero Energy’s McKee, Texas refinery, Ardmore, Oklahoma refineries, and WRB’s Bolger, Texas refinery. The new pipeline system could also transport oil from Granite Wash and Permian basin to Dixon, Texas, where NuStar has a tank farm.
Eurek_Plains%2009282012.jpg To find out what kind of interest exists for this new pipeline project, NuStar held a binding open season the end of last year. A binding open season allows companies to make a long-term commitment to use the pipeline. Commitment terms of five, seven, or ten years are available for this project.

NuStar, based in San Antonio, is one of the chief US pipeline operators. The company currently has 8,433 miles of pipeline, 82 terminal and storage facilities that store and distribute crude oil, refined products, and specialty liquids, and a fuel refinery with a capacity of 14, 500 barrels per day. NuStar expects to have the Wichita Falls pipeline section available for shipping by the second quarter of 2013 and is hoping to have the entire Niobrara Falls Project up and running by the first quarter of 2014.

New pipelines are a symptom of success. Oil produced from wells needs to get to refineries and then to market. They are indicative of economic growth and prosperity for our states, like Texas and Colorado. These pipelines will also affect individuals, specifically, those who own land in the way of the prospective pipelines. If you are one of those individuals in Texas, please review my recent post on the subject (read it here) about why you may need a qualified and experienced pipeline easement attorney!

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February 15, 2013

Natural Gas Self Sufficiency in Texas and the US

The United States, including Texas, will be self-sufficient in natural gas within the next ten years, according to a recent survey of oil and gas professionals. The survey, entitled Energy Independence and Security: A Reality Check was published by the Deloitte University Press. There is less optimism about self sufficiency in oil, however. Deloitte released the results of this survey at their recent Oil and Gas Conference in Houston, and the full report will be available shortly.

The survey questioned 250 oil and gas professionals. The participants averaged about 20 years of experience in the oil and gas industry. Also, all the participants had college or graduate degrees and were primarily executives.


Of those surveyed, 75% think the US is already self sufficient in natural gas or will be within ten years. John England, the vice chairman of Deloitte, said: “It’s not surprising that oil and gas decision-makers are enthusiastic about the role of natural gas in our national energy future, given burgeoning supplies, America’s comparatively low cost of extraction, and its relative cleanliness.” He noted that the most surprising thing about natural gas is that just a few years ago the country was prepared to import it. How quickly things changed. In relation to gas prices, 86% responded that in 2013 the price should remain at less than $4/MMbtu. 40% predict prices lower than $3/MMbtu.

A majority (51%) of participants also think that current estimates on recoverable natural gas from shale plays is correct. The remaining respondents were evenly split on whether current estimates were somewhat overestimated or underestimated. Roger Ihne of Deloitte said that this shows the strength of the assertion that the US has bountiful shale resources, as “over 95 percent think the current industry estimates are accurate or not far off.”

Industry participants in the survey were so optimistic about America’s natural gas possibilities that a majority believe the US will export liquefied natural gas in the future. 72% believe the government will approve of such exports, and 36% believe the approval will come before 2014.

On the other hand, 56% of participants believe the US will never be self sufficient in oil and only 26% believed self sufficiency in oil is possible within ten years. But the participants also thought that light, sweet crude oil prices would remain high in 2013. They particularly noted that West Texas Intermediate oil, on average, should be about $80 to $99/ bbl in 2013.

Most of the survey participants expect increased investment in the industry in 2013, as well. 60% said there will be increased capital spending and 53% think there will be “much more” or “a little more” activity in mergers and acquisitions. 65% expect more exploration in the Gulf of Mexico, as well. On the Keystone Pipeline, 78% think the government will eventually approve the project, with 42% expecting approval in the next year.

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February 8, 2013

Oil and Gas Well Fracing Findings in Wyoming Likely Wrong

Ever since Gasland came out and hydraulic fracturing became a hot topic that everyone, even people with no knowledge of the field, had an opinion about, the federal government has sought to use the issue for political gain. When people in Pavillion, Wyoming, complained about their drinking water and claimed that hydraulic fracturing, or fracing, had contaminated their wells, the Environmental Protection Agency (EPA) went rushing out to do tests.

The EPA constructed two monitoring wells and tested water samples from these wells. It issued a draft report in December 2011, concluding that it was “likely” that fracing contributed to water contamination, and claimed that they found elements of methane, ethane, diesel components, and phenol in their samples. Oil and gas industry experts at the American Petroleum Institute (API) criticized the study at the time for its unscientific data and flawed research methodology. One of API's directors, Erik Milito, noted that the lack of properly conducted research also casts doubt on the EPA’s upcoming national study.

Another federal government agency, the US Geological Survey (USGS), also tested in the area and came to different results, described in two public releases, the "Sampling and Analysis Plan for the Characterization of Groundwater Quality in Two Monitoring Wells near Pavillion, Wyoming" and the other entitled "Groundwater-Quality and Quality-Control Data for Two Monitoring Wells near Pavillion, Wyoming, April and May 2012".

USGS found no evidence of some of the chemicals claimed in the EPA study, and others were found to be present at significantly lower levels than reported by the EPA. USGS worked in cooperation with the State of Wyoming, the EPA, and Wyoming’s native tribes to come up with its scientific findings, but the agency did not analyze the findings. USGS also only sampled from one of the two EPA wells, indicating that the other well could not provide a sample of representative water conditions, raising further concerns about how the EPA constructed the test wells in the first place. Wyoming’s Governor Matt Mead praised the USGS’s process over that used by the EPA, because the USGS allowed state experts to collaborate and have a say in the methodology. (Imagine that! Getting input from local experts who know the area! What a concept.)

The owner of the natural gas wells in the Pavillion area, Encana Oil and Gas, also questions the EPA’s results and asserts that the monitoring wells were poorly and improperly constructed. Problems with the EPA’s methods include possible cross-contamination of groundwater during the EPA’s drilling, and misrepresentation of monitoring well depths versus the depth of average drinking water sources. Encana indicated that contaminants that were actually found in the water samples by EPA are naturally occurring in the area, and are not the result of hydraulic fracturing. Mr. Milito of API agreed with this assertion, saying, “[W]hile EPA has yet to acknowledge this, hydrocarbons are naturally occurring and have historically been detected in groundwater in the Pavillion area. It is not unexpected to find hydrocarbons in groundwater in a hydrocarbon-bearing formation.” He was also worried that if the EPA thinks the Pavillion tests were scientifically sound and useful, they will use continue to use shoddy construction and inexpert techniques in other testing areas. He urged the federal government not to make regulations based on such unscientific data.

There's a second issue here besides the problems with the EPA's methodology. I think there is a fair basis for suggesting that EPA may have actually doctored the water samples to make fracing look bad. It won't be the first time that a bureaucrat has changed the facts to advance their ideology. After all, isn't that what our President does all the time?

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February 1, 2013

Another Study Shows Job Creation Due to Oil and Gas Shale Wells in Texas and U S

Another independent study titled “America’s New Energy Future: The Unconventional Oil and Gas Revolution and the US Economy,” released recently concluded that shale oil and gas drilling and development has helped create 1.75 million jobs in the last few years in the United States. The study also indicated that there was a possibility of 2.5 million new jobs by 2020 and 3.5 million by 2035. The study was done by IHS-CERA, an independent global energy research firm, and was commissioned by a group led by the US Chamber of Commerce’s Institute for 21st Century Energy. Other organizations that supported the research for this study are the American Petroleum Institute, the American Chemistry Council, and the Natural Gas Supply Association.

This study is the first of a series of three intended to shed significant light on the impact of shale development. This first study, titled “National Economic Contributions”, is about the impact of “upstream operations,” that is, oil and gas extraction. The second study will look at the impacts of shale development on a state by state basis. The third will go into “downstream operations”, or the impact of shale development after production.

This particular effort claims to be the first to examine the nationwide impact of shale energy development and to provide concrete numbers about the beneficial developments. Karen Harbert, the President and CEO of the Energy Institute, explained that this study is proof that shale energy is a game changer for the US. She said, “This new, comprehensive study demonstrates that shale energy is already contributing over $200 billion to our economy, with much more to come, if policymakers at all levels of government don’t stand in the way.”

The report also indicates that this industry is also poised to directly benefit local governments at all levels. For example, this year shale is responsible for $62 billion in tax revenue according to this study. By 2035, shale energy development is expected to bring in more than $2.5 trillion in tax revenue, more than half going to state and local governments. This revenue can assist in paying down the deficit and can fund important programs for Americans. On top of that, trillions of dollars are expected to be invested by the energy industry as well, bringing continuing growth to our economy and creating jobs. In 2012 alone, $87 billion was invested in shale development.

Another obvious benefit of shale development discussed by the study is the continuing movement toward energy independence for the country. The research showed that, thanks to shale, the US now has enough natural gas to supply the country for 100 years. Shale development will reduce the need for oil imports by as much as 60 percent by 2020. Ms. Harbert said that the US would therefore spend $200 billion less on imported oil. Shale has already led to a 25% increase in oil production in the last four years. Further increases are expected, with 2015 numbers expected to be 46% higher than 2008 oil production, and a 68% increase by 2020.

While not discussed directly by this study, the profit generated by shale development also gets paid to shareholders of energy stocks, the majority of which are individuals like you and I, as well as retirement funds for individuals.

The "$64,000 Question" is this: are our local, state and federal government agencies going to work with energy companies to create balanced and responsible shale development, or will they be swayed by the false claims of some energy opponents? Remains to be seen, friends.

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January 25, 2013

New Fracing Study Verifies Fracing Safety for Texas Oil & Gas Producers

There is more evidence from yet another study, the "Hydraulic Fracturing Study", published in October 2012, that concludes that hydraulic fracturing, or fracing, is safe and does not pollute either air or water or cause earthquakes. This study was prepared for Plains Exploration & Production Co., an independent oil and gas company, and the Los Angeles County Department of Regional Planning, and was conducted by Cardno Entrix, an international environmental and natural resource management consulting firm. The study examined two test wells at the Inglewood Oil Field in Los Angeles County, California, and determined that there were no detectible indications that fracing might induce earthquakes or have a negative impact on air or water quality.

The Inglewood Oil Field is one of the largest urban oil fields in the United States and is adjacent to Baldwin Hills, View Park, Windsor Hills, Blair Hills, Ladera Heights, and Culver City, California. The oil field was discovered near Culver City by Standard Oil in 1924. Plains Exploration has been operating there since December 2002, and conventional fracing has been used in the field by prior operators. The field contains 1,200 acres and a total of 1,475 wells have been drilled. 469 wells are in active production and 168 waterflood injection wells are active at this time.

496561_la_palm.jpg The Cardno study was part of a settlement in 2011 of a lawsuit filed in 2008 against Los Angeles County and Plains Exploration over land use. Schlumberger Ltd. and Pinnacle, a company owned by Halliburton, did the micro-seismic monitoring and fracture mapping. Plains Exploration also did a high-rate gravel pack job at two different wells earlier this year to help collect information for this study. The study concluded, in part, that: “(t)ests conducted before, during, and after the use of hydraulic fracturing and high-rate gravel packing showed no effects on the integrity of the steel and cement casings that enclose oil wells. There is also an ongoing program of well integrity tests at Inglewood oil field.”

The study found that noise and vibrations associated with fracing were within the allowable limits established by the Baldwin Hills Community Standards District. The emissions were found to be within the regional air quality regulation standards of the South Coast Air Quality Management District. The Los Angeles County Department of Public Health did a community health assessment and reported that it found no statistical difference between the health of the community around the oil field as compared to the health of residents of Los Angeles County overall.

While this study and related facts deal with California, the findings are applicable to all areas where the safety of fracing is unfairly attacked. Energy producing states, including Texas, can use the growing evidence from across the United States, and in other countries around the world, to show that the hysteria over fracing is political and not grounded in scientific fact.

This study is also a reminder that local governments are in the best position to understand the particular geology and circumstances of their particular geographic areas and can best determine how to regulate fracing. The Los Angeles health report determined, “The long history of oil production in the area provides operators with an excellent understanding of the local subsurface conditions and reduces standard risks and uncertainties that would be present in new operations.”

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January 18, 2013

The Problem with Duplicate Fracing Regulations

American Petroleum Institute’s Chief Economist John Felmy has warned policymakers that unnecessary duplicate regulations could obstruct the development of unconventional oil and gas plays in the US. He pointed out at a news conference in Washington, DC that these plays have already created jobs and helped improve economic conditions in many areas of the country.

Mr. Felmy restated API’s position that regulation by state agencies is best suited for shale development and techniques like hydraulic fracturing, or fracing. He particularly noted the “North Dakota Miracle,” which turned that state into the number two oil producer in the nation and reduced unemployment to three percent while increasing incomes overall. He also highlighted other successes in states such as Texas, Arkansas, Ohio, Pennsylvania, and Louisiana. API and the industry are getting involved in states to raise awareness about the economic benefits of shale, including doing workshops in shale states. API has also issued fracing best practice guidelines, which can be helpful for a discussion of safety standards and industry safeguards. These standards include information about well construction and integrity, water management, mitigating surface impact, environmental protection, and isolating potential flow zones during well construction.

Aside from these statements regarding state regulations, Mr. Felmy also spoke at a recent DC conference about the possibility that New York may lift its high-volume fracing ban. New York is home to part of the Marcellus Shale, and there is potential there for growth and development. Fracing has taken place in New York since the 1950s, and horizontal wells since the 1980s. Both are legal. But newer technology with high-volume fracing, which makes it possible to get to oil and natural gas that was unreachable before, has been banned since 2008.

There is talk by state officials of lifting the ban on high-volume hydraulic fracturing in at least some areas of the state. Governor Andrew Cuomo talked to reporters last summer about lifting the ban in struggling counties on the Pennsylvania border, if the towns approve of the use of the fracing technology. Mr. Felmy said he was hopeful the Governor would follow through and asserted that polls show a large majority of New Yorkers believe the oil and gas industry and natural gas development will bring jobs to the state. A 2011 study commissioned by API showed that, were the ban lifted, the state could see over 47,000 total jobs created in 2015 and over 64,000 in total jobs in 2030, up from the current estimate of 14,800 jobs for both years. In addition, lifting the ban in New York could result in revenues of $83 million per year by 2015 and $456 million per year by 2030.

Mr. Felmy said that “(w)e remain committed to safe and responsible development of our shale energy resources and to working closely with the states to ensure effective, appropriate regulation.”

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January 11, 2013

Oil and Gas Well Drilling Boom in the Eagle Ford in Texas

Another company is increasing its presence in South Texas in the Eagle Ford Shale. Penn Virginia Corporation has increased its holdings by 4,100 net acres in Gonzales and Lavaca counties for $10 million. This brings the company to 31,000 net and 41,100 gross acres in the Eagle Ford. In Gonzales County, the new 3,200 net acres is adjacent to Penn Virginia’s development area and is estimated to have 20 horizontal well locations. The 895 net acres in Lavaca County is complimentary to existing Penn Virginia locations in nine units, with an estimated additional 10 horizontal well locations.

This activity is bringing an economic boom to South Texas. The Railroad Commission of Texas has issued an estimated 4,293 drilling permits for the Eagle Ford in 2012 alone. This has brought jobs to a region that long suffered from double digit unemployment and poverty.

1236528_cactus.jpg “If you’re looking for a job, this is the place to be. If you want to relocate, this is the place to be," said Diane Laplow of San Antonio. There were 48,000 new jobs created by activity in the shale last year. Aside from working directly in the oil and gas industry, this boom is bringing opportunities for small business as well, creating many jobs in other sectors of the local economy. For example, people are opening family businesses, like restaurants, to feed hungry oil workers. “It’s a very good spot to start a business," said Sarah Cadena, a native of the area whose family now owns a burger and wings joint on a busy highway.

The area has grown so much so quickly that it has actually caused some growing pains, and the Eagle Ford Consortium is working on this. According to its website: "(t)he Consortium is composed of stakeholder representatives of a cross-section of community members. The group offers a forum for beneficial education and information-sharing among agencies and an opportunity for agencies to identify common issues and work together on defining potential solutions." These growing pains include including roads clogged with truck traffic, overburdened utilities, and a severe housing shortage that’s given rise to "man camps" for workers. Trailer parks are springing up to house oil workers, and many people sleep in bunk beds in places with several other workers. Long lines have plagued grocery stores and gas stations, because the availability of these services has not caught up with the population. Restaurants are crowded and prices have gone up dramatically.

But all of this overall is great news for South Texas. The bottlenecks of housing and retail services will be resolved in time, with even more jobs in construction to serve these workers, which in turn will create a stronger and more diverse economy in this region of Texas.

Leodoro Martinez, chairman of the Eagle Ford Consortium, said, “[This] is a huge change, if you know the history of South Texas, the border area, our high unemployment rate, our poverty level. This is a total transformation of that -- the opportunity to have success stories."

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January 4, 2013

Sanchez to Accelerate Oil & Gas Drilling in Eagle Ford Shale, Texas

Sanchez Energy Corporation, a fast growing independent oil and gas company based in Houston, Texas, announced recently that it will accelerate its 2012-2013 drilling in the Eagle Ford shale play. This shale play covers 11 million acres from the Mexican border in South Texas to East Texas near Louisiana and covers 1/16th of the state of Texas. It has a unique geologic composition that allows for more production of oil and gas than other shale areas, and it is an excellent candidate for the use of hydraulic fracturing, or fracing.

Sanchez has a 95,000 net acre position in Eagle Ford, and the corporation is gathering cash from proceeds from a recent private placement of preferred stock, using the $144.6 million in proceeds to fund capital expenditures. Those expenditures focus on accelerating the drilling program across all Eagle Ford operating areas. Tony Sanchez, III, President and CEO of Sanchez, said, "Our recently closed $150 million convertible preferred offering, combined with our future cash flow from operations and modest debt from our anticipated credit facilities, provides the liquidity to continue executing and accelerating our drilling plans in 2012 and 2013." In addition, the company will close shortly both a $250 million first lien revolving credit line, with an initial borrowing base of $27.5 million, and a second lien loan also of $250 million, with an initial commitment of $50 million, to provide more cash for the Sanchez expansion of operations.

With the money it has raised, Sanchez can grow and expand—the company has already identified 800-1200 potential drilling locations. Production has grown more than 90 percent just since the end of June, 2012, with 2300 barrels per day of oil equivalent being pumped by the end of August, 2012. The company sees a rate of 4000 to 5000 barrels of oil equivalent per day by the end of 2012, due to the more developmental-type drilling planned.


As the NASA photo above shows, the Eagle Ford is a big deal. The increased drilling by Sanchez and others will benefit numerous areas of the Eagle Ford in Texas, and will be a growth engine for our economy and our growing oil and gas industry in Texas. In the Palmetto area of Gonzalez County, Sanchez plans to start as many as 12 gross and six net wells by the end of the year, up from an initial plan of nine gross and 4.5 net wells. In the Marquis area of Fayette and Lavaca Counties, the company had initial expectations to drill six gross and net horizontal wells this year, but it now plans for nine gross and net horizontal wells. In the same area, a rig is expected to drill continuously in Prost, where Sanchez estimates as many as 32 more development locations are possible after 3D seismic is shot and interpreted early next year. Also in 2013, central production and gas gathering lines are going to be laid in this area. In the Maverick area of Zavala and Frio Counties, the company will drill horizontal wells continuously through 2013 and has identified 235 to 350 potential drilling locations with 60 to 90 million barrels of oil equivalent potential.

In tough economic times, news like this shows that Texans should be excited and hopeful for the future thanks to the incredibly rich resources our state is lucky to possess.

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December 28, 2012

Hoeven Bill Makes Texas Primary Regulator of Fracing of Gas Wells

As we’ve seen time and time again, at least in Texas, state government is in the best position to regulate the energy industry in areas such as hydraulic fracing. Texas has done a good job of using its laws and its court system to deal with the issue in a reasonable and sensible way, promoting the oil and gas industry for economic growth and energy independence while also making sure Texans, their property rights and their environment are safe.

North Dakota Senator John Hoeven’s new bill is a welcome move in Washington for those of us working in oil and gas law. Senator Hoeven, who is on the Senate’s Energy and Natural Resources Committee, is calling it the Empower States Act. He told reporters in Bismarck, North Dakota that “(t)he legislation also recognizes that states have a long record of effectively regulating oil and gas development, including [fracing], with good environmental stewardship.” He went on to assert that “(w)ith the right policies, I believe we can get our country to energy independence in five to seven years.”

Senator Lisa Murkowski of Alaska immediately signed up to cosponsor the bill. “Senator Hoeven's bill provides for local accountability, local knowledge, and local communication instead of a one-size-fits-all federal approach to regulation" Senator Murkowski said while she was in North Dakota for a two day tour of the technological advances used in the Bakken shale region. She said that it “makes sense” to let the states take the lead on regulations in oil and gas development.

If the bill passes and goes into effect, any federal agency or department would be required to hold a hearing and consult the state, Indian tribe and local government affected by any proposed new regulation on oil and gas development. The agency proposing the new regulation would also be required under the bill to create an energy and economic impact statement identifying any potentially adverse effects on energy supplies, reliability, and price, and discuss possible job losses and revenue decreases to the states’ general and education funds. The federal agency would also have the burden of showing that the new regulation is needed to prevent immediate harm to humans and the environment. Senator Hoeven said this is intended to prevent arbitrary decisions by the Environmental Protection Agency (EPA), which has been a serious problem in recent years, and will allow states independence in determining what is best for their unique geological circumstances. Finally, the bill includes an opportunity for redress in the federal courts, either in the state or in the District of Columbia. The federal court would be required to examine the regulation itself, rather than relying exclusively on the EPA’s (often biased) findings.
In addition to Senator Murkowski, the bill has attracted the support of the American Petroleum Institute. API’s president Jack Gerard said, “Hydraulic fracturing has been used safely for more than 60 years, and the states are well-equipped to ensure that record continues. The Empower States Act recognizes that states are getting the job done when it comes to robust regulation of [fracing].”

The bill was still in a Senate Committee at the end of the 2012 session. Let's hope it is taken up again in 2013.

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December 21, 2012

Texas Natural Gas Engineering Degree Offered Again

There is good news for anyone wanting to make a career in the growing field of gas development! This year, after more than a dozen years, students will be able to study for a degree in natural gas engineering at Texas A&M University, Kingsville.

When the university’s engineering program started in the 1930s, this natural gas degree was among the first introduced by Frank Dotterweich, a former dean and now the namesake of the engineering school. For most of the 20th century, countless engineers graduated with this degree and went to work in the oil and gas industry. As the Kingsville university president said, “We were internationally famous for that program.” But it started to become less popular in the 1990s when fuel prices were very low and led to a weak market for job seekers. Texas A&M suspended the degree in 2000, but still kept a graduate degree in the area for those wishing to specialize.

533027_cap_and_diploma.jpg But things have changed, and now Texas is in the middle of an energy boom, which is especially advantageous for the Kingsville campus of Texas A&M because of its proximity to the Eagle Ford shale. The boom in natural gas industry jobs have created renewed interest in getting this type of engineering degree. And the fast pace of technological advancement in this field has increased the need for well educated professionals who are able to use the specialized technologies that gas production uses today. There is also a need for people who know how to design pipelines to take natural gas to the market, and at the moment there is a void of qualified candidates. Currently, many companies are training engineers from other fields in gas and gas pipeline engineering themselves.

By January 2112, the Texas A&M was getting at least five calls a week inquiring about a degree in natural gas engineering. Former students and also energy industry groups took the initiative to push for the return of this degree option, which was approved by the Texas Higher Education Coordinating Board in June 2112. Stephen Nix, the current dean of the Dotterweich College of Engineering said, "We are certainly excited to offer this type of opportunity for students in South Texas."

Students choosing to major in natural gas engineering this year will take classes through the engineering college’s Department of Chemical and Natural Gas Engineering. The first course started with the new academic year recently and is entitled Fundamentals of Reservoir Engineering. The class has space for 20 students. Mr. Nix told reporters that some of those students would be incoming freshman, but others will be older students who will transfer into the program. He characterized them as “waiting in the wings” for the natural gas degree to be offered again. The goal is to have a minimum of 60 students in the program by 2017. Mr. Nix asserted that in a few years the programs new graduates will be well equipped to pursue professional opportunities in natural gas, which he claims is “the fuel of the 21st century”.

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December 14, 2012

Challenge to New EPA Ethanol Standard Dismissed

Texas gas retailers are in for a tough time. The federal Court of Appeals for the DC Circuit ruled earlier this year in favor of the Environmental Protection Agency (EPA) on a challenge to the introduction of a higher corn ethanol blend in gasoline. The new higher blend would contain 85% gasoline and 15% ethanol, and is nicknamed “E15”. It is an increase over the old 10% ethanol standard. The EPA approved this new blend in 2011 for cars and light trucks made since the model year 2000, but banned it for light equipment and older vehicles. Bio-fuels makers sought the higher blend rate as a way to satisfy a federal guarantee of a share of the gasoline market, set at 13.2 billion gallons in 2012 and rising to 15 billion gallons annually from 2015. The EPA gave its final regulatory approval of E15 in June 2012.

In the legal challenge before the DC court, food businesses claimed that E15 would raise the price of corn. Governors from four poultry-raising states asked the EPA for relief from this E15 mandate because of its impact on feed. The worst drought in 50 years has seen the corn crop decrease by 13% this year, and the governors say that this crop is too small to withstand 40% of it being used in fuel without a severe economic disruption.

1394537_corn_field_-_inside.jpg The engine manufacturers claimed they could be open to liability if their engines malfunctioned due to the new fuel blend. Charles Drevna, the president of the American Fuel & Petrochemical Manufacturers, and Bob Greco, a director at the American Petroleum Institute, both claimed that E15 approval comes before testing of E15 in vehicles is complete and that it has already been shown to cause damage to engines. Vehicle manufacturers are already putting warnings on their gas caps that using E15 could void their vehicle warranties.

The opinion of the three judge panel on the DC Court of Appeals ruled two to one that the petroleum industry, engine manufacturers and the food industry did not have legal standing on the matter. The Court stated that these industries failed to sufficiently demonstrate how they were harmed by the approval of E15. Critics find this astonishing, especially for the petroleum industry, which is required to comply with the federal mandate on ethanol in the 2007 Energy Independence and Security Act.

Currently, only one gas retailer in Kansas is selling E15 fuel. There are practical barriers to the new requirement, such as installing new blender pumps that can dispense this type of fuel. Out of 160,000 gas retailers in the United States—gas stations, truck stops, convenience stores, grocery stores and marinas—only about 2,500 have pumps that can handle gasoline blends higher than the old E10 blend. Aside from the expensive practical barriers, a lot of businesses are afraid of liability if something goes wrong with the E15 gas blend, such as someone putting it in a car not meant to burn it, thus harming the car's engine or voiding the warranty. Business owners note that consumers are not asking for E15, and its use will likely be slow to spread.

The ethanol industry has been going down the tubes for years. This is the federal government's way of trying to shore up another losing proposition.

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December 7, 2012

Chesapeake Backing Out on Texas Oil and Gas Leases?

A few recent cases involving Chesapeake Energy Corporation backing away from potential oil and gas leases are raising alarms. Obviously a contract is only as good as its enforceability. It goes without saying that landowners need to be diligent so that they are not taken advantage of by large oil companies. Many complex legal issues are involved in contract disputes, and experienced legal help is always crucial. For example, in one case from earlier this year, Kantner v Chesapeake Energy Corp., a Texas Court of Appeals found that individual landowners lacked standing to bring a breach of contract claim when the contract was between Chesapeake and a landowners committee.

In this particular case, the plaintiffs were owners of property in Deer Creek Estates in Crowley, Texas. In 2007 and 2008, a Deer Creek Estates Residents Oil and Gas Lease Committee was formed to negotiate oil and gas leases with Chesapeake. The Committee and Chesapeake negotiated and agreed to two documents, a Supplemental Agreement Regarding Gas Leases and a “form lease.” However, the Committee did not have the authority to bind any of the landowners to the terms of either document. The form lease actually stated that none of the landowners were required to sign it, allowing each landowner the right to negotiate his or her own lease.

Because of its own financial issues, Chesapeake decided not to proceed with leases in Deer Creek Estates, and the landowners sued for specific performance of what they claim was a contract negotiated between their Committee and Chesapeake. The documents negotiated by the Committee provided for a $27,000 per net mineral acre signing bonus, a 25.25% royalty, and a three year term with no renewal option. The signing bonus was to be paid by a thirty day bank draft at signing.

In the lawsuit, the landowners admit they did not execute the Supplemental Agreement or the form lease, but claim they have standing as third party beneficiaries of the agreement between their Committee and Chesapeake. The trial court granted Chesapeake's motion for summary judgment, and found that there was no evidence that the landowners were third party beneficiaries.

The Court of Appeals for the Second District of Texas in Fort Worth agreed with the trial court and found that the purported contract between the Committee and Chesapeake did not sufficiently identify the landowners as third party beneficiaries. In doing so, the Court cited a similar case, Maddox v. Vantage Energy LLC, in which the appellants also attempted to claim third party beneficiary status on a contract but failed to provide sufficient evidence of that status. As in Maddox, in Kantner the landowners are not specifically named as third party beneficiaries in the agreement with Chesapeake. The landowners were not identified by address and no map was attached to show which lot numbers or addresses were affected by the contract. The purported contract contains no defined limited group as intended beneficiaries. Taken together, all this led that Court to find the landowners were not third party beneficiaries.

The Court also considered whether the landowners were “donee” beneficiaries. However, if specific performance on the contract were to be granted, there would be no donation, but rather an exchange for mineral rights. Therefore, the landowners weren't donee beneficiaries either.

These cases have obvious implications for future oil and gas leases in our area. Many neighborhoods and subdivisions have this type of committee to negotiate efficiently for larger groups, and Texans should be aware of how the law in the area works to be informed of their rights. The lessons from these cases should be incorporated into future agreements with oil companies so that landowners are protected in the event the oil company tries to back away from its leases.

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November 30, 2012

New US Oil and Gas Reserve Estimates

The United States Geological Survey (USGS) released a new estimate last week on the US’s oil and gas reserves. The new estimate for 2012 is part of the Reserve-Growth Assessment Project. It found 32 billion barrels of crude oil, 291 trillion cubic feet of natural gas, and 10 billion barrels of natural gas liquids as potential undiscovered US reserves. The USGS estimate stated that these amounts represent about 10% of the overall US oil and gas endowment and do not include reserve growth estimates for federal offshore areas.

Most reserve growth results from the delineation of new reservoirs, field extensions, improved technology that enhances efficiency, and recalculation of reserves due to shifting economic and operating conditions. For this estimate, fifty-five large oil fields and thirty-five large gas fields significantly contributed to the reserve growth. Within the fifty-five oil fields, sixty-eight individual conventional accumulations (i.e. reservoirs or groups of reservoirs) were identified and assessed. In the gas fields, two accumulations were individually assessed. The sixty-eight individually assessed oil accumulations accounted for seventy percent of the potential reserve growth in the United States. The other thirty percent is from smaller accumulations estimated by the regression methods.

The estimate noted that no attempt was made to gauge economically recoverable resources, so resources such as shale gas, tight gas, tight oil, and tar sands were not included in the USGS’s study. The USGS used detailed analysis of geology and engineering practices, which departs from the methods of previous reserve growth estimates which relied entirely on statistical extrapolations of growth trends. The USGS used both public and commercial geologic information and field production data.

Director Marcia K. McNutt said, “By providing geologically based, domestically consistent estimates of the potential additions of oil and gas from the growth in reserves in known fields, and placing that information in the public domain, we are furnishing a valuable projection on how much and where fossil fuels may be produced in the future.” Director McNutt went on to say, “When combined with our estimates of undiscovered resources, policymakers can obtain a more complete picture of domestic, technically recoverable oil and gas.”

The full picture of technically recoverable oil is even brighter, with a recent study by the Institute for Energy Research putting it at 1.4 trillion barrels in the United States. The largest deposits are offshore, in Alaska and in shale in the Rocky Mountain west. This study asserted that there is enough oil to last America’s consumption for 250 years, and 175 years worth of natural gas. In terms of coal, the North American countries- the US, Canada, and Mexico- together have 497 billion short tons of recoverable coal. That coal could power the US at the present rate of consumption for 500 years, according to this study.

Looking at our energy resources in any light, it is clear that the United States has been geologically blessed with considerable resources. To those of us working in or with the oil and gas industry, this demonstrates that if the US experiences high prices or gasoline or fuel oil shortages, it is probably the result of politics rather that lack of resources.

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November 23, 2012

Eminent Domain, Texas Pipelines and Texas Landowners' Rights: Update on the Denbury Case

The Denbury case was one of the most important developments in Texas oil and gas law in the past year, and this blog reviewed the March, 2012 Texas Supreme Court ruling here. In summary, the Denbury case involves a landowner who objected to a private energy company’s use of the eminent domain statute to appropriate his land for a gas pipeline. The Court found for the landowner.

The decision in March not only denied Denbury Green Pipeline’s motion for a rehearing, but also clarified the Court's original opinion (see my post here) in several respects. The Court added that "private" means a pipeline that is limited in its use to wells, stations, plants, and refineries of the owner. The Court went on to say that a “common carrier” means that the company is transporting gas for hire and therefore implies more customers for the gas than just the owner of the pipeline. The Court upheld its view from the prior ruling that the Denbury pipeline was for private use only.

In August, the latest decision by the Texas Supreme Court ruling in Denbury was issued, written by Justice Wainwright with Justice Johnson concurring. The two justices joined the main decision issued in March and reaffirmed that simply checking a box on a Texas Railroad Commission form is not sufficient to make a company a “common carrier” under the law. However, they issued this separate opinion to distinguish their views on the scope of the Court’s holding.

This opinion agreed that some affiliate relationship is not sufficient to support a finding that gas transport is for the public’s benefit, but stated that the Court should take care not to issue pronouncements exceeding the scope of the dispute at hand. This latest decision points out that the scope of the term “affiliate” used in the Court’s previous opinion is broader than the referenced definitions of “affiliate” in natural resource statutes and regulations. This could lead to an interpretation of “affiliate” from the Court’s decision that is broader than intended by the Legislature. Justice Wainwright wrote, “[T]he Court’s use of this broad term could result in a conclusion that an entity owning just one share of the pipeline owner’s stock is an ‘affiliate’ and the pipeline owner is therefore not a common carrier, without any evidence of control.” Justice Wainwright emphasized that the Court can protect property rights under the Constitution without undermining Texas’s law of corporate entities’ separateness. The opinion goes on to state that the disqualifying affiliate relationships should be more clearly set out, as it is important to both property owners and the energy industry.

Finally, the opinion points out that the Court received fourteen amici curiae in this case and many involved confusion over the language of the Court’s decision, which Justice Wainwright noted the Legislature could also address for further clarity. Many have called for the Legislature to address this issue of eminent domain and common carrier status in the next session this year. Those in the oil and gas industry will keep a close watch on how these Denbury decisions and any resulting legislation effect eminent domain law for other pipeline projects in the future. These cases may include a similar case involving the Keystone XL pipeline, which may also end up before the Texas Supreme Court.

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November 16, 2012

Texas Eagle Ford Shale Play is Best Oil and Gas Play in the US!

A new report by IHS Inc., a global information and analysis company, states that Eagle Ford in South Texas is a contender for the best tight oil play in the US. This is based on strong drilling results, a large prospective area and the magnitude of the resource potential.

At the moment the number one position is held by the Bakken formation, located in North Dakota, Montana, and Saskatchewan. Bakken has been number one because it opened up development of unconventional resources using high-tech drilling methods and hydraulic fracturing. Andrew Byrne, the director of equity research at IHS and the author of this study, said “The results from the Bakken were so strong that it set the standard by which all others will be measured. It was the one play that incited the industry into pursuing these opportunities.” But now that title is shifting to Eagle Ford.

The study looked at 27 tight oil plays and assessed the emerging and mature tight oil plays in North America which have the largest impact on investment patterns and North American oil and gas supplies. The study is intended to help clients estimate the resource potential and recoverable hydrocarbons of each play. It’s also meant to help clients understand performance metrics and future supply potential and establish metrics to compare the performance and value of each play. The study enables clients to determine play strategies, determine potential partners and merger and acquisition strategies, and also to develop analogs for global tight oil potential.

This examination found that both on typical well performance and peak performance, Eagle Ford’s best wells exceeded the wells drilled in Bakken. This performance has also impacted the competitive merger and acquisition environment, with Eagle Ford’s implied deal values averaging $14,000 per acre in 2011 and top prices reaching $25,000 per acre. And implied deal values have been increasing. Several billion dollar transactions for undeveloped acreage have been announced during the past 18 months.

Mr. Byrne said, “Our analysis at IHS indicates that Eagle Ford drilling results to date appear to be superior to those of the Bakken.” He went on to say that while Eagle Ford doesn’t have as many wells as Bakken at the moment, the peak of the well-distribution curve compares favorably to Bakken. To illustrate this, the most frequent Eagle Ford well result is 300-6,000 barrels per day for a peak month average, compared to 150-300 barrels per day at Bakken. Eagle Ford’s best wells also beat Bakken’s best and most productive wells.

In terms of within the Eagle Ford itself, Mr. Byrne said that the central area of the play has outperformed all others. This area includes the counties of Gonzalez, western Lavaca, DeWitt, Karnes, Bee, Live Oak, Atascosa, Dimmit, and eastern Mullen. The western area of Eagle Ford is next best, and the eastern area has the least activity and its performance is lagging behind the other two areas. Additionally, Eagle Ford is divided into three distinct windows: the oil window, the liquids-rich gas window, and the dry-gas window. The highest production rates are from the liquids-rich gas window.

This fantastic growth at Eagle Ford has already proven to be great news for the Texas economy. And now it is becoming the most dynamic energy industry area in the nation, which can only bring more good news to our state!

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November 9, 2012

US and Texas Oil and Gas Reserves Grow at Record Pace

A report of the US Energy Information Administration issued within the past few months indicates that horizontal drilling and hydraulic fracturing in shale have helped US and Texas oil and gas reserves grow at a record pace in 2010. This was the biggest single year increase since the organization began publishing oil and gas reserve estimates in 1977. These figures identify how much oil or natural gas can be produced with reasonable certainty, given current economics and existing technology.

The EIA Report stated that domestic crude and condensate proved reserves rose by 2.9 billion barrels, from 22.3 billion barrels in 2009 to 25.2 billion barrels in 2010, which is an increase of 12.8%. The wet natural gas proved reserves rose by 33.8 trillion cubic feet, from 283.9 trillion cubic feet in 2009 to 317.6 trillion cubic feet in 2010, an increase of 11.9%.

EIA Administrator Adam Sieminski told the US House Energy and Commerce Subcommittee last week that the increasing ratio of oil to gas prices in the US had led oil producers to focus on liquid-rich areas in 2010. The trend has continued for 18 months after that. In other words, higher oil and gas prices make drilling more profitable and increase production.

The trend this year continues into 2012. From January to May, EIA estimates crude and condensate production averaged 6.2 million barrels per day, which is the highest level since 1998. There have been significant increases in onshore oil production, particularly because of higher output in North Dakota and Texas. There have been increases in dry gas production since 2005, mainly due to shale gas production. Reduced production in some areas, like the Haynesville shale, were offset by increased production in the Eagle Ford Shale, the Marcellus Shale, and associated gas production.

In addition to this national information, Texas is also doing well. The Texas Petro Index showed a nine percent increase in crude oil production in Texas from January to June 2012 compared to the same time period in 2011. Before the recent energy boom, Texas oil had been in decline since the 1970s, making this transformation all the more impressive. Texas had the largest volumetric increase in the nation, largely due to development of Permian and Western Gulf basins. Texas also led in additions of natural gas proved reserves.

All of this comes at a time when our lawmakers in Washington are debating the pace of domestic oil production expansion. Republicans have strongly criticized the administration’s blocking of offshore drilling in the Atlantic and Pacific.

"These reserves increases underscore the potential of a growing role for domestically produced hydrocarbons in meeting both current and projected U.S. energy demands," Mr. Sieminski told the House committee. Erik Milito of the American Petroleum Institute also weighed in, saying "The report is further proof that we have more oil and natural gas than anyone thought possible even a few years ago. We are sitting on a lottery ticket that could spur millions of jobs, billions of dollars in revenue for the government, and more than 100 years of energy for our country."

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November 2, 2012

Updates on Crimson’s Success in East Texas Oil & Gas Operations

A Houston company, Crimson Exploration Inc., has provided an update on its successful operations in east Texas, including Woodbine, Eagle Ford and other programs. This is important information for the growth of the oil and gas industry in Texas, a crucial component to economic growth and energy independence.

Crimson has 18,500 acres in the Woodbine section that cover three areas the company refers to as Force, Iola-Grimes, and Chalktown. In these areas, the company has been developing the Woodbine, and production tests have confirmed the oil potential in all three areas. Crimson has identified 115 potential drilling locations. Assuming the average output is an ultimate recovery of 400,000 BOE (barrell of of oil equivalent) per location, with 90% oil and natural gas liquids, total net potential exceeds 34 million BOE. That is five times the average for Crimson in 2011.

161275_oil_drilling_rig_3.jpg In the Force area, in Madison County, 50 wells have completed since January 2009 using modern horizontal drilling and fracture simulation completion techniques. These wells have had initial rates of 600 b/d of oil. The first two producing Crimson wells initially averaged over 900 b/d of oil, and the area is considered substantially derisked. In Crimson’s first horizontal Woodbine well in this area, the well produced 128,000 barrels in its first four months.

Crimson has 5,100 net acres in the Chalktown area in Madison County as well. It is testing the Lewisville sand, a lower Woodbine objective that has produced vertical wells in the area. One of the wells there is producing extraneous water, possibly from a natural fracture. The company is working to shut off the source of the water to better test the oil potential.

In the Iola-Grimes, in Grimes County, the company has 7,650 net acres and is in active development testing a stratigraphically older Woodbine area than in Force.

In Eagle Ford, recent wells drilled in Brazos, Robertson, and Leon Counties could have potential of more than 600 b/d of oil. Crimson could also add as many as 230 locations and 68 million BOE to its output. Using horizontal and multi-stage frac completion technology, similar to that used at Woodbine, has the potential to increase Crimson’s output in Georgetown, Buda and Glen Rose as well. Georgetown and Buda could each add 58 locations and 17 million BOE. Georgetown wells had an initial rate of above 700 b/d of oil. Buda has initial rates of 600 b/d of oil.

Crimson also has two new primary locations that will likely be drilled in 2013 and might include nine to ten wells in the future. The locations are in Zavala County and Liberty County. In Liberty a former well was lost due to mechanical problems and last produced in January. In Zavala, Crimson delayed completion of wells to better understand optimal completion techniques being developed by other operators in the area.

To those of us both in and out of the oil and gas field, the bottom line is increased production and exploration and that the industry is healthy and growing in Texas. If left alone and allowed to develop naturally, there is no reason the industry will not keep growing and adding to the Texas and American economies for the foreseeable future.

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October 26, 2012

The Beat Goes On: Another Report Questions EPA Fracing Tests

Another study, entitled "Review of EPA Hydraulic Fracturing Study Plan", is questioning the validity of the Environmental Protection Agency’s (EPA) data on hydraulic fracturing ("fracing") and drinking water. The impact of fracing on drinking water has been a hot political topic for a while now, and more and more scientific studies are showing that the EPA’s data is either overblown or just plain wrong.

The Battelle Memorial Institute, a non-profit science and technology research and development organization, released a study recently concluding that the EPA did not define important quality requirements in its study process. The EPA used its discretionary authority to broaden its study significantly beyond what Congress requested in fiscal year 2010, which was originally only to include fracing and drinking water. Instead the EPA reached beyond, encompassing numerous peripheral elements related to oil and gas exploration and production activity, including various upstream and downstream stages of the water life cycle, site preparation and development, and standard oil and gas production and other industrial activities. The Battelle study stated that a broader study increases complexity and risk. Battelle warned that ambitious schedules, driven by various 2012 reporting goals, could make data collection and analysis less robust and thus scientific conclusions less sound. It also noted that site data collected during 2006 to 2010 could become obsolete by the time the EPA issues its final report in 2014.

The Battelle study was commissioned by the American Petroleum Institute (API) and America’s Natural Gas Alliance (ANGA) due to concerns about the direction of the EPA study. Stephanie Meadows, API upstream policy senior advisor, said, “Battelle’s analysis of the plan for EPA’s study reinforces many of our previously stated concerns about the study and raises new ones. It finds deficiencies in the rigor, funding, focus and stakeholder inclusiveness of the plan.” She told reporters that API and ANGA intend for Battelle’s report to help EPA produce “the most scientifically sound study possible” and hopes that this study can encourage the EPA to make sure their final report is done right.

The Battelle study noted that the EPA did not designate its report as a “highly influential scientific assessment,” which would have required more rigorous standards and peer review. The Battelle study also pointed out that it appears no systematic planning was used in the EPA study, which would have allowed the study to be more “appropriately directed and academically robust.” Battelle recommended more collaboration between the EPA and organizations, like API and ANGA, which have extensive knowledge of geology and water. "Given the industry's extensive experience with production of oil and gas from unconventional reservoirs, its unique expertise in the process of hydraulic fracturing and associated technologies, and its wealth of relevant data and information available to inform this effort, it is a weakness of the study plan, and likely its implementation, that significant industry collaboration is missing," said the report. ANGA’s vice president told reporters that the organization continues to reach out to the EPA in an attempt to develop a collaborative relationship.

I have concluded that what we have here is a half-hearted and fairly unscientific attempt by the EPA to push its agenda. I have no quarrel with the EPA if they are going to conduct a real study, using recognized scientific protocols and methodology. But why are our tax dollars being used for what appears to be another psuedo-scientific study by federal bureaucrats!

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October 19, 2012

Why You Should Have a Texas Pipeline Attorney Review That Pipeline Easement

The pace of oil and gas pipeline construction in Texas has increased enormously. As a Texas pipeline attorney, I regularly get calls from folks who ask me why they should go to the expense of having an attorney review their pipeline easement before they sign it. Here are the reasons why I believe that consulting an attorney is important:

1. The law in Texas regarding compensation for pipelines has been evolving. There is now greater recognition of what are called "remainder damages", that is, compensation for the effect that installation of the pipeline and any surface equipment has on the market value of the rest of your property. Only by having a Texas pipeline attorney review the application of the current law to your specific situation will you know if you are entitled to these additional damages.

2. It is important to know whether the pipeline for the easement you're being offered is a "common carrier" or not. A common carrier pipeline is a pipeline that carries oil or gas for third parties for hire. The law now requires that the pipeline company proves that they are a common carrier. If they are a common carrier, and can prove it, they will have the power of eminent domain (also called condemnation) if you cannot agree on easement terms with them. If they are not a common carrier, they cannot use condemnation and your bargaining position with them is much different.

3. A land man or other representative of the pipeline company may tell you that the easement you are being offered is "just a standard form". Watch my lips on this one: there is no such thing as a standard easement form. The land man may have meant that the easement they offered was standard for that particular land man, or for the particular pipeline company the land man was representing. However, there is simply no such thing these days as a standard, industry-wide form.

4. Some folks will look at the easement and think that it doesn't look that complicated, so why use an attorney? If you are not an oil and gas or pipeline lawyer, do you really know what the terms in that easement mean? Do you know when words in the easement have one meaning in ordinary use and another meaning in the oil and gas industry? Even more important: do you know what's missing? Do you know what the legal implications of the language in the easement are?

5. Some people think that if they are getting the compensation they want, then the fine print in the easement does it really mean much. The truth is that what is in the body of the easement, in the "fine print", can have a greater impact on your pocketbook in the long run than the amount of the compensation. In some cases, depending on the easement, the financial gains to you by eliminating future problems with a few changes in the easement can result in much savings to you than what you receive in initial compensation!

6. An easement can go on for many years, and perhaps forever. What remedy do you have if the pipeline company stops using the pipeline, but you still have to abide by the terms of the easement? Some people think that if they simply include language in the easement that says they can terminate the easement if it's not used, then this will be taken care. In many cases, it does not.

325126_submerged_pipeline_sign.jpg 5. Sometimes people are taken in by the friendly and cordial attitude of the land man or pipeline representative and think that he or she is on their side. Yes, good land men are nice. It is their job to be nice. If they weren't nice, they would have been fired a long time ago. Whether the land man is nice or not, the land man's professional and legal allegiance is to the pipeline company the land man represents, and not to you.

7. There are those landowners think that it's just too expensive to have an experienced lawyer review the easement for them. However, there are many oil and gas attorneys in Texas whose fees are not only reasonable, but whose rates are a fraction of the amount of damage that can be done to your land because of an improper agreement. In addition, the attorneys fees are sometimes offset by the increased compensation as the result of an easement negotiated by an attorney. This easement may last your lifetime, or longer. Doesn't it make sense to be sure you can live with it? Your land may be a big investment. Isn't it worth taking care of?

8. In some cases, the land man may make verbal representations or assurances that a land owner relies on in signing the easement. Unfortunately most (there are a few exceptions) verbal promises by the pipeline company or its land man are not enforceable under Texas law.

9. There are times when the land man may pressure you to sign the easement right away. They may say this is "high priority" and if you don't sign quickly, the offer will be withdrawn. However, it usually takes quite a while to plan, survey, and obtain easements for each section of pipeline. There is almost never a situation where it is truly a case of "sign right now or no deal".

10. There are times when a land owner's property is quite small and so the land owner assumes that the pipeline company won't make any changes in its easement anyway. However, sometimes even small interests count. Secondly, many times owners of small interests, such as family members, go together and retain me to negotiate their easement, and together, they have more leverage than they did acting individually. In my office, the cost to review, evaluate and negotiate an easement is the same whether it's for one family member of twenty. Finally, most pipeline companies are reasonable, and are open to making reasonable changes even when your interest is small. The key is to have someone who is experienced and who knows what changes are appropriate to ask for given the size of your interest. Even small changes can make a big difference in the overall fairness of an easement.

11. I occasionally have been asked to try to work out easement problems caused by the land owner's failure to read easement before they signed it. The land owner tells me that they thought they could negotiate the easement themselves, and save the money that an attorney would've cost. Unless you have experience in negotiating an easement, you are almost always not going to get the best deal for yourself. Land men can spot an inexperienced person a mile away, and they are not going to cut you any slack! Remember, their loyalty is to the pipeline company, and not to you.

12. It is important to know exactly what the pipeline company will be building. Are they going to install only an underground pipeline? Or are they intending to install surface uses, such as a cleaning station or a compressor? Where exactly are the pipeline, any surface equipment, and the temporary work area going to be located? Will it be necessary to destroy any large, old trees? A landowner should be compensated appropriately for surface equipment, temporary work area, and large important trees, over and above compensation for the pipeline itself. An experienced attorney can assist you with a determination of what additional damages are appropriate to request.

13. Some types of compensation for damages from a pipeline company are taxable and some are not. Often, it is appropriate to request that the pipeline company give you two checks, one for the taxable damages and one for the nontaxable damages, so that you can prove this to the IRS if necessary. An experienced attorney can help you separate the taxable from the nontaxable compensation and ensure that the payment procedures bear this out.

If you get an offer from pipeline company or its land man, simply smile and say: "Thank you. I will seriously consider this. I will send it to my attorney promptly and we will be in touch with you soon". And then call your attorney!!

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October 12, 2012

Legislation to Assist Oil and Gas Development Faces Dim Future

Before the election, the House of Representatives passed sweeping energy legislation, including HR 4480, in an attempt to facilitate the development of the oil and gas industry. The bill passed by 248 to 163 and its sponsor, Representative Cory Gardner of Colorado, urged the Senate to take up this bill promptly, for the good of the American economy.

Included in the package of seven bills the House passed, all directed at oil and gas development in the Western US and on federal lands, there are provisions requiring the Secretary of Energy to have a plan for leasing federal land, directing the Secretary of the Interior to offer previously unavailable land as at least 25% of the annually nominated total, and requiring analysis of impacts of certain Environmental Protection Agency (EPA) rules on gas, diesel, and natural gas prices. Other included bills would require the Secretaries of the Interior and Agriculture to have a new federal onshore energy production strategy every four years to guide leasing plans, the Secretary of the Interior to hold at least one lease or sale per year in the National Petroleum Reserve-Alaska, and allow the Secretary of the Interior to hold oil and gas lease sales online.

Republican members of the House pointed out that while gas prices may be going down a bit, they are still double what they were in January 2009. The bills are intended to alleviate the devastating impact of government regulations on job creation and gas prices for the American consumer. Democrats and some radical environmentalist allies, of course, see it differently and have been complaining about the bill’s theoretical and speculative environmental impact. The Democrats also tried to attach amendments to the various bills to preserve major regulatory provisions, fully fund the Commodities Futures Trading Commission, and require federal oil and gas lessees to more diligently develop their holdings. These amendments were voted down.

Those who actually work in the industry and see the benefits this brings in terms of the economy and job creation were happy at the passing of this sweeping energy legislation at long last. American Petroleum Institute Executive Vice President Marty Durbin said, “Greater access to domestic energy resources, combined with smarter policies that boost our refining industry, will benefit consumers in the long run. More homegrown energy is good for all Americans.” Independent Petroleum Association of America President Barry Russell also pointed to the legislation scaling back roadblocks for procedures and as helping US economic expansion through more jobs and energy security. In particular, he said, the legislation is a necessary check on the EPA’s decisions with a new inter-agency committee assessing the effect of proposed rules and regulations on the economy. The President of the American Fuel and Petrochemical Manufacturers also stated that these measures would allow the US to remain competitive in the global marketplace.

Of course, the prospects of this bill post-election are pretty dim. The Democrats have other agendas besides jobs and lower gas prices for Americans.

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October 5, 2012

More Scare Tactics: EPA Way Off on Fracing Methane Emissions Estimates

There is now even more evidence that the Environmental Protection Agency (EPA) is using politics, and not science, in opposing hydraulic fracturing and the oil and gas industry. A recent survey and report entitled "Characterizing Pivotal Sources of Methane Emissions from Unconventional Natural Gas Production", done by the American Petroleum Institute and America’s Natural Gas Alliance (ANGA) reached a few interesting conclusions, especially for those of us skeptical of the EPA’s stance on hydraulic fracturing. The survey found that the methane emissions levels from fracing in the US were 50% lower than the EPA estimated in its 2011 emissions inventory. Between 2010 and 2011, this new study found the natural gas industry emitted 4.4 million tons of methane gas, compared to the EPA’s estimate of 8.7 million tons. This is an important distinction because methane can be a potent pollutant.

There is little to dispute in this extensive and thorough new survey and report, which studied 91,000 wells operated by more than 20 companies over a vast geographical area. It represents nearly one-fifth of all US oil wells (18.8 % to be precise). The survey examined ten times more dates than those used in the EPA’s study on methane emissions. This survey and report show even more drastic differences in numbers in specific areas. For example, venting of methane into the air during liquid unloading was 86% less and emissions from well workovers were 72% less than indicated in the EPA report.

Howard Feldman, API’s regulatory and scientific affairs director, mentioned earlier this month that, “The industry is voluntarily reducing its environmental footprint and not waiting for regulatory mandates or incentives to continue to make progress. The technology and equipment used to reduce emissions were created by the industry, and companies are already implementing those technologies in locations where it is most effective. By January of 2015, all wells are required to include reduced emissions completions, which will further ensure emission reductions.” Mr. Feldmen said there are no plans to challenge the EPA's emission standards in court, and added he hopes the agency will look at the industry report's findings and reassess its regulations.

The survey further stated that as the oil and gas industry and federal government continue to address methane emissions from fossil fuel production, there are three main points to consider: 1) in addition to voluntary measures by producers, more data will become available in the future; 2) the oil and gas industry has committed to improving itself; and 3) the producers who participated in the API and ANGA survey are committed to providing information about the new and evolving area of unconventional oil and gas operations.

Mr. Feldman concluded by saying: “We think the emphasis on gas is good for the country, and we believe anyone who feels otherwise is out of touch with what’s going on.” As someone who has worked as an attorney in this field for many years, I could not agree more.

When I see instances like this, in which the EPA's figures diverge substantially from reality, I have to suspect that the EPA has once again cast objectivity aside and is pursuing its own private agendas instead.

See Our Related Blog Posts:

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Texas' Proposed Rule 3.29 for Hydraulic Fracturing Chemicals Disclosure

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September 28, 2012

Eagle Ford in Texas Has Record Year for Oil and Gas Production

In great news for the Texas oil and gas industry, as well as the Texas economy, drilling at the Eagle Ford Shale, a band of rock in south Texas containing a mixture of light, sweet crude oil, natural gas, and high quality condensates, may outpace last year’s boom. UK based research company GlobalData, issued a report earlier this year indicating that production will increase in 2012.

The report confirms there has been explosive growth in oil and gas activity in this area of south Texas. This was already apparent last year, when production of crude oil, natural gas and natural gas liquids tripled compared to 2010. Combined liquids production is estimated to have increased by an even greater factor, from 10.8 million barrels of oil equivalent in 2010 to 57.5 million barrels of oil equivalent in 2011, an increase of 432%.

This data confirms other reports and evidence that drilling has shifted away from natural gas and towards the more lucrative crude oil and condensates, largely as a result in the drastic decrease in North American gas prices. Regardless of this shift in focus, natural gas continues to play a significant role in Eagle Ford drilling. The GlobalData report states that combined liquids and gas production was at 105 million barrels of oil equivalent in 2011. Only five years earlier the output was 200,000 million barrels of oil equivalent. By the end of the current year, the company expects the production to have doubled from last year, to 207.3 million barrels of oil equivalent.

This production boom in the Eagle Ford has resulted in companies such as Anadarko Petroleum Corporation, Petrohawk Energy Corporation, EOG Resources Inc, Burlington Resources Inc, and Rosetta Resources Inc producing high volumes of natural gas and high-quality liquids.

The rate of drilling permits has also increased significantly in this area of Texas. If the current rate of permit issuance by the Railroad Commission of Texas continues, last year’s 4,286 drilling permits could be exceeded. 1,620 permits were issued in the first four months of 2012 alone and if that rate continues more than 4,800 permits could be issued this year. As an example of the rate of expansion, Chesapeake Energy Corporation alone received a record number of 724 drilling permits in Eagle Ford during 2011. That company plans capital expenditures of up to $2.4 billion. If this continues, there could be major companies fighting each other to get a piece of Eagle Ford’s wealth.

"GlobalData anticipates that the Eagle Ford shale play will continue to see increased drilling activity during the coming years," the company says, which is good news for Texans.

The University of Texas, San Antonio, also released a study on Eagle Ford activity and the impact on south Texas. This study estimated that the oil boom has led to about $25 billion in economic output in the 20 counties affected. Researchers estimated that crude oil production increased six fold from 2010 to 2011. With these recent studies, all Texans should be optimistic about the future of our oil and gas industry and the positive effects it will have on our economy as a whole.

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September 21, 2012

Texas Land and Mineral Owners May Benefit from Waterless Fracing

As many Texas oil and gas lease owners know, fracing creates new channels in rock that can increase extraction rates for the recovery of fossil fuels. However, some claim that the process contaminates groundwater or risks air quality. The traditional process works by pumping fracturing fluid into the well-bore at a sufficient rate to increase down-hole pressure. But a new technology is on the horizon to achieve the same results without using water. This new process is only a few years old and was largely invented by Robert Lestz, the chief technology officer at GasFrac Energy Services Inc.

The Process & Benefits

Waterless fracing works with almost the same process as traditional methods, but it replaces the traditional mixture of water, sand, and chemicals with a thick gel made from propane. The company claims this petroleum gel is as natural to a well as soil is to the earth. This gel is called “liquefied propane gas,” or LPG for short. LPG has the added advantage of reverting to vapor while still underground, and it therefore returns to the surface in a recoverable form. Also, unlike water-based methods, LPG does not carry chemicals used in drilling back to the surface. In that way it requires less post-job cleanup and almost no flaring. Another benefit of this new technology is that it is more efficient, because the fracturing fluid can be recovered and re-used or re-sold, saving the oil and gas producer substantial expenses.

Future Use

Thus far, LPG has mainly been used in western Canada, where GasFrac is based. Their goal is for the process to spread to new locations quickly. In fact, it has the potential to get around politically-motivated hydraulic fracturing bans, such as the one in place in New York. GasFrac is in talks to use LPG fracing on 135,000 acres in Tioga County, New York. The company is also interested in expanding into Western Europe, in countries such as the UK, Switzerland, and France, which also have a hydraulic fracturing ban in place.

GasFrac is expanding operations to include Texas and will develop a 20 acre operational center near San Antonio to provide waterless fracing to oil and gas companies working in the Eagle Ford Shale. They have a two year contract with BlackBrush Oil and Gas LP to provide the technology to 900 drilling sites.

1401193_artificial_pond.jpg The economy in the area is already benefiting from this growth, and GasFrac intends to hire at least 100 local workers. Phil Mezey, BlackBrush’s CEO, stated that LPG fracing has already brought "oil production at a sustainable rate weeks earlier than with the standard water frac and we are seeing huge savings on disposal of frac fluids."

This is also great news for Texas because of the Eagle Ford area’s continued drought problems. Hydraulic fracturing requires significant amounts of water, which can compound the water shortage. With so many pressures on the area’s aquifers, some were speculating that a choice would have to be made between fracing and farming. LPG fracing is a potential solution to this problem by eliminating the need for any local water resources.

This could be a game changing new technology as GasFrac continues to expand in North America and internationally. Even some in the environmental community welcome this as a positive step. One representative from the Environmental Defense Fund admitted that this was a positive sign that the industry can reduce alleged environmental impacts.

See our previous posts on related subjects:

Texas Fracing Study Interim Results: Hydraulic Fracturing Does Not Pollute Groundwater

Texas' Proposed Rule 3.29 for Hydraulic Fracturing Chemicals Disclosure

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September 7, 2012

Texas Railroad Commission Review of Flaring Rules for Texas Gas Wells

With all the news about the false controversy involving hydraulic fracturing, the Railroad Commission of Texas is pre-emptively addressing concerns about another important issue for the Texas oil and gas industry--natural gas flares. Commissioner David Porter announced that the Eagle Ford Task Force will study the issue of whether Texas’s regulations on flaring and ventilation need to be updated.

Gas flares are generally associated with a booming industry where the production is outstripping the infrastructure capacity, especially in terms of pipelines. In high producing areas, like the Eagle Ford Shale, drilling and first production is reached weeks before pipeline companies get natural gas infrastructure such as pipelines into the area. Oil can be moved by truck, but natural gas needs pipelines. In general, the use of gas flares as a safety valve is not used in an abusive fashion, because it is in the oil and gas companies’ interest not to waste gas. But Mr. Porter still wants to ensure that everyone is complying with the current regulations on flaring and venting.

This issue of gas flares is tied to the debate on hydraulic fracturing, as the Eagle Ford Task Force was also commissioned to look into issues of how hydraulic fracturing affects groundwater. The Task Force is branching into this new area, with its main concern being the effect of gas flares on air quality. At Eagle Ford, there is concern that the San Antonio metro might exceed federal limits on ozone emission standards. The Texas Railroad Commission intends to work with other state agencies to streamline the air pollution rules in Texas and also to make monitoring and reporting on air emissions easier.

Commissioner Porter reported that state regulators and executives are working together to find environmentally sound solutions for gas flares. There are plans to increase the use of natural gas generators at these locations, which can power electric machinery and reduce flaring at the same time. The Commissioner points out that any updates to the regulations will reflect the increasing amount of production of gas from unconventional resources in shale. Mr. Porter also says that the industry should focus on new gas flare technology that promotes energy saving and also protects the environment.

The Commissioner specifically does not want a media campaign of misinformation to treat this issue like the fracing issue—where everyone thinks they know what they are talking about, but do not. Unfortunately, with fracing, the media provides a lot of incorrect information to the public. Fracing has become such a political minefield that politics has often overshadowed, and overruled, scientific evidence in the court of public opinion.

Mr. Porter noted, “We must proactively address flaring with fair, predictable, commonsense regulations based on science and fact. If we don’t, we can expect the anti-fossil fuel folks, including the EPA, to once again attempt to curtail oil and gas production in our state by using politically motivated rulemaking to implement their political agenda.”

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August 24, 2012

Obama’s Task Force Agrees: Shale Drilling is Safe

In April 2012, President Obama signed an executive order creating a six person committee to coordinate efforts among three government agencies to research the risks and benefits of unconventional oil and gas production. The committee is composed of two members each from the Department of Energy, the Environmental Protection Agency, and the US Geological Survey, which is part of the Department of the Interior. It was set up to use each agency’s particular competencies to address concerns about unconventional technologies and shale development and to make sure the industry properly mitigates any risks involved. The first meeting of the group was in May 2012. The overall goal of the committee is to develop a research plan for prudent development of U.S. oil and gas reserves.

The Energy Department representative who is up heading the committee, Christopher Smith, the Deputy Assistant Secretary for Oil and Natural Gas, in May 2012 told a breakfast meeting hosted by the Chamber of Commerce in Fort Worth, Texas, that he believes shale drilling can be done safely. He later toured the manufacturing facility of FTS International, formerly called Frac Tech, which makes equipment for hydraulic fracturing—the “controversial” technology involved in getting oil and gas from shale. Mr. Smith is a Fort Worth native who graduated from Southwest High School in 1986 and is also a graduate of both West Point and Cambridge University.

This was Mr. Smith’s second visit to the Fort Worth area in his official capacity since his appointment at the Department of Energy in 2009. Two years ago he was in Fort Worth with a Chinese delegation in the US to learn more about hydraulic fracturing. At the time, Mr. Smith told the Chinese that the Barnett Shale is ground zero for learning about shale oil and gas development, because “they can see the benefits, but also the ways the City has worked with some of the environmental concerns.”

These environmental concerns would include air pollution and also any potential groundwater contamination. He also called shale production of relatively inexpensive natural gas an “opportunity” for both consumers and businesses. He discussed harnessing the scientific capacity of 10,000 scientists and engineers available to the Department of Energy to learn how to prudently and safely develop these crucial fossil fuel resources and how this shows the government is taking concerns about this kind of technology seriously. He said that incidents and complaints must be examined, but that shale oil and gas is a resource that can be developed safely.

So, even the President's own committee understands the real science about hydraulic fracturing and shale extraction technology. The evidence demonstrates that it is safe for the environment and safe for the communities nearby. Hopefully we will soon see the end of the day when the fracing “bogeyman” is used as a cynical political tool for personal political gain.

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August 18, 2012

New Study: A Roadmap for Energy Independence for Texas and the United States

Abundant oil and gas in Texas and the rest of the U.S. has already proven to have significant economic benefits, and not just to mineral owners in Texas and the U.S. It will continue to benefit the country as technology in this sector continues to improve. Our energy independence has the capacity to improve for the next decade or more. Increased domestic fuel production rose by 1.4 million barrels per day between 2008 and 2011, while net imports of fuel declined by 2.7 million barrels per day. More production will create jobs and help reduce the trade deficit.

However, a newly released study, “The New American Oil Boom: Implications for Energy Security,” by the Securing America’s Future Energy’s Energy Security Leadership Council (ESLC), a group comprised of top military brass and CEOs of major companies, suggests that while increased domestic oil production is important, alone it is not a long term solution for America. The report was released at the Bush Institute at Southern Methodist University in Dallas, Texas recently.

“Energy independence" for the United States is an admirable goal, but even if the U.S. were to produce enough oil to meet our demand, the domestic price is still set on the global market, meaning a potential supply disruption anywhere can impact the price of oil everywhere,” said Herb Kelleher, co-founder and chairman emeritus of Southwest Airlines and a member of the ESLC. The U.S. remains tied to unpredictable Middle East politics because of oil needs.

The study asserts that increased U.S. oil and gas production cannot shield American consumers from these volatile international oil markets that determine prices. Even countries that are net exporters of oil, such as Norway and Canada, remain subject to high and volatile oil prices. Geopolitics play a role too, and the report noted that sometimes countries that are neither large oil consumers nor oil producers can have a huge impact on the oil market, citing in particular countries with important shipping channels or infrastructure.
The fact that Iran’s government can try to put a choke-hold on our oil supply by impeding passage through the Straight of Hormuz is a serious worry. Changes in supply or demand anywhere in the world can have a huge impact on the U.S. through oil and gas prices. The study notes that the impact on the U.S. is more a function of how much oil and gas is consumed, not how much is imported. As American consumers are forced to spend more at the gas pump, that money comes at the expense of spending that consumers would have done elsewhere, affecting the economy as a whole.

The ESLC study included recommendations for the future, such as increasing vehicle fuel efficiency requirements, accelerating development of transportation fuel alternatives to fossil fuels, and also stronger support for more U.S. oil production, which remains a crucial cornerstone of our economy and an excellent opportunity to create job growth. The report also recommends switching heavy duty trucks to natural gas and increasing the efficiency and availability of electric vehicles for light duty use.

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August 3, 2012

New Study Gives Texas Mineral Owners More Information on Fracing

The film Gasland purported to show how communities are adversely affected by hydraulic fracturing (also known as "fracing"). This film was full of inaccuracies and half-truths, and was apparently intended to incite opposition to fracing by masquerading as a "scientific" documentary. Environmentalists and politicians with a specific anti-energy agenda use films like this one to promote their own cynical goals. This campaign against a decades-old drilling practice continues despite numerous scientific studies and solid evidence disproving fracing’s naysayers.

1395215_low_tide_texture.jpg We can now add another study to that growing list. A effort by scientists and researchers at Durham University, Cardiff University (both in the UK) and the University of Tromsø (in Norway) has found that fracing at least 2,000 feet below an aquifer minimizes chances of water contamination in the United States. Their study was published at the end of April, 2012 in the journal Marine and Petroleum Geology. Of particular interest to Texans, it examined the Barnett and Eagle Ford Shales in Texas, as well as the Marcellus Shale in Pennsylvania, the Niobrara Shale in Colorado, and the Woodford Shale in Oklahoma.

One of the authors of the study, Richard Davies, said: “[T]he Earth has a number of safety mechanisms which stop natural hydraulic fractures from going on forever.” The study explains how hydraulic fractures can happen naturally, as rocks embedded with water deep underground get pressurized over millions of years. The liquid can cause the rock to crack, and the crack will continue until it hits another type of rock, and then it stops. What happens with man-induced hydraulic fracturing is very similar, as pressurized water is pumped into the rock to crack the shale and release the trapped natural gas. People worry that these cracks will go so far vertically as to connect the wells to the aquifers.

The study authors looked at thousands of natural and man-induced fractures all over the world. In particular, the authors looked at data from five natural gas shale reservoirs around the United States (those listed above). They found that the longest vertical crack was 2,000 feet long. That sounds like quite a long distance, but in reality these natural gas wells are usually fraced below 7,000 feet and the water aquifers generally exist above 1,000 feet. The study also points out that the chance of a crack being longer than 1,500 feet is less than one percent. The longest such crack anywhere in the world is 3,600 feet in Namibia. That crack apparently took billions of gallons of water and millions of years to reach that length. Even that fracture is not close enough to affect the aquifers at stake here—they are at least 6,000 feet away from the fractured area.

This is one of a handful of studies to take a scientific approach and could be a starting point for a scientific-based discussion on a minimum distance between fracing and aquifers. The research team and authors hope more data continues to become available and the study of these fractures can continue, but this is certainly a good starting point for a rational analysis. As a Texas oil and gas attorney, I strongly support these scientific advances and welcome new research on the topic. More science and less unfounded hysteria is definitely called for.

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July 20, 2012

New Life for Oil and Gas Wells in Tyler County and Duval County, Texas

Bayside Petroleum Company, based in Dallas, Texas, has been busy increasing its oil and gas production by renewing or acquiring leases in two mature oil and gas fields in Texas.

Bayside recently renewed its leases in the Muscadine Field in Tyler County, Texas in preparation for rejuvenating this field, first discovered in the 1950s. This field has three wells on 230 acres of land and has produced 400,000 barrels of oil and 350 million cubic feet of natural gas. Bayside plans to drill a new well, to a depth of 8,175-8,500 feet. This well will replace the older well, called the No. 2 well, which will be reserved for future use as a saltwater disposal well. The other two wells, Nos. 3 and 4, are on lands surfaces controlled by the National Park Service (the NPS). The company will file a Plan of Operation with the NPS and, upon approval, Bayside will commence reworking wells 3 and 4. The company will also evaluate the Muscadine Field for future additional drilling. Bayside specializes in reworking and recompleting “marginal” oil and gas wells.

Gordon Johnson, CEO of Bayside, stated, “This is an excellent opportunity for Bayside to bring increased production from this field to the market." Bayside owns 100 percent working interest in the Muscadine Field and a 70 percent net revenue interest for this lease.

This past week, Bayside also acquired an oil and gas lease covering the Moody and West wells in Duval County, Texas. Acting through a subsidiary, Bayside acquired 181 acres and seven existing wells on the property. The previous owner of these wells passed away and the wells have been unused since. Bayside plans to rework or recomplete all of these wells and possibly drill new wells. The wells have previously produced oil from the Jackson Series sand, at depths between 2,200 and 2,400 feet.

This new lease is adjacent to other Bayside properties in Duval County, according to Mr. Johnson, and fits in nicely with the company’s specialized program in reworking older wells. He said that work on these wells will start this summer.

The recent activity by companies like Bayside show once again how important the oil and gas industry is to Texas’s healthy and growing economy. Like Apache Corp breathing life into an older Texas oil field (see this post here), this news from Bayside shows how old Texas oil wells can continue to be productive. With the energy market booming and technology improving, there are even more options available to increase the production in older, mature, and even declining, wells. Along with Bayside and Apache, Exxon and Chevron have also paid attention to more mature oil wells. It goes without saying that reworking the older wells is good stewardship of our resources, but it is also is good for these local economies—creating more stable, well-paying American jobs.

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July 7, 2012

An Increase in Texas and U.S. Oil Production Will Lower Gas Prices

It seems like a noncontroversial statement to say that increasing the supply of a product will lower its price. But because of politics, that statement still elicits arguments and recriminations in Washington when the discussion is about oil or gas production. At a March 20, 2012 press conference, American Petroleum Institute President and CEO Jack Gerard stated the obvious, that increased oil and gas production domestically will relieve the price at the pump, and said that President Obama needs a “reality check” about the mixed signals his administration is giving to the market. The President’s comments about releasing oil from the Strategic Petroleum Reserve, and encouraging other countries, like Saudi Arabia, to step up production, proves that even the Obama administration understands that supply is a big factor in the high gas prices Americans are facing at the pump in the midst of the summer driving season. At the same time, the Obama administration is talking about raising taxes on gasoline, which sends the opposite message to the market and increases prices.

Mr. Gerard stressed in his press conference that voters understand that tax increases are not the solution to the high price of gas, and voters are overwhelmingly supportive of the oil and gas industry in America. He discussed the findings of an API Harris International poll that questioned 1,009 registered voters in early March. According to Mr. Gerard, 81 percent of those polled believed that more US oil and natural gas development would reduce gas prices. Another 84 percent thought it would help US energy security, and 90 percent of those polled think that more oil and gas development will lead to more American jobs.

1198014_motorway.jpgMr. Gerard explained his prescription: “A true all-of-the-above energy strategy would include greater access to areas that are currently off limits, a regulatory and permitting process that supported reasonable timelines for development, and immediate approval of the Keystone XL pipeline to bring more Canadian oil to US refineries. This would send a positive signal to the market and could help put downward pressure on prices.” As evidence of the impact of market signals and increased supply, he points to gas prices over $4 a gallon during President George W. Bush’s administration, and how lifting the moratorium on Gulf of Mexico drilling resulted in a dramatic drop in the price of oil, and therefore the price of gas, within days. He further asserted that the US has ample domestic energy reserves and can safely produce more oil and gas as the country needs it.

This issue is becoming more critical to Americans by the day. Business Week reported that the national average price for a gallon of gas is $3.97, which is an increase of almost 4 cents in just two weeks. These prices affect every American, and none of us can afford to be shelling out so much money unnecessarily.

For further reading on this subject, I urge you to look at the American Petroleum Institute’s new website, explaining to non-industry consumers the details about gas prices.

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June 29, 2012

Texas Oil & Gas Fuels a Robust Economic Recovery

Until recently, most of us in Texas and throughout the country (unless you had an oil and gas lease) struggled with high gasoline prices. However, a new study entitled, “Are the Energy States Still Energy States?” by Mark Snead, an economist and Vice President of the Federal Reserve Bank of Kansas City, provides more context to the overall interaction between the energy industry and the economy. The study suggests that thirteen energy producing states, (we'll call this group the "Energy States"), have strong enough energy industries that higher oil and gas prices actually help, rather than hurt, their economies. Mr. Snead’s list of the thirteen Energy States are Alaska, Louisiana, Mississippi, Oklahoma, Texas, Colorado, Montana, New Mexico, Utah, Wyoming, Kansas, North Dakota and West Virginia.
1266445_vintage_gas_pump.jpg Texas itself is the largest single producer of both oil and gas in the country, and by itself produced 21% of crude oil and one-third of natural gas output in the U.S. in 2008. The same year, the Texas energy industry generated nearly $65 billion in oil and gas earnings, more than half of the national earnings from oil and gas.

Mr. Snead’s study shows that during the recent recession, the Energy States did better than other states that lacked a robust energy sector. Individually, all the Energy States economically outperformed both the nation as a whole and non-energy states as a group. The Energy States experienced faster job growth prior to the recession, entered the recession much later, and have posted better job growth overall since the recession. Between December 2007 and September 2009, non-energy states saw a contraction of employment by 5.7%, compared to 2.8% in Energy States. Since the start of the recession, Energy States were four of the top five states, and seven of the top ten states, in job growth. Energy States North Dakota and Alaska were the top two states in terms of job growth and had the only net job increases throughout the recession! Contrary to general expectations, the economies of the Energy States actually start to decline when gas prices go down. Lower oil and gas prices have the inverse effect on the Energy States compared with non-energy states, where high gas prices can take a severe toll on economic productivity.

Mr. Snead stated that on their own, the increased employment and income produced in the Energy States is not enough to offset the economic effect of high gas prices, but that if the country as a whole increased energy conservation and production efforts, it could make a significant difference. He pointed to two obvious benefits to Americans—more jobs and more money focused on domestic resources instead of foreign oil and gas.

Increased domestic production does not always produce an immediate reduction in gas prices. In general, more supply does decrease price, but Mr. Snead points out that when the US exports its oil, prices are subject to global market factors. Still, some states like Kansas and Oklahoma see studies like this as encouragement to proceed with development of their energy resources, such as the Mississippian Lime formation, which might hold vast oil reserves.

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June 22, 2012

A Win for Texas Mineral Owners and the Texas Railroad Commission

Finally a piece of good news and an intelligent decision has come from the Environmental Protection Agency (EPA)! It has taken them more than a year, but in the end even the EPA had to accept scientific fact. Recently, the EPA vacated an emergency order from December 2010 prohibiting Fort Worth-based Range Resources from pumping natural gas from two wells in Parker County, Texas.

In the EPA’s original 2010 order, it accused Range (without any evidence, mind you) of contaminating drinking water in Parker County with methane gas, allegedly caused by hydraulic fracturing in the Barnett Shale. The Texas Railroad Commission, the oldest regulatory body in the State of Texas, invited the EPA and the owners of the affected wells to a January 2011 hearing on the issue. Neither the EPA nor the supposedly affected well owners showed up. (No doubt they did not want to be confused by the facts or by real science). The hearing proceeded as scheduled, however, with scientific experts in the oil and gas field testifying. These experts can determine the geochemical gas fingerprint of a substance like methane that identifies where the gas originates.

The scientific evidence conclusively showed that the methane found in the drinking water was from a shallower Strawn gas field and not from fracing in the Barnett Shale by Range Resources. The sample did not match the fingerprint of Barnett Shale gas, which is more than 5,000 feet below the surface. Range Resources staff also testified that their gas wells were mechanically sound and that there were no leaks. After considering the evidence, the Railroad Commission found that Range Resources’ drilling had not caused the contamination in the water wells. Despite this decision and the solid scientific evidence behind it, the EPA stood by its 751 page Emergency Order and continued with its case against Range. The conflict ended up in federal court. It took another 14 months of grasping at straws and stalling for the EPA to admit they never had a valid case. While it is frustrating that the legal fight had to drag on at all, I guess those of us in the oil and gas industry should at least be glad that the EPA finally admitted its error, rather than continuing to waste more taxpayer money and time on pointless litigation.

In applauding this long overdue admission by the EPA, Railroad Commission Chairman Barry Smitherman said, “By dropping their court case and the enforcement actions, EPA now acknowledges what we at the Railroad Commission have known for more than a year: Range Resources' Parker County gas wells did not contaminate groundwater.” Fellow Commissioner David Porter went further, saying, “Today the EPA finally made a decision based on science and fact versus playing politics with the Texas economy.” Mr. Porter also made a statement that many Texans whole-heartedly agree with: “Today’s decision reflects my longstanding position that the EPA and the Obama administration should stay out of regulatory matters in Texas and let us remain in charge of protecting our own natural resources.”

One could hope that the EPA has seen the light and will stop the campaign against the oil and gas industry. Their about-face on Range Resources shows that even the EPA can’t ignore science forever. But with so much political posturing going on, especially in an election year, it is unlikely that the EPA and the current administration will give up their position as the refuge of the poorly trained, the unscientific and the ill-informed any time soon! Seriously, I realize there are some good folks at the EPA, but whoever had anything to do with this particular proceeding are not among them.

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June 15, 2012

Oil and Gas Wells Create Jobs in Texas and in the United States

Earlier this month, a study by the New York-based World Economic Forum (WEF) found that the energy industry was responsible for 9% of all new job growth in the United States in 2011. In the US, the oil and gas industry grew at 4.5% last year, compared to a 1.7% total GDP growth nationwide. The WEF Report, entitled "Energy for Economic Growth", was released on March 7, 2012 in Houston, Texas during the IHS-Cambridge Energy Research Associates Energy Week, and states that the US oil and gas industry directly created 37,000 jobs and indirectly created 111,000 jobs in 2011 alone. Those numbers indicate that the energy sector has trended towards creating more growth indirectly than via direct job creation, highlighting the ripple effect that industry growth has on the job market as a whole.

1388612_market_movements_2.jpg Roberto Bocca, senior energy industries director at WEF, has been quoted as saying that “we always suspected that energy had a vital role to play in the economic recovery, but we were still surprised when the data uncovered the magnitude of the sector’s multiplier effects.” The report concludes that the energy industry is by its nature capital intensive and therefore contributes significantly to the economy as a whole. In addition, energy sector jobs in general require highly trained and skilled workers and those workers are paid good salaries. Per worker earnings for the industry are twice as high as average earnings in Germany, Norway, the UK, and the US, and four times the average in Mexico and South Korea. Because of these higher earnings, industry workers have more disposable income to spend than the average worker and therefore help the economy by spending in other areas. Also important for the “multiplier effect” is the industry’s extensive supply chain to keep the sector running. The oil and gas industry has a greater impact on the economy than even the financial, telecommunications, software, and non-residential construction sectors.

The WEF Report also looked at the role of energy prices and how they affect economies. The Report pointed out that lower energy costs reduced prices across the board, thus making products more affordable to consumers. Lower energy costs also increase the discretionary spending of consumers and businesses. The study showed that lower natural gas prices will result in a 1.3% increase in US GDP in 2013, one million more jobs in 2014, and, by 2017, a 3% increase in industrial production output than without the anticipated shale gas development.

This Report was good news for the rest of the world as well, because it also predicted that the global energy sector would help pull the world economy back from the recent recession. The report highlights some countries—China, India, and South Korea—that have focused on renewable energy sources as growth sectors for their economies. Other developed countries are focusing on this renewable sector, as well, to achieve sustainability goals. The Report pointed out, however, that these new technologies have higher costs and so creates trade-offs that should be considered. In any case, HIS-CERA Chairman and Pulitzer Prize-winning author Daniel Yergin said, “The energy sector has the potential to be a tremendous economic catalyst and a source of innovation in its own right, while it simultaneously produces the very lifeblood that drives the broader economy.”

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June 7, 2012

American Petroleum Institute sues EPA over Unrealistic Requirements

In a suit with implications for Texas gasoline consumers, the American Petroleum Institute filed a petition for review in the US Court of Appeals for the District of Columbia last week against the Environmental Protection Agency over what it deems unachievable bio-fuels use requirements. These latest requirements are in the 2012 Renewable Fuel Standard. It seems that once again the government is trying to use the EPA as a cudgel to beat the oil and gas industry, and the API is having none of it.

The Clean Air Act requires that the EPA determine the required amount of cellulosic bio-fuels used in gasoline each year, depending on the volume available. This year, the EPA mandates that refiners and importers of gas and diesel use 8.65 million gallons of cellulosic bio-fuels, but in reality, there is an almost complete dearth of that type of fuel commercially available. Bob Greco, API’s director of downstream and industry operations, has been quoted as saying that the “EPA’s standard is divorced from reality and forces refiners to purchase credits for cellulosic fuels that do not exist. EPA’s unrealistic mandate is effectively a tax on manufacturers of gasoline that could ultimately burden consumers.” He went on to call it a “regulatory absurdity.”

The API has historically a realistic and workable Renewable Fuel Standard and wants the EPA to base its assessments on at least two months of actual cellulosic bio-fuel production in the current year when deciding upon the following year’s requirements. Instead, what the EPA does is rely on the promises of cellulosic bio-fuel production companies of how much they can produce, even though those promises have been, and continue to be, of questionable validity.

This lawsuit is the latest move in a ridiculous situation with the EPA mandating the use of a material that is simply not available. The New York Times reported on this problem and the lack of cellulosic bio-fuels in January. The president of the National Petrochemicals and Refiners Association told the New York Times that the 2011 bio-fuel requirement “belies logic” and the 2012 numbers make even less sense. In 2011, fuel companies paid the Treasury about $6.8 million in penalties because of this bio-fuel requirement, even though advocates of cellulosic bio-fuels admit that oil and gas companies are correct in complaining that it is not available!

The idea behind this cellulosic bio-fuel requirement is the government’s goal of having 36 billion gallons of bio-fuels incorporated into gasoline annually by 2022, as set out in the Energy Independence and Security Act. But that has little basis in the reality of today’s marketplace. Regardless, the EPA maintains, despite all evidence to the contrary, that this 2012 requirement is “reasonably attainable” and that the EPA will push on with these bio-fuels requirements because they want to avoid a theoretical problem of having too much cellulosic bio-fuel on the market.

While there is a whole separate debate about: 1) whether the EPA should be allowed to mandate the contents of gasoline; 2) the cost to all of us because of the damage that gasoline with bio-fuels causes to engines; and 3) the efficacy of using bio-fuels at all when so much fossil fuel has been discovered to be commercially accessible in the United States in the last few years, the actual facts of this situation are almost too ludicrous to believe. The federal government is mandating the use of a product that does not exist, and then functionally taxing companies for not using it!! Who knows what’s next in this anti-energy environment in Washington.

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June 1, 2012

New Federal Pipeline Safety Legislation Applies to Texas Gas Pipelines

Recently both the U S House of Representatives and the Senate passed by unanimous vote new federal pipeline legislation. The legislation would both reauthorize and strengthen existing pipelines safety programs through 2015, improve enforcement of existing laws, address National Transportation Safety Board recommendations, and fill in any gaps in the law if necessary.


This was the most recent of the pipeline safety acts passed by Congress. The very first statute that regulated pipeline safety, the Natural Gas Pipeline Safety Act, was passed in 1968 and amended in 1976. Congress added language about liquid pipelines to the statute in the Pipeline Safety Act of 1979. The Acts that followed were the Pipeline Safety Reauthorization Act of 1988, the Pipeline Safety Act of 1992, the Accountable Pipeline Safety and Partnership Act of 1996, and the Pipeline Safety Improvement Act of 2002. Congress also created the Office of Pipeline Safety (part of the Department of Transportation) in 1968 for the purpose of overseeing and implementing pipeline safety regulations. However, the Office of Pipeline Safety has been accused of weak enforcement and ineffective rules.

The latest pipeline safety legislation was passed partly in response to disasters such as the 2010 PG&E pipeline explosion in San Bruno, California, that killed eight people, and an accident in July when an Exxon Mobil pipeline dumped an estimated 1,000 barrels into the Yellowstone River. Some of the specific features of the legislation include doubling the maximum fine for safety violations to $2 million, increasing the number of pipeline inspectors, and requiring automatic shutoff valves on new or replaced pipelines wherever “economically, technically and operationally feasible.” Oil and gas companies would be required to meet maximum pressure standards when testing all pipelines, including old ones.

Members of the oil and gas industry endorsed the legislation. Donald F. Santa, president of the Interstate Natural Gas Association of America, stated that improvements in integrity management, incident notification, public education, and pipeline safety research and development would result in “a safer, more reliable pipeline system nationwide.” Likewise, Dave McCurdy, the president of the American Gas Association, said that he looked forward to the bill finally reaching President Obama’s desk, where it would inevitably be signed.

Despite having many obvious benefits, the legislation contained some compromises that left some people wanting. Some critics complained that the legislation did not provide for enough safety inspectors (it authorizes the hiring of 10 federal inspectors). Others, like Congresswoman Jackie Speier, who represents San Bruno, felt that the language on automatic and remote shutoff valves was still too weak.

Continue reading "New Federal Pipeline Safety Legislation Applies to Texas Gas Pipelines" »

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May 25, 2012

Texas Fracing Study Interim Results: Hydraulic Fracturing Does Not Pollute Groundwater

Hydraulic fracturing has often been criticized for its possible effect on groundwater, but the early results of a study by the Energy Institute at The University of Texas at Austin indicates that the concern is largely unfounded. Early results of the study, entitled "Separating Fact from Fiction in Shale Gas Development" shows that the process alone does not contaminate drinking water. Instead, what the study pointed out was that fracturing sites might have a higher rate of surface problems that could occur with any type of drilling.


The purpose of hydraulic fracturing is to wrest natural gas and oil from shale and sand formations, which tend to be dense and difficult to penetrate. The hydraulic fracturing approach uses a combination of sand and chemicals, mixed with millions of gallons of water, to break up and keep open the shale formations, resulting in hydrocarbons being released. Although most of the fracturing fluid is water, a tiny percentage is made up of chemicals, several of which could potentially be dangerous. There have been reports of surface spills killing livestock and polluting drinking water. The EPA has blown that tiny percentage out of proportion, claiming that fracking fluid in general is harmful and should be phased out by the oil and gas industry.

Yet the University of Texas results show that hydraulic fracturing has been getting an undeserved bad reputation. According to Chip Groat, the University of Texas geologist leading the study, what actually happens is that shale drilling causes more problems on the surface than drilling without fracking. These problems include spills of drilling and fracking fluids and leaks from wastewater pits. There have also been problems with surface casing (a steel pipe at the top of a well meant to isolate the flow of hydrocarbons from aquifers) as well as the cement jobs that hold the casing in place, but these are problems common to any type of drilling project, not just fracking. Chip Groat’s position is that no evidence links these problems to incidents of groundwater contamination.

In Texas, hydraulic fracturing is a common practice of the oil and gas industry. Prior to the study, the Railroad Commission of Texas, the state’s oil and gas regulator, reported at least 311 complaints about the possibility of contaminated drinking water from the beginning of 2006 to the end of September this year. However, one of the commissioners stressed that no complaint had ever been linked to an improper well cement casing.

The University of Texas study shows why it is important to get all of the facts before rushing to pass legislation -- on a state or federal level -- banning or seriously restricting a method that the oil and gas industry use on a regular basis. If legislators reacted to people’s fears and just passed legislation, the oil and gas industry could suffer a serious profit loss without any genuine benefit to the public. Indeed, the public would be hurt because losses in the oil and gas industry mean losses for everyone, across a wide span of industries. Texas depends upon oil and gas producers to keep its economy humming along. Therefore, any legislation that threatens to curb their actions must be thoroughly examined for potential harmful effect.

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May 6, 2012

Texas' Proposed Rule 3.29 for Hydraulic Fracturing Chemicals Disclosure

Last fall, the Texas Railroad Commission held a hearing to consider a new rule for disclosure of hydraulic fracturing chemicals. At the hearing, Chemistry Professor Andrew Barron from Rice University claimed that the rule would serve to demystify the chemicals used and help assure the public that the chemicals were not overly dangerous.


The new rule will be codified as 16 Texas Administrative Code section 3.29 and would implement House Bill 3328. House Bill 3328 has already been passed by the Texas state legislature and signed by Governor Perry. Section 3.29(c) lists disclosure requirements for suppliers, service companies, and operators who are involved with hydraulic fracturing. Under the Rule, not later than 30 days after the completion of a hydraulic fracturing treatment, suppliers and service companies must provide the well operator with the names of each chemical substance that was purposely added to the hydraulic fracturing fluid. In particular, any chemical ingredient that requires a Material Safety Data Sheet must be listed.

The rule defines “chemical ingredient” as “a discrete chemical constituent with its own specific name or identity.” An additive is “any chemical substance or combination of substances” contained in a hydraulic fracturing fluid that is purposely added to the base fluid for a specific reason whether or not that reason is to create fractures in a formation.

Under the rule, operators of wells have the responsibility of submitting information to a hydraulic fracturing chemical disclosure online registry. The data that must be given includes the operator’s name, the date of the treatment, the well’s location, the well’s API number, the amount of water used in the treatment, each chemical treatment used, and several other important pieces of information. Operators must also submit a well completion report for each well that received a hydraulic fracturing treatment to the Railroad Commission. Certain chemical ingredients are exempt from being listed under Section 3.29(d), such as ingredients not disclosed by their manufacturer, or ingredients not intentionally added to the hydraulic fracturing treatment. Ingredients that are trade secrets would also be protected from disclosure.

The proposed rule was published in the Texas Register on September 9, 2011. A 32-day public comment period -- including the October 5th hearing -- has already concluded. Some of the comments came from sources such as Pioneer Natural Resources. In an October 11, 2011 letter, Pioneer’s Vice President of Government Affairs, Roger Wallace wrote: “Pioneer strongly supports mandatory public disclosure of the chemical ingredients used in hydraulic fracturing.” Wallace expressed concern that the Railroad Commission would come under pressure to create a rule that gives suppliers, service companies, and operators too much discretion, and thought that the trade secret section would make it too easy for certain ingredients to be kept hidden. Meanwhile, the Texas Oil and Gas Association -- which produces 90% of Texas’s crude oil and natural gas -- expressed general support and proposed several revisions to the rule. These revisions include clarifying a number of terms, such as “hydraulic fracturing treatment” and “landowner,” and promoting a clearer process for challenging a claim of trade secrets. Already, several oil and gas companies voluntarily post the ingredients of their frac fluids on their websites. I suspect that the disclosures made will allow people to see that the chemicals used are pretty mundane, and hopefully some of the hysteria about fraking will dissipate.

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May 1, 2012

Senate Subcommittee Reports That States Regulate the Shale Oil and Gas Industry Effectively

Contrary to the Obama administration’s expectations, it sounds as though states are doing a fine job regulating the oil and gas industry, according to members of a shale gas subcommittee in the U.S. Senate. In the Shale Gas Subcommittee 90-day Report subcommittee members reported to the Senate Committee on Energy and Natural Resources during a hearing last fall. The subcommittee was formed to make recommendations about the safety and environmental performance of shale gas production.


The Report made 20 recommendations, including:

1. Improve public information about shale gas operations.

2. Improve communication between state and federal regulators. The subcommittee recommended continued yearly support to STRONGER (the State Review of Oil and Natural Gas Environmental Regulation) and to the Ground Water Protection Council for expansion of a data management system that determines risk, along with similar programs.

3. Improve air quality. The subcommittee had recommendations for reducing general pollutants, ozone precursors, and methane quickly.

4. Protect water quality. The subcommittee recommended a water management system based on “consistent measurement and public disclosure of the flow and composition of water at every stage of the shale gas production process.”

5. Disclose fracturing fluid composition. The subcommittee believed that although the risk was remote that fluid from deep shale reservoirs fractures could leak into drinking water, any chemicals in fracturing fluids should be made available to the public.

6. Manage short-term and cumulative impacts on communities, land use, wildlife, and ecologies.

Continue reading "Senate Subcommittee Reports That States Regulate the Shale Oil and Gas Industry Effectively" »

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April 13, 2012

Make Sure That Your Texas Oil and Gas Agreement Complies With the Texas Statute of Frauds

Any good Texas oil and gas attorney must be fully versed in the Texas Statute of Frauds. The Statute of Frauds is an old concept, requiring that certain contracts have to be in writing and signed to be valid. The Statute of Frauds dates back to at least seventeenth century England, and was exported to the United States as part of common law. It now exists in the Texas Uniform Commercial Code and in the Texas Business and Commerce Code. The Texas Statute of Frauds requires that all conveyances of real property and transfers of mineral interests (including oil and gas leases) be in a writing, signed by both parties.


For an agreement to comply with the Statute of Frauds, it has to include all of the essential elements of the agreement. Basic elements include the time of performance and a description of the property. This may sound fairly straight forward, but time and again, disputes have arisen over oil and gas agreements and conveyances that failed to accurately describe the interest being conveyed -- or in which the conveyance was not in writing at all.

For example, in Quigley v. Bennett (2007), geologist Robert Bennett charged Michael Quigley, an oil and gas operator, with fraudulently inducing him to perform services related to an oil and gas lease. Bennett claimed that he was entitled to an overriding royalty interest that Quigley had conveyed to him orally in return for certain services that Bennett performed. The Texas Supreme Court disagreed. Because Bennett and Quigley never put the conveyance in writing, Bennett had no interest. He therefore was not entitled to the $1 million award that the jury had given him.

More recently, in Preston Exploration Co. v. Chesapeake Energy Co. (2010), the Court reviewed a disagreement over the legal descriptions in Purchase and Sale Agreements for oil leases. Preston argued that the Purchase and Sale Agreements and exhibits complied with the Statute of Frauds because the description identified the property being conveyed with “reasonable certainty.” However, the District Court of the Southern District of Texas found that since neither the Agreements nor the exhibits included specific information about the location of the leases, they failed to comply with the Statute of Frauds.

So if you want to transfer an oil and gas interest, how can you make sure that your agreement complies with the Statute of Frauds? This is one of those situations where you really might want to consider enlisting the assistance of an attorney to make sure it's done right. As mentioned above, the agreement should identify the property with reasonable certainty, which means “the contract must, at least, furnish the property description within itself or by reference to other identified writing then in existence.” Multiple writings can accomplish this purpose as long as the second document refers to the first -- something the agreement in Preston failed to do. In identifying land with reasonable certainty, an agreement should identify characteristics such as the amount of land; the specific tract the land is on; the city, county, or state where the land is located; the specific street address (if any), etc. There should be no doubt about where the land is located. Maps and plats can be used to identify the tract of land, but they must be very specific. Ideally, they should provide information such as the names of the owners in the chain of title, General Land Office Abstract numbers, survey lines of each tract, the amount of acreage in each tract, etc. As the Preston case illustrates, you can’t just refer to a “lease” and expect that to be enough.

In summary, if you are involved in the transfer of an oil and gas interest, you not only need a written document, but also clear and specific language in the document identifying the terms of the agreement and the land involved, namely its size and location. If your agreement complies with the Statute of Frauds, and you hopefully won’t be one of the unfortunate few who have to defend their interests in court.

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March 23, 2012

New Study Shows That Removing Oil and Gas Industry Tax Credits Would Cost Jobs, Increase the Deficit

The oil and gas industry is under attack not only in Texas, but nationally. Several months ago, a new study by Louisiana State University Professor Joseph Manson, An Economic Analysis of Dual Capacity and Section 199 Proposals for the U.S. Oil and Gas Industry, was released. Professor Manson's study found that tax changes proposed by the Obama administration would actually increase the deficit.


One of Obama's proposals would prohibit oil and gas companies from using the manufacturer’s deduction created by Section 199 of the American Job Creation Act of 2004. The other proposal would create limits on foreign tax credits used by U.S. dual-capacity taxpayers. The Obama administration claims that these changes would lower the deficit and has included them in every annual budget proposal. Instead, Professor Manson demonstrates that these proposals would result in a loss of $53.5 billion a year in tax revenue.

Section 199 allows taxpayers who produce or manufacture in the United States to deduct a certain percentage of domestic production activity from their taxable income each year. The dual-capacity taxpayer rules prevent U.S. firms operating in foreign countries from being doubly taxed. Professor Manson’s study, sponsored by the American Energy Alliance, took a detailed look at the effect that the loss of these credits would have on the oil and gas industry. Professor Manson concluded that there would be a loss of 155,000 lost jobs, a loss of $68 billion in wages, and a loss of $83.5 billion in reduced tax revenues. Not only that, beware the unintended consequences: as more people are laid off, more people will request unemployment benefits, food stamps and other forms of assistance.

Professor Manson made his calculations using the Modern Regional Input-Output Modeling System II, developed by Nobel Economic Laureate Wassily Leontief, which supposes that when a company has to pay $1 more in taxes, it must take it out of other sources, such as workers’ pay. As a result, Professor Manson notes: “[A] tax on just a small number of firms can be felt throughout the economy.” He found that job losses go beyond those strictly related to oil and gas production: construction, retail, food services, and even arts and entertainment would feel the pain. Not only would there be significant job losses, but also the U.S. could suffer $341 million in lost output. The region hardest hit would be the Gulf of Mexico, where the local community has already suffered extensively following the Deepwater Horizon tragedy.

Professor Manson has a long, distinguished history in finance. He has been a Senior Fellow at The Wharton School since 2005. He was a Visiting Scholar for the Federal Deposit Insurance Corporation and the Federal Reserve Bank of Philadelphia. He has consulted for government agencies, research institutions, and corporations on issues ranging from mortgages to consumer lending to valuing distressed securities. He has also testified before numerous government committees, including the Senate Judiciary Committee, the House Financial Services Committee, the Federal Reserve Board, and the European Parliament. His opinions are valued and respected, which is why his conclusions in the new study should not be dismissed.

The repeated introduction of these proposals confirms that the Obama administration’s approach to the oil and gas industry is misguided. It treats all companies as though they are greedy conglomerates hoarding billions at the expense of the average American. In fact, this study shows that oil and gas companies benefit Americans in a variety of industries every day. Singling out these companies by removing these particular tax benefits means that everyone would feel the pain.

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March 10, 2012

Texas Landowners' Easement Rights Case Clarified by Texas Supreme Court

Readers may recall that last year the Supreme Court of Texas issued an opinion with profound implications for the rights of Texas landowners when they are faced with a request for a pipeline or utility easement. In Texas Rice Land Partners Ltd. and Mike Latta v. Denbury Green Pipeline-Texas LLC, issued on August 26, 2011, the Court addressed the issue of the requirements a pipeline company must meet in order to be deemed a common carrier and thus be entitled to use the power of eminent domain. My discussion of the original opinion can be found here.

In its original decision, the Court limited the eminent domain powers of pipeline companies, stating that they must show more than that the pipeline could be used by others, aside from the company building the pipeline, at some indefinite point in the future. In addition, the Court held that a permit issued by the Texas Railroad Commission, which was previously assumed to confer common carrier status (and thus eminent domain power), no longer has this effect. This decision, therefore, shifts the burden onto the pipeline company to prove that it meets the requirements to be classified as a common carrier. The Court’s decision gives vastly more power to landowners, and the case is likely to impact the attitude of all pipeline and utility companies negotiating with landowners for easements and rights of way.

In an opinion last Friday, the Supreme Court not only denied Denbury Green Pipeline's motion for rehearing, but Court also clarified its previous judgment in significant ways. In stating that a company cannot wield the power of eminent domain for a private oil or gas pipeline, the Court added that "private" means a pipeline that is limited in its use to wells, stations, plants, and refineries of the owner. The Court went on to say that a “common carrier” means that the company is transporting gas for hire and therefore implies more customers for the gas than the owner of the pipeline. In other words, the pipeline cannot be built for the owner’s exclusive use and still be a common carrier.

In this second decision, the Supreme Court affirmed its prior determination that Denbury’s pipeline was for private use only. It found that this pipeline would not serve a public use by transporting gas only from one Denbury property to another Denbury property. The Court also cited an absence of compelling legislative findings and or a sufficient public purpose in support of its conclusion that this pipeline was private. Finally, the Court stated that for an entity planning to build a CO2 pipeline to qualify as a common carrier under Texas Natural Resources Code Section 111.002(6), there must be a “reasonable probability” that at some point in the future the pipeline will serve the public by transporting gas for more than one customer that will either use the gas or sell it to someone other than the pipeline carrier.

While acknowledging that pipeline construction and the Texas energy industry are important to maintain Texas' economic growth, both the Court's original decision and the substituted opinion denying Denbury's motion for rehearing echo hundreds of years of legal and Constitutional precedent protecting individual property rights as a cornerstone of our government. The Court noted that Texas protects landowner rights even more strongly than neighboring states, and it should take more than simply checking a box on a government form to confer common carrier status and all that goes with it, all without a right of judicial review.

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March 1, 2012

"Clean" Energy is More Hazardous To the Environment than Oil and Gas Drilling

Environmentalists like to argue that oil and gas are harmful to the planet, that their sources are drying up, and that “clean” green energy is the way of the future. However, more studies are finding that green energy is far from harmless to the environment. In fact, it may actually be more harmful than traditional energy sources.

This is because the batteries that run “clean” energy hybrids, electric cars, and other related products are made up of rare earth elements (REEs). REEs consist of 15 periodic elements of the lanthanide group, along with scandium and yttrium. These metals are in nearly all batteries due to their unique properties.

hybrid_car.jpg According to an EPA report, because REEs are generally concentrated evenly throughout the Earth’s crust, there are few locations where they can be economically mined. That doesn’t mean, however, that a determined government would be unable to gain a monopoly over REEs. Or that REEs would not require extensive mining and refining.

While the United States controlled the REE industry up until 1985, in recent years, China has taken over. By some accounts, it now produces 95% of all REEs. China managed to gain control by flooding the market with cheap REEs, due to large high-quality reserves and low labor costs. Since then, China has sent the cost of REE products -- such as fluorescent light bulbs -- soaring. The United States is trying to regain its dominance, and American producers have received permission to conduct exploratory drilling for heavy metals. Currently Mountain Pass mine in California is the only mine that has been used for heavy metal mining. Government and industry have set their sights on the Bokan Mountains in Alaska, Diamond Creek in Idaho, and the Bear Lodge Mountains in Wyoming as other potential mining locations.

Of course, even if the race between China and the U.S. to dominate the REE industry does not result an in international crisis, there is still the matter of REEs’ environmental cost. Preparing REEs for consumer use is a costly and toxic process. First, each element must be extracted from the earth. Then the REE goes through chemical processing, disposal of contaminants, and transportation. Chinese production has resulted in large amounts of harmful gas, as well as large amounts of solid and liquid waste. Once these toxins have been released into the environment, they can rapidly spread through the air, soil, and water. A few months ago, the Chinese government shut down REE production to address the alarming levels of toxins in the environment, often from small REE producers who had little to no oversight. However, it remains to be seen whether China will be able to fix all of its problems -- or whether it is even possible to create an environmentally friendly refining process.

The problems above do not even touch upon what happens when “clean” batteries wear out and how they are disposed. The nickel in these hybrid batteries can leak into the environment, creating health problems for local residents.

So let's see: the leading environmentalist arguments against the oil and gas industry are: extraction is harmful for the environment, oil is becoming increasingly rare and dependence on oil forces us to rely upon other countries with whom we have tense relations. On the other hand, when we consider REEs, we can say that their extraction is harmful for the environment, they are becoming increasingly rare and dependence on REEs forces us to rely upon other countries with whom we have tense relations. After all that, we still have the environmental hazards that result from disposal.

With all that coming from “green” energy, maybe it’s time to give “traditional” energy another chance!!

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February 28, 2012

Do Oil and Gas Prices Really Move in Tandem?

The conventional wisdom is that when oil prices are high, gasoline prices follow. Yet is that really true? Just recently, oil prices were up more than 9%, yet gas prices at the pump actually dropped 15 cents, to 3.30 a gallon. Why is this? Well, it turns out the conventional wisdom is mostly true, but gasoline prices do not follow oil prices perfectly, and each has its own reasons for prices rising and falling.


First, why do gas prices tend to follow oil prices on an upward climb? According to one source, it is simply because when oil prices rise, gas dealers raise their prices in order to avoid losing money. At the same time, when oil prices go down, it can take anywhere from two days to three weeks for gas prices to fall. Another reason may have to do with the type of crude oil on the market. When crude oil is plentiful, but gas prices are still high, the reason may be because the crude is heavy and sour, which requires greater processing -- as opposed to light, sweet crude oil, which is easier to refine.

If this is the case, then why do oil and gas prices sometimes vary? There are several reasons, most very specific to the way oil and gas are produced and to their intended purpose. While nearly half of crude oil -- 42% -- is used for producing gas, the other 58% is used for diesel fuel, jet fuel, and is even used to make everyday products such as tires. Therefore, the more demand for these items, the more the price of oil will be affected.

As for why gas prices rise and fall, the reasons range from the methods of production to the state of the economy. First, gas prices are affected by demand -- when people travel in the summer, prices tend to go up. During the winter, with less travel, prices tend to drop. Second, there is not just demand for oil in the United States, but all across the world. China, India, and Brazil, all enjoying economic expansion, require more energy to keep their economies moving. Less oil means that it is more valuable, which increases the price of any product associated with it, including gas.

Third, gas is not just made of oil, but also of fuels meant to make gas cleaner burning. These fuels, such as ethanol, are often required additives, and their presence increases the cost of a gallon of gasoline. Even when all of these factors are taken into account, probably the biggest reason for gas’s continued high prices -- even while oil prices remain low -- is taxes. Taxes are imposed by both the state and federal government on every gallon you use, adding enormously to what you pay at the pump.

In short, high gas and oil prices are not part of some nefarious scheme cooked up by the oil industry to bilk consumers. There are a variety of reasons for oil and gas prices to be the way they are, mostly just having to do with the way each is processed. That said, if more oil and gas drilling were permitted, some of the pressures might be reduced, resulting in lower prices at the gas pump.

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February 18, 2012

Texas Oil Companies Expanding

In what is hopefully a sign of a healthy Texas oil and gas industry, as well as good news for Texas mineral owners, Apache Corporation (the subject of a recent post) has not only renewed its lease of 365,000 square feet at its Post Oak Central office building, but has also leased another 132,000 square feet of space. This represents a 36 percent office space increase, bringing Apache’s total square footage to 467,000. The company also extended its current lease term to 2018, a five year add-on to their agreement, which was set to expire at the end of this year. The Houston office complex is owned by JP Morgan and is distinct for its three 24 story glass and steel towers.


Apache’s move to expand its operations was likely prompted by the company’s healthy profit margins. The Wall Street Journal recently reported that Apache’s fourth quarter earnings were up 73 percent as the company benefited from high oil prices and increased production. Apache’s fourth quarter profit was $1.9 billion, or $2.98 a share. That is a substantial increase over their $689 million profit and $1.77 share price from 2011. Chief Executive G. Steven Farris said the company expected to spend $9.5 billion on drilling capital this year, up from $8 billion in 2011. Revenue also increased for the company by about 25 percent to $4.3 billion. Apache’s global production was up by 4.2 percent from a year earlier and average prices went up 24 percent for oil and nearly 3 percent for natural gas. These reports on Apache’s success are good news for the Texas energy industry and a benefit to Houston, the company’s headquarters.

This comes on the heels of other big real estate transactions in Houston, a city fortunate to be at the center of the oil and gas industry’s resurgence. In January, Noble Energy signed a lease for 467,000 ft2 of office space at the former headquarters of Hewlett Packard, taking over the northwest Houston building in its entirety. The 10 story building opened in 1998 as the headquarters for Compaq Computer Corporation. The building was one of Houston’s largest vacant office buildings and Noble’s lease is helping bring the city’s vacancy numbers down significantly—showing once again how a robust and profitable energy industry can help the economy as a whole.

In December, Shell Oil renewed its 1.2 million ft2 office lease at One Shell Plaza and Two Shell Plaza in downtown Houston. Shell’s Houston lease was the biggest lease signed in the United States in 2011. Last year, 1.8 million square feet of office space was occupied in Houston and that number is expected to be the same or greater this year, spurring new construction for the first time in years.

This energy boom is rippling across Houston’s economy and not just in real estate circles. Houston is the first major metropolitan area in the US to regain all the jobs lost during the recent recession. The region added 76,000 jobs last year according to the Texas Workforce Commission and is on track to create tens of thousands of more jobs this year, almost entirely thanks to the profitable and growing energy industry.

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Apache Oil Purchase Good News for the Texas Panhandle

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February 10, 2012

Separating Facts from Politics: Recent Studies on Fracing

The battle in Texas and in the country in the oil and gas field over hydraulic fracturing, or “fracing", rages on, of course. There are several recent developments in the effort to uncover the facts about fracing, as opposed to unsubstantiated claims and political posturing. These research efforts are important resources for better understanding of this technology and how it affects the environment and the natural gas industry. With so much discussion and debate on the issue of fracing, a technology used for years but subject to intense criticism only recently, it is especially important to publicize the scientific evidence related to the process, rather than buying into the political hype (see a previous post on my opinions here).

The University of Texas at Austin released its preliminary findings, entitled "Boom or Bane: A Report on Hydraulic Fracturing of Shale", excerpted from an intensive ongoing research and study project on this issue, on November 9, 2011. The University’s Energy Institute examined the use of hydraulic fracturing in shale gas drilling. The preliminary findings indicate that there is no direct link between fracing and groundwater contamination. The researchers suggest that, at worst, any contamination is probably from above ground spills, mishandling of drilling waste products, or faulty cement casings—not the the hydraulic fracturing itself. Dr. Charles “Chip” Groat, a UT geology professor and Energy Institute associate director who is leading this research project, stated at the release of the preliminary findings: “Our goal is to inject science into what has become an emotional debate and provide policymakers a foundation to develop sound rules and regulations.” The final report is expected to be released soon, in the early part of this year. The Energy Institute has two other projects on hydraulic fracturing in shale gas development in the works which may also shed light on the issue in the near future.

In November of last year, the Environmental Protection Agency released its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. This study intends to look into the potential effects on drinking water from various natural gas drilling techniques associated with hydraulic fracturing. The EPA plans to use existing data as well as developing case studies at the Haynesville, Marcellus, Bakken, and Barnett fields. They will study drinking water at sites where fracing has already been used and collect data both before and after fracing at new sites where the process has not been used before. This report will be released in two parts, the first of which is expected by the end of 2012. That first report will contain the analysis of existing data. The longer-term results of this EPA project will be released in a supplemental report in 2014, which will include information and conclusions from the case studies of new sites.

On November 10, 2011, the Shale Gas Production Subcommittee of the Secretary of Energy Advisory Board released its final report, entitled "The SEAB Shale Gas Production Subcommittee Second Ninety Day Report", on shale gas production. This report focused on implementation of the 20 recommendations made in a related interim report, including more public information about shale gas production, disclosure of the fracturing fluid’s composition, and the creation of a shale industry organization dedicated to improving best practices. The final report speaks mostly in generalities. It calls for progress in reducing the environmental impact of shale gas production and creating partnerships between the industry, states, and federal agencies.

There will always be some who seek to demonize anything that the oil and gas industry does. However, fair-minded people should ensure that their elected officials base any policy decisions related to fracing on real evidence and not partisan posturing.

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February 5, 2012

Chesapeake Reduction in Gas Well Drilling & Exploration May Effect Texas Mineral Owners

Texas mineral owners who have signed oil and gas leases with Chesapeake Energy may be faced with some unanswered questions.

The American natural gas industry faces the paradox of having been too successful in recent years. A glut of natural gas on the market due to technological advances have allowed access to previously inaccessible gas, especially through horizontal drilling and hydraulic fracturing. The glut of gas has pushed prices down 45 percent in the past year. In fact, natural gas prices are at a ten year low right now. As a consequence, the second largest natural gas producer in the nation, Chesapeake Energy Corporation, recently announced that it will cut gas production by half. The company will only operate 24 of its dry gas drilling rigs, down from the 50 rigs it operated in 2011.

Chesapeake’s measures will only reduce America’s supply of gas by 1.4 percent. The indications from other natural gas companies regarding cutting gas production has been mixed. EQT Corporation stated that it would suspend natural gas drilling in Kentucky indefinitely because of low prices. Exxon declined to comment. Cabot Oil & Gas has no plans to cut production.

Chesapeake says it will take the $2 billion it plans to cut from natural gas production and shift it into the more profitable area of oil production, as oil prices have remained high even as natural gas prices have fallen. Chesapeake also plans to cut $2 billion from its land buying budget and immediately cut production by 8 percent. It is deferring new dry gas wells and pipeline connections where possible. Chesapeake is considering letting current mineral leases expire. The company expects its lowest expenditures for dry gas drilling since 2005.

While this may be good for Chesapeake’s financial stability and its investors, it raises questions for Texas mineral owners who have already signed mineral leases with Chesapeake. If you are a Texas mineral owner who has already signed a lease with Chesapeake, you may wish to have a Texas oil and gas attorney review your lease to determine what your options may be.

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NAT GAS Act May Be Misguided Legislation

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January 31, 2012

Apache Oil Purchase Good News for the Texas Panhandle

New technology has breathed new life into older Texas oil fields in the Panhandle and in nearby Oklahoma. Apache Corp, one of the nation’s largest energy explorers, recently purchased Cordillera Energy Partners III LLC for $2.85 billion. Apache is paying $600 million in common stock and the rest in cash. The deal brings Apache control of 254,000 acres of the Granite Wash Field, an area of older oil wells in the Texas panhandle and across the Texas-Oklahoma border. It consists of a series of thick, multilayer, liquids-rich sandstone and conglomerates, and the area possesses superior reserve properties compared to other shale.

The remaining oil and natural gas in Granite Wash is between 11,000 and 13,000 feet deep, and there is natural gas at a depth of up to 17,000 feet. At these depths the oil and natural gas was technologically impossible to access in the past. Recent extraction advances broke through that technological hurdle, but the area was still economically nonviable because of the high costs involved. Apparently no longer. This area has estimated reserves of 71.5 million barrels of oil equivalent and a current net production of 18,000 BOE per day.
Apache is not new to the region. In fact, the company was formed in the Panhandle 57 years ago, and Apache has been drilling there for 35 years. Industry growth over the past few years, combined with Apache’s experience in the area, made this recent purchase a logical step for the oil giant. Apache has drilled 79 horizontal wells since 2009, providing the needed experience at accessing previously inaccessible oil and gas deposits using new drilling techniques. These new horizontal drilling options now account for about half of Apache’s Central Region production—about 40,000 net barrels of oil per day at the end of 2011. Hydraulic fracturing ("fracing") will also assist in accessing natural gas wells (see my post on fracing here. Apache’s Chief Executive, G. Steven Farris, stated that they expect to more than triple the activity of the combined Apache and Cordillera acreage in the coming year.

All of this is very good news for Texas Panhandle residents, as increased drilling activity will boost the local economy and create more jobs. It is also good news for the country as a whole. These new innovations and investments in energy have resulted in a resurgence of the oil and gas industry, so much so that natural gas prices fell to a ten year low last week. Apache is not the only company going after older wells with new technology—both Exxon and Chevron are going back to wells in areas that were thought to be tapped out. Apache itself has operations around the world, from Australia to Egypt, and has been trying to expand its production in the US. Now that Apache is acquiring Cordillera, the two companies are looking for further opportunities in oil fields in South Texas, North Dakota, and Pennsylvania. Cordillera Chief Executive George Solich, who began his career at Apache in the 1980s, said they will continue to acquire acreage in the Granite Wash area on behalf of Apache through the closing of the deal.

Texas mineral owners beware: if you own minerals in the Granite Wash area, or in counties adjoining this area, you may receive all kinds of offers to purchase your minerals. Don't ever consider selling your minerals without talking to a Texas oil and gas attorney first. In most cases, they will probably tell you not to sell, because you will probably never get paid what they are really worth!

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January 22, 2012

University of South Alabama Studies Impact of Gulf Oil Spill on Real Estate Values

One of the largest offshore oil spills in history occurred when the massive Deepwater Horizon semi-submersible oil drilling platform suffered a drilling-related explosion, was engulfed in flames, and sank. The economic and environmental effects of this event are still not fully understood, so studies are ongoing to determine the impact that it has had on the Gulf region. One such study, entitled "The Gulf Oil Spill and Its Impact on Coastal Property Value Using The Before-and-After Procedure" was completed several months ago by the University of South Alabama on the effect that the spill has had on Alabama coastal property values.

718977_big_oli_rig.jpgIn order to determine the amount of decline in value on affected coastal properties, the study made use of the before and after procedure (BAAP) that is based upon market prices preceding the Deepwater Horizon incident and data indicating the impacted value of those same properties after the accident occurred. The study seeks to determine if a stigma has attached to these properties, which amounts to the perceived blemishes on those properties that have arisen as a result of the spill. The study focused on evaluating properties located directly on the waterfront, multiple types of residential properties, and both developed and undeveloped land. It relied upon sales transaction records in the area for the year prior to the spill as a comparison basis to help determine the possible drop in value attributable to the spill.

The research showed that the possible effect on the studied areas was significant, and vacant residential properties on the waterfront suffered the greatest decrease in values after the spill, as they dropped over 42 percent in value from April 20, 2010, to August 15, 2010. Single-family waterfront residences saw a half-percent drop during the same period, and condominiums saw a 3.5 percent drop. However, much of the decrease in value was likely due to a downturn in prevailing economic conditions. A control group of properties located in Florida (not affected by the spill) was also tracked, and similarly situated properties also saw condo and vacant waterfront land prices drop by over 20 percent during the same time period, though single family residences saw a jump in value of over 30 percent. As such, the numbers indicate that only the drop in undeveloped property prices may have been caused by the oil spill.

While the study rendered a somewhat surprising result for many – that there was not a stigma attached to waterfront properties in the Gulf region of Alabama that caused a decline in property values – it also noted that there are some limitations to the analysis. The BAAP method is best served by having real-time property sales price information for continued evaluation to render more accurate results. Additionally, the BAAP does not factor in a decline in potential buyers in the market, and instead only focuses on sales prices properties during the study’s time period. In order to formulate a more full analysis of the Gulf Oil Spill’s effect on real estate values in the region, an adjustment process for the decline in buying activity is needed.

With the passage of time, we have seen that the long term effects of the Deepwater Horizon incident have been much smaller than expected. If a study were done today, I suspect it would reveal no lingering effect on any property values along the Gulf.

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January 13, 2012

New Ammunition for Negotiation of Oil and Gas Pipeline Easements for Texas Property Owners

A recent decision by a Texas Court of Appeals may be helpful to Texas property owners who are negotiating an oil and gas pipeline right of way or easement on their property. In its opinion rendered in LaSalle Pipeline LP v. Donnell Lands LP, the Texas Fourth Court of Appeals in San Antonio upheld a jury award to a Texas landowner of $604,950.00 for dimunition in value to approximately half of the landowner's 8034 acre ranch in McMullen County, Texas.

951423_alaskan_pipeline_2.jpg LaSalle, the pipeline company, enjoyed the right of eminent domain, or condemnation, of the right of way for its pipeline, because the pipeline it was laying was intended to be a common carrier. However, LaSalle offered the landowner nothing for for the decrease in value to the Donnell's land due to the 16" gas pipeline stretching across almost five miles of their property.

At trial, the Donnell's expert witness, (an M.A.I. appraiser who specialized in farm and ranch land appraisals), testified that he believed the first tract involved would suffer a 10% decrease in value due to the pipeline, and that the second, smaller, tract, would experience a 25% decrease in value. He arrived at his figures by comparing sales of similiar land, with and without pipelines, both in McMullen County and nearby Webb County. The Donnell's expert testified that the landowner was due $902,255.00 in damages, consisting of dimunition in value damages, payments for the right of way itself and the temporary workspace damages. The landowner also testified about why he believed the pipeline would decrease the value of his property. These reasons included: 1) the pipeline would be there forever, and would always be a "black mark" on his land; 2) the pipeline cut right through the middle of his property; 3) the pipeline owner and operator would have permanent access to come and go whenever they wanted; and 4) the pipeline easement could be freely assigned to any other company.

This last reason is especially important. No one can guarantee that the right of way will not be assigned in the future to a company who is less than diligent in doing maintenance, or who is less than careful with the adjoining land, than the current pipeline company.

LaSalle appealed the jury award to the Fourth Court of Appeals in San Antonio. The Court of Appeals made a small adjustment to the temporary workspace damages, but otherwise upheld the jury's verdict and the damage award. LaSalle will no doubt appeal to the Texas Supreme Court.

I'd say that the pipeline company brought this result on themselves, by refusing to offer the landowner any dimunition in value damages (also called "remainder damages") and by taking the position both in the trial court and in the Court of Appeals that the pipeline did not create any damage to the rest of the landowner's property. That is a pretty arrogant, and ultimately, self-defeating attitude.

The Fourth Court of Appeals was not creating new law in this decision. They relied on established Texas law. I never want to be in the position of predicting how the Texas Supreme Court will decide something, but if I was a betting woman, I'd bet that the Texas Supreme Court will uphold this decision.

The pipeline industry is already complaining that this decision injects "uncertainty" into the process of obtaining pipeline easements. What a strange, and frankly, groundless, argument. First, real estate appraisers have been calculating, and Texas courts and juries have been deciding, these kind of damages for many decades. Secondly, landowners have a right to dimunition in value damages because they have a right to be fairly compensated for all damages caused by pipelines and utility lines.

I'm not going to apologize if this next statement sounds naive to you. There is a moral issue here. Sometimes it seems like the pipeline companies are observing that "other" Golden Rule (the one that says "He who's got the gold, makes the rules") rather than the real Golden Rule: "Do unto others as you would have them do unto you". There is also a practical side to this: pipeline companies might find property owners a whole lot easier to negotiate with if the companies are truly fair to the owners. I suspect that a whole lot more right of way can be acquired a lot more quickly and at a lot less cost that way.

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January 5, 2012

NAT GAS Act May Be Misguided Legislation

It is important for all of us to keep informed about proposed legislation related to energy issues. Even if you aren't an oil and gas attorney or involved directly in the energy industry in some way, all of us are affected by energy independence (or lack thereof) and prices. Local, state, and federal legislation often has profound effects on how much energy costs us and whether or not America’s own energy potential is maximized.

775062_oil.jpg Consider the New Alternative Transportation to Give Americans Solutions Act, otherwise known as the NAT GAS Act. Originally, this bill seemed like a good idea. It was introduced in the House by Oklahoma Republican John Sullivan and shepherded through the Senate by Democrats Harry Reid of Nevada and Robert Menendez of New Jersey and Republicans Richard Burr of North Carolina and Saxby Chambliss of Georgia.

The NAT GAS Act would allow consumers or investors who either purchased natural gas vehicles or who built natural gas stations to claim between $5 billion and $9 billion in federal tax credits over the next five years. It had bipartisan support. Many Republicans were happy to sign on initially because of their tendency to support legislation helping the natural gas industry and to give this important sector of our economy a reprieve from some of the currently oppressive taxes. A bevy of prominent business leaders signed on as well, such as T. Boone Pickens .

This support is understandable because America needs more natural gas—an efficient, abundant, and clean energy source. However, it apparently remains a challenge to enact common sense legislation involving natural gas use. Certain segments of the liberal left have been waging a war against natural gas for years. Also, some state legislatures are shortsightedly fighting energy tax savings by actually raising taxes to preserve their own government spending. This ultimately hamstrings industry growth and job creation. Expectedly, President Obama continues his knee-jerk reaction in opposition to any type of sensible fossil fuel policy. The politically-motivated outcry over hydraulic fracturing, and efforts to curtail a demonstrable safe 60 year old practice, (click here for related blog) interferes with rational discussion on the subject.

Despite the real need for sensible energy legislation freeing the natural gas industry for growth, the NAT GAS Act may actually be more of a mirage of responsible legislation than anything else. Recently, 19 Republican co-sponsors have dropped out after considering the real consequences of this legislation. More analysis has shown that the Act does not truly facilitate natural gas production or assuage supply-side concerns, which probably explains why so many Democrats signed on. What the Act really does is skew the market by favoring some consumers over others, which may result in artificially inflating the cost of natural gas. It is may also be unnecessary, as UPS and other companies have fleets of vehicles powered by natural gas without the NAT GAS Act.

At the end of the day, the energy creation environment is complicated enough without further unnecessary laws and regulations being injected into the process. Certain legislation in the area may be helpful, but it is important that it remain revenue neutral, so as not to be used merely to increase federal coffers. The most logical solution is usually to allow the free market to work efficiently and without artificial alterations instead of promoting more unnecessary legislation which distorts natural energy demand.

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December 27, 2011

Royalty Owners: Delay in Claiming Lost or Unpaid Oil and Gas Royalties Can Cost You!

Assisting royalty owners in locating lost oil and gas royalties, and getting royalty owners paid their rightful royalty payments, is one of the parts of my practice as a Texas oil and gas attorney that I enjoy the most. However, many of my clients are suprised to learn that there is a pretty strict time limit to how far back they can claim unpaid or underpaid royalties. For that reason, if you think you are not getting royalties to which you are entitled, or if you think your royalty payments are not being correctly calculated and that you may be underpaid, it is important to take action to correct the situation sooner, rather than later.

A recent decision last week by the Texas Supreme Court underscores this point. Specifically, the Court issued a decision in Shell Oil Co., et al. v. Ralph Ross which could effect all future royalty disputes in Texas. In a nutshell, the Court solidified the four year limit under Texas law within which a lawsuit for underpaid or nonpaid royalties must be filed.

The case involved a dispute between the Ralph Ross, as the Plaintiff, and Shell Oil Company. Mr. Ross’s family had leased the mineral rights on their land to Shell since 1961. Mr. Ross is an oil and gas attorney and therefore understood the oil and gas industry and the relevant legal issues more than the usual lessor. Under the original lease, Shell was required to pay a certain percentage to the family for any gas produced from the land—a total roughly equaling one sixteenth of the profits. However, between 1994 and 1997, Shell used a different calculation, and underpaid Mr. Ross and his family for their royalties. Shell claimed this was due to a simple accounting mistake.

In 2002, Mr. Ross assumed all rights relating to his family’s oil and gas lease and first became aware of the underpayment. In 2002, Mr. Ross sued Shell Oil for breach of contract, unjust enrichment, and fraud. The family’s legal claims were brought five years after the final underpayment took place. Texas has a four year statute of limitations for filing this type of suit. However, the family argued that the statute of limitations period should be extended, or "tolled", under the “fraudulent concealment doctrine.” The doctrine essentially states that if a defendant conceals information from the plaintiff, and as a result the plaintiff could not have become aware of the problem, then the statute of limitations "clock" will not start to run until the plaintiff actually becomes aware (or should have become aware) of the problem.

Both the trial and appellate courts found for the family, holding that Shell had behaved fraudulently in underpaying for the gas produced from the family's land and that Shell engaged in fraudulent conduct which extended (or "tolled") the four year statute of limitations. Shell appealed the decision of the trial court and court of appeals to the Texas Supreme Court.

Last week the Supreme Court reversed the decision of the lower courts and found for Shell Oil. Justice Lehrmann, writing the opinion, held that contrary to the lower courts’ rulings, the fraudulent concealment doctrine did not toll the limitation period in this case. Justice Lehrmann noted that royalty owners are required to make themselves aware of relevant information which was publicly available to the royalty owners regarding the royalty payments they actually receive (or don't receive) and the payments they should have received. The Court held that if a royalty owner fails to utilize due diligence by finding that information within the 4 year limitations period, then that royalty owner's claim has expired. This opinion was a reiteration of the Court’s decision in BP Am. Prod. Co. v. Marshall.

The Court went on to say that there were significant discrepancies in royalties paid to the Ross family, and that these discepancies put them on notice that Shell was underpaying them. The Court also restated its decision in Wagner & Brown, Ltd. et al v. Horwood, in which they held that even if a reasonable explanation for the suspiciously low royalty payments exists, the royalty owner cannot avoid the due diligence requirement to investigate. The Court concluded that Shell’s alleged fraud could have been discovered by the Ross family if they had acted diligently during the limitations period. As a result, the family could not go forward with their suit.

This ruling is another reminder of how important it is to keep on top of your rights under an oil and gas lease. It is risky to sit on your rights, let suspicious payments slide, or let a land man or company agent explain away issues which may actually be a violation of the lease. Be aware that most disputes regarding royalties end up being settled, and do not end up in a lawsuit in court. However, the four year cutoff is going to apply in a negotiated settlement, as well as in a lawsuit.

With the four year statute of limitations period firmly set in Texas oil and gas law, if you are suspicious or concerned about low royalty payments, or about royalty payments that you should be getting but are not, it is imperative to talk to a Texas oil and gas attorney right away to protect your interests. Waiting too long could very well forfeit your rights to missing, underpaid or unpaid royalties.

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December 18, 2011

Oil & Gas Companies Spend More on Greenhouse Gas Mitigation Than Government and Private Industries

There are a number of misguided environmental "activists" who characterize efforts to reduce greenhouse gas emissions as some kind of a “David vs. Goliath” struggle between forward-thinking environmentalists who love the planet, on one hand, and greedy energy companies who want to plunder the planet, on the other. While this may be a convenient bias for news articles and political debates, it bears little resemblance to reality. As an oil and gas attorney in Texas, I work directly with the oil and gas industry. As a result, it's clear to me that the false dichotomy between those who care about the environment and those in the energy industry is exactly that: false. The truth is that many energy companies involved in obtaining, refining, and selling oil and gas are also environmentalists who work hard to preserve the planet.

For example, oil and gas companies are much better environmental stewards than they are given credit for. Consider a new report from the American Petroleum Institute analyzing investments in greenhouse gas technologies in North America over the last year. This report notes that there was roughly $225 billion spent in on greenhouse gas (GHG) mitigation in 2010. Of that total, U.S. based oil and natural gas companies contributed nearly half: $108 billion. That amount includes about $37 billion in shale gas development technologies and $71 billion in other investments. About $60.5 billion of the industry’s investment went toward oil and gas substitutions—including the shale gas investments. The shale gas advances are included in the data because its use can reduce the use of coal, which can significantly curb methane releases.

Compare these energy industry investments with about $74 billion in total federal government spending (most in projects funded by the “stimulus” package) for GHG mitigation. Private entities (other than energy companies) combined invested roughly $43 billion during that same time period. Most federal spending went toward energy efficient lighting, biofuels, solar power, and wind. The other private investments included efforts in advanced technology vehicles, electricity efficiency, biofuels, and wind power.

The API study was produced by T2 and Associates and is entitled "Key Investments in Greenhouse Gas Mitigation Technologies from 2000 Through 2010 by Energy Firms, Other Industry, and the Federal Government". It was created by analyzing 565 different public documents and databases on the topic, including corporate reports, federal budgets, and other sources.

These figures present a much different picture than that painted by some environmentalists, i.e., of an industry dragging its feet to prevent GHG mitigation efforts. Let us not forget that these large investments were made in the face of a significant and persistent recession. When businesses of every stripe were laying off workers, cutting services, and eliminating all non-essential efforts, the oil and gas industry continued to preserve jobs, produce jobs, and invest in GHG mitigation. In addition, these investments were made despite the significant questions about the psuedo-science that serves as the basis for claims of climate change due to alleged manmade greenhouse gas emissions.

Of course, all of these efforts received little to no attention in the national media. Instead, virtually all public or political mentions of the energy industry continue to be the usual attacks based on skewed or flat-out incorrect assertions about the work of these companies. One can only hope that more fair-minded Americans will become aware of the true story of the oil and gas industry’s efforts like these latest GHG mitigation investment figures. It is when we base our decisions on correct information, rather than psuedo-science, that we can properly balance energy production and environmental preservation.

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December 10, 2011

Mineral Deeds Can Be Complex!

Property transfers involving mineral rights can be complex. As a Texas oil and gas attorney, I help my clients navigate these difficult legal issues. Mineral rights and potential royalties from those minerals can have a significant impact on the value of a property. Therefore, whether you are buying or selling property, it is critical that the deed and other documents accurately address the mineral rights.

One especially tricky, but not uncommon, scenario, was the subject of a recent article in Tierra Grande, a publication from Texas A & M’s Real Estate Center. This situation involves a transfer in which the original sales agreement or earnest money contract reserves the mineral rights to the seller, but the reservation of mineral rights is not stated in the actual deed delivered to the buyer at closing.

Sometimes both parties admit the error and correct it in a non-contentious fashion by executing a correction deed. However, when a friendly solution does not materialize, there are several key legal issues of law that determine whether the deed can be reformed to match the sales contract and include the mineral reservation.

The first legal principle is the statute of frauds, which in Texas is contained in Section 26.01 of the Texas Business and Commerce Code and Section 5.021 of the Texas Property Code. The Texas statute of frauds provides that all terms of a real estate sale must be in writing and signed by both parties to be enforceable. The second legal principle is the merger doctrine, which provides that the deed is the final expression of the parties' agreement and supersedes all prior written or oral agreements, including the sales contract or the earnest money contract. The third legal principle that often applies is the statute of limitations, which, according to Texas Civil Practices and Remedies Code Section 16.051, is four years from the date of delivery of the deed to the buyer. Texas recognizes an exception to the statute of limitations, however, called the "discovery rule". In other words, the seller has four years from the time the seller discovered or reasonably should have discovered the mistake in the deed within which to file suit for reformation of the deed This date may be a later date than four years subsequent to the delivery of the deed.

If the statute of limitations has expired, even with the application of the discovery rule, then the seller's remedies have expired and that's the end of the story. If the statute of limitations has not expired, then we consider the merger doctrine. Generally, the merger rule dictates that the deed is the parties' final agreement. However, an exception to the merger doctrine can be based on a mistake, accident, or fraud in the deed. The concept of mistake is especially interesting in this context. In general, it has to have been a mutual mistake, that is, both parties must have intended to agree to something that did not end up in the deed. A Texas court in Gail v. Berry earlier this year ruled that, if the buyer notices the mistake in the deed at the time the buyer signed it, this will be considered to be a mutual mistake, even though this might appear to be a unilateral mistake by the seller. In the Gail case, the seller was allowed to reform the deed to reflect the mineral rights reservation.

The next question a Texas oil and gas attorney often encounters is what happens when the buyer has signed an oil and gas lease before the deed is reformed? In most cases, if the lessee/oil and gas company did not know about the mistake and could not have reasonably discovered the mistake, it is considered to be a bona fide purchaser, i.e., an innocent party. As a result, the oil and gas lease will be allowed to stand.

There is, of course, a lesson to all this. Have an experienced attorney handle mineral and real estate transactions. The small amount of money you may save by foregoing competent representation could cost you dearly in the long run.

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December 6, 2011

The Myth of the "Oil Peak"

I'll bet that most Texas oil and gas attorneys (and, I'm sure, everyone in the oil and gas business) often hear the myth repeated that someday there will be a peak in oil production, followed by a rapid decline which will cause the collapse of human civilization as we know it. This myth predicts that someday, possibly someday soon, (although that date keeps getting pushed back when it turns out to be wrong) the world will simply run out of oil. Please understand this myth for what it is—unnecessary fear mongering by those with either a political purpose or who are ignorant of the oil production process.

Daniel Yergin , an expert energy researcher and the Pulitzer Prize winning author of "The Prize", excerpts from his new book, "The Quest: Energy, Security and the Remaking of the Modern World", in a recent Wall Street Journal interview. He describes the ways in which the purveyors of this “oil peak” myth are systematically wrong. For example, the myth drastically oversimplifies the complex nature of oil production. It is based on the concept that the world has X amount of oil, and when we use X amount, there will be none left. While in an absolute sense that may be true, oil production is not nearly as simple as that. This country has a long history of feverish predictions that we are running out of oil, going back as far as the 1880s. The actual prospect of running out of oil remains as distant today as it did then.

From 2007 to 2009, for every barrel of oil produced in the world, 1.6 barrels of new reserves were found. In addition, energy technology, including green energy, has advanced to the point where we use oil in a much more efficient way than in the past. As a result, each barrel of oil goes further. But the “oil peak” myth still holds our collective national attention for some reason. Mr. Yergin attributes this in large part to a man by the name of Marion King Hubbert, who studied geology in the first half of the 20th century. The "oil peak" is often referred to as “Hubbert’s Peak.” In 1956, Hubbert theorized that oil production would peak between 1965 and 1970. When production did decline after 1970 and the oil embargo rocked America soon after, his theory seemed vindicated. He also claimed that the generation of children born in 1965 would see oil reserves wiped out in their lifetimes. But what Mr. Hubbert did not count on was the huge increase in newly discovered oil and gas reserves found and produced in the U.S. By 2010, US oil production was three and a half times higher than Mr. Hubbert predicted it would be.

Hubbert apparently did not have a good grasp of economics and technological change, and this hampered his ability to understand the future of oil. Both economics and technological change are critical to understanding how the oil industry works and changes over time. Economics drives production through the forces of supply and demand, but Mr. Hubbert, oddly enough, insisted that oil prices didn’t matter. He was mistaken, of course. High oil prices motivate oil companies to find new reserves and to develop new technology to produce known reserves. Technological innovation has increased dramatically in the oil industry in the last decades, resulting in discovery of new reserves and production of known reserves previously believed to be inaccessible.

Oil production in the US has increased 10% since 2008, assisted by discoveries like the Bakken oil fields in North Dakota (see our previous post). Mr. Yergin suggests that instead of thinking of a peak, it is more accurate to think of oil production as a plateau, which is leveling off because of increased energy efficiency and new technology.

Yergin brings substantial background and insight to both his first book, "The Prize" and now to this new work, "The Quest". The are both recommended reading for anyone interested in the history and the future of oil.

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November 30, 2011

IHS CERA Study Finds That EPA Grossly Overestimates the Amount of Methane Emissions from Shale Gas Wells

The EPA has once again overestimated the amount of pollution that comes from an oil and gas source -- with potentially grave consequences for the industry. This time, the EPA has overestimated the amount of methane gas that comes from shale gas wells. A new report from the IHS Cambridge Energy Research Associates has found that the EPA’s estimates were based on too small a sample of wells, and on a method that did not conform to industry practices.

Because methane is highly flammable, those who drill new shale gas wells make every effort to minimize the emissions. This includes several methods for capturing and relieving gas, such as installing a blowout preventer at the surface.


The report found that rather than base its methane emissions estimates on gas that escaped to the surface, the EPA based them on what was captured. The report noted that if methane emissions were really as high as the EPA supposed, there would be extremely hazardous conditions at the well site. It would be be “unwise” for the EPA to use its methane estimates for the basis of new policy. Furthermore, EPA proposals for more regulation of hydraulically fractured gas wells are already part of industry standards.

How did this come about? The EPA based its 2010 revised estimates on too small a sample -- specifically, two workshop presentations based on just four projects in Wyoming, New Mexico, Texas, and Oklahoma. The presentations described the amounts of methane captured during “green completions” of natural gas wells. Green completions are meant to capture as much methane as possible before it reaches the surface while the well is completed. Therefore, it seems absurd to use it as a basis for estimating methane gas emissions. Yet for some reason, the EPA assumed that the wells that captured this amount methane were an exception, and that every other well must release the methane into the atmosphere because their states do not specifically regulate gas emission. In fact, IHS CERA director Surya Rajan stated that it is “common industry practice… to capture gas for sale as soon as it is technically feasible.”

Rajan further noted that gas that can’t be sold “is flared rather than vented for safety reasons.” The EPA’s estimates assume that the gas is never flared -- that it is simply released. IHS CERA did a revised calculation that took into account that gas well drillers were professionals who knew what they were doing. It found that only 18% of methane gas produced in 2010 came from new wells. Even if the methane gas produced during the 10-day flowback (completion) procedure were vented from every well, it still would produce two-thirds less than EPA estimate.

This is all too common: federal regulators get involved in a situation that they know too little about and threaten to make it worse under the guise of “improvement.” For instance, the EPA ignores the fact that states can and do regulate emissions without their help: Texas has passed new regulations for monitoring emissions this past year. If the EPA does not respond to industry concerns, we could be looking at new regulations that not only don’t address any real problems, but make daily operations more difficult for gas well drillers. That means more unnecessary delays, money wasted and higher prices for gas. As a Texas oil and gas attorney, I find this extremely troubling.

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November 25, 2011

Self-Serving Political Posturing Prevents Real Energy Independence

As is no doubt true of most Texas oil and gas attorneys, I’m always interested in reading about new developments in the oil and gas industry, although they often seem to attract more than their share of political wrangling. Of course, energy independence is a hot-button issue these days (see our recent post on the topic). Unfortunately, political posturing often gets in the way of common sense solutions to this pressing problem.

I was reminded of how politics is the enemy of practicality when I read an interview with Harold Hamm, CEO of Continental Resources in the Wall Street Journal recently. Continental Resources is the 14th largest oil company in the United States. Mr. Hamm is the man who discovered the Bakken oil fields in Montana and North Dakota, which he claims holds 24 billion barrels of oil, and that has already helped make America the world’s third largest oil producer. Mr. Hamm believes that energy independence is within our grasp.

New technological advances are helping the industry grow by leaps and bounds. Horizontal drilling allows economical access to oil reserves that would not have been possible in the past. It has done for oil production what fracing has done for natural gas. Mr. Hamm believes that America’s oil production and reserves will triple in the next five years, which will have a broad impact on the economy. There are 10 million royalty owners today who are earning money from the oil located beneath their land. These royalty owners are not the millionaire Wall Street investors that Obama is so fond of bashing, these are just folks, like you and me, using those royalties to pay help pay bills and to save for retirement.

But instead of investing and promoting the resurgence of this industry, which could create an untold number of good, well-paying American jobs, politics has once again interfered. Obama instead chooses to spend billions of taxpayer dollars on subsidies to companies touting green energy, which supplies only 2.5% of America’s energy needs. These types of energy sources may be useful in the future, but they are not feasible alternatives in the short term. In fact, for a number of reasons, these sources will never provide more than a few percent of our energy needs, no matter how much they are subsidized. Notwithstanding the facts, the Department of Interior continues to delay drilling permits month after month, preventing energy production to meet our needs today, preventing the creation of American jobs, and preventing payment of huge royalties to local, state and the federal government that would help with the current debt crisis.

Please don't tell me that we need to subsidize these "green industries" to prevent pollution. Oil and gas companies spend billions of dollars every year to insure their operations do not polute and do not harm the environment. Those who say otherwise are, frankly, uninformed.

What is even more incredible than the misplaced subsidies is the length to which federal agencies go in harassing oil and gas companies. For example, the Justice Department has brought charges against Continental and six other oil companies for violating the Migratory Bird Act . The maximum penalty for each charge under this Act is six months in prison and a $15,000 fine. What was the heinous wrong that brought down the full force of the Justice Department on Mr. Hamm and his company? Well, a small bird, very common, and not an endangered species, was found dead in one of Continental’s oil pits in North Dakota. I love birds, and I believe that all life is sacred, but there is not even evidence that suggests the bird was killed by this pit.

This case seems even more far-fetched when one considers that some 440,000 birds die from the wind turbines every year, according to the American Bird Conservancy. So, you might ask, what is the Justice Department doing about this? Alas, wind energy is one of Obama's political pet-projects, and the investors and officers of a number of these companies are major Obama supporters. I can find no record of any prosecution based on this law against wind energy companies.

The way Obama rewards his supporters with our tax money, while punishing the industries and companies that create jobs, appears to be cynical, cold-blooded, Chicago-style thug politics at its worst. I only hope enough voters perceive the insanity of this behavior between now and election day.

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November 22, 2011

Oil and Gas Pipeline Easements and Texas’ New Eminent Domain Law

There is a new arrow in the quiver of Texas oil and gas attorneys who represent land and mineral owners! Specifically, there are significant changes to the Texas eminent domain statutes, which went into effect on September 1, 2011. Oil and gas companies can still acquire easements across private property to build pipelines. If the pipeline is a private pipeline, the pipeline company must obtain the voluntary agreement of the property owner. If the pipeline is going to be a common carrier, and the pipeline company and property owner cannot agree on easement terms, the company can commence condemnation, or "eminent domain" proceedings, in which panels of commissioners appointed by a court decide the easement terms.

Another portion of the statute allows landowners to construct roads over the pipeline, although the pipeline company may still impose restrictions on things like the size and road material.

The new law applies to condemnation lawsuits initiated on or after September 1, 2011. These changes strengthen a landowner’s right to defend against eminent domain from both the government and private companies. One of the landmark changes to the eminent domain law is a new “bona fide offer” requirement, which means the purchasing entity must give a written offer for the property 30 days before the final offer is made. Additionally, a certified appraisal of the property in question must accompany the final offer, and that final offer must be of equal or greater value than the appraisal figure. The landowner now has 14 days to respond to the final purchase offer. The new law also allows landowners to obtain relevant information concerning the proposed easements from the potential purchasers.

Prior to the effective date of these new legal requirements, the number of condemnation proceedings surged in those areas of Texas that are experiencing increased oil and gas production. This has especially been the case in South Texas because of the Eagle Ford shale, where natural gas production nearly quadrupled and oil production increased tenfold between 2009 and 2010. According to an article in the Wall Street Journal, at least 184 lawsuits against landowners had been filed already between January and August 2011 in just four South Texas counties, compared to only 24 lawsuits in all of 2010. A district court judge in Lavaca County indicated that the number of lawsuits filed this year is “highly extraordinary.” That county alone registered 62 such lawsuits by August, 2011, compared with only 18 in all of 2010.

These pipeline cases are important to everyone involved, so there is incentive to make the process equitable and fair for all parties. Texas oil and gas companies employ thousands of workers and contribute to a healthy and growing economy. The boom in oil and gas production has also brought prosperity to many areas of Texas. However, it is equally important to consider the rights of private landowners whose property is affected by the pipelines.

It may take time to determine the total impact of revisions to Texas eminent domain law. Hopefully, the original purpose of the law will be fulfilled: giving landowners more knowledge and influence in negotiations with pipeline companies. These companies are going to face more significant hurdles in exercising their eminent domain rights than in the past, especially when this new eminent domain law is combined with the recent Texas Supreme Court decision in Denbury (read our recent blog entry on this case here). The Denbury decision essentially affirmed that there must be a reasonable probability that the pipeline will serve the public before a pipeline company can use eminent domain.

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November 9, 2011

Texas Comptroller Targets Systemic Flaws of Federal Regulations

As a Texas oil and gas attorney, I have followed with great interest the tumultuous relationship that seems to perpetually exist between Texas and its landowners on one hand, and the United States Environmental Protection Agency (EPA) on the other. Unfortunately, some misguided policymakers are under the mistaken notion that the EPA is working to protect the environment, and that the efforts of Texas and other states to fight those federal regulations are misguided. That oversimplification could not be further from the truth.

As Texas Comptroller Susan Combs explained in a recent editorial published in the Star Telegram, Texans are committed to the well-being of their air, land, and water. If legitimate steps need to be taken to protect the long-term well-being of our resources, Texans have and will continue to be the first to step up and take action. Unfortunately, many of the EPA’s latest regulations and requirements passed in the name of environmental protection actually protect next to nothing, and have no scientific basis whatsoever, yet come with very significant detrimental consequences for Texas residents.

1369356_fall_tree_by_lake.jpg As Combs notes, “private landowners are the best stewards of their own property.” She goes on to say that the EPA continues to ignore the knowledge and reasonableness of our private property owners when making arbitrary decisions that have effects on their land and lives. Even more troubling, at times the Agency seems to specifically target Texas in ways that defy common sense and scientific reality. For example, Combs discussed the EPA’s new “cross-states” air pollution rule. The new regulation will disproportionately affects Texans. The measure targets nitrogen oxide and sulfur dioxide. Texas plants produce roughly eleven percent of the sulfur dioxide targeted by the regulation, yet, inexplicably, Texas is being ordered to absorb a quarter of the reductions—more than double its actual share.

Anyone who understands the energy industry in our state understands the significant impacts the regulation will have. The state’s largest power generator, Luminant, explained that the rule will eliminate 500 Texas jobs as two generating units are being idled and three ignite mine operations halted. In addition, the Electric Reliability Council of Texas reported that the rule may increase electricity rates for consumers, because the state’s generation capacity will be reduced in the peak load months of summer.

Considering the consequences of these regulations, particularly in light of the already tough economic circumstances, one would expect the regulations to be based on some scientific evidence and enacted only after input from those affected. Unfortunately, neither is true. As the Texas Commission on Environmental Quality explained, the EPA’s own forecasting models did not reveal that these emissions had any significant impact on other states. On top of that, Texas wasn’t even included in the new requirements until the final version of the rule was adopted, meaning that no one from the state had the opportunity to provide comment or feedback on the regulations while they were being discussed.

Other examples of EPA overreach abound. Proposed EPA jurisdiction expansions may allow the agency to control isolated wetlands, streams, and other purely local pools of water such as stock tanks. The EPA has not produced a single scientific reason why the expansion is necessary. Yet, the action would place many Texas construction projects in jeopardy. The uncertainty, time delays, and other permitting challenges foisted upon residents by federal bureaucracies will have ramifications throughout the state.

As a Texas oil and gas attorney who works with landowners on a variety of issues, I am well aware of the systemic problems unnecessarily faced by local residents because of misguided EPA conduct. As Comptroller Combs explains in her editorial, it is important for all Texans to remain aware of these developments and to make their voices heard on a national level.

See Our Related Blog Posts:

EPA Proposal to Extend Its Regulatory Authority May Adversely Affect Texas Ranchers

Additional Offshore Workplace Safety Regulations Proposed by DOI & BOEMRE

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October 29, 2011

Texas Mineral Owners: Don't Waste Your Potential Royalties

When a Texas mineral owner asks me to review or negotiate an oil and gas lease offer they have received, one of the first things I do is to determine who the proposed operator, or lessee, will be. Many people do not realize how important it is to know just who you are leasing to. If you do not investigate the proposed lessee before you sign, you may be throwing away the royalties you could have received had you leased to a competent oil and gas company.

First, I determine whether the potential lessee is a licensed oil and gas operator. I strongly urge my clients not to sign a lease with a middleman. Instead, I insist that the actual oil company who will be operating the lease be disclosed so we can do a background check on them. There can be many potential problems if you sign a lease with a middleman. These include, (but are certainly not limited to), the following problems:

1148655_vintage_fountain_pen_3.jpg 1) The company who contacted you may be a broker or a “lease hound”, that is, a person or company who tries to sign up leases cheaply and then sell them to a real oil company for a huge markup. I prefer to see my client be paid that markup, rather than the middleman.

2) They may be an agent for a “boiler-room” operation, who make their money by selling interests in a lease or “drilling program” as an investment. They make their money on the sale of these interests, and could care less about drilling a good well, or treating your minerals or the surface of the property competently. In some cases, they don't care if a well is drilled or not, because they have already made their money.

3) You can end up with the drilling being done by an inexperienced or even unscrupulous operator, who can destroy the surface of your land, leave toxic chemicals, and either refuse to clean up, or go out of business or file bankruptcy to avoid the cost of cleanup.

4) An inexperienced or unscrupulous operator can do an inept job of developing your minerals, damage the reservoir and possibly leave the minerals unrecoverable. In either case, this type of operator can either go out of business or file bankruptcy to avoid the payment of damages.

5) Many reputable oil and gas operators refuse to buy leases from these middlemen. Instead, they wait until the initial term of the lease has expired, and then contact the mineral owner to lease from them directly. An oil and gas lease is almost always “exclusive”, that is, you are prohibited from leasing to anyone else during the initial, or primary, term. Thus, while your minerals are tied up in a lease to a middleman, you may miss out on a good lease with a competent oil and gas company, and lose the royalties you would have been paid during this time. It’s also possible that you will miss your window of opportunity more permanently: by the time your initial term is up, a competent operator may have leased what they need in surrounding areas, and not be interested in leasing from you any longer.

Once we determine who the actual lessee will be, if the proposed lessee is not well known, I strongly recommend that I do a background check on the proposed lessee. While there are many good oil companies and well operators, there are a number that you do not want to lease to for any price. As I indicated above, allowing an inexperienced or unscrupulous operator to drill on your land can result in serious financial consequences for you. A background check is not a guarantee that these things will not occur, but it gives us some idea of whether the operator is legitimately incorporated, how long they have been in business, how many other wells they operate and where, and whether there are or have been any lawsuits or regulatory proceedings against them.

Way too many mineral owners do not investigate who the proposed lessee will be. When they contact me, after the damage is done, it is usually too late.

These lease hounds and brokers and middlemen come out of the woodwork when the price of oil goes up. Please don't waste your mineral assets and the potential royalties those assets can produce for you by leasing to someone without checking them out first! In addition, please be patient. In an area of the state where the brokers and lease hounds are busy, the competent oil companies often follow!

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October 25, 2011

Texas Supreme Court Decision Impacts Texas Oil and Gas Pipeline Negotiations

I spend a significant amount of time as a Texas oil and gas attorney assisting landowners with negotiation of easements and rights-of-way for oil or gas pipelines. As my client and I work through the negotiation process, it is vital to understand the various options available to the pipeline company if we are unable to reach an agreement. While we always try to reach a fair agreement, knowing what the other party can do if a deal is not reached is a key part of crafting an appropriate strategy so that you, as a landowner, can get the most value out of the agreement. Earlier this year, the Texas Supreme Court handed down a landmark decision which may affect the options available to pipeline companies when they negotiate with landowners. The case, Texas Rice Land Partners, Ltd. and Mike Latta v. Denbury Green Pipeline-Texas, addressed issues regarding when a pipeline company is a common carrier and therefore, when the eminent domain power is available to pipeline companies.


The Texas Natural Resources Code allows “common carrier” pipelines to wield the eminent domain power only if they are going to transport gas “to or for the public for hire.” Of course, this statute reflects the constitutional requirement that property cannot be taken from an owner if it will be used merely for private purposes. In Denbury, the Texas Supreme Court provided further clarification on what a pipeline must do to qualify as a common carrier so that they can utilize the eminent domain power. In the past, it was assumed by most involved parties, including Texas oil and gas attorneys, that the issuance of a common carrier permit by the Texas Railroad Commission was sufficient to satisfy the requirement. In other words, if a pipeline company received the permit, then they could utilize the eminent domain power if they could not negotiate a right of way with the landowner. The Denbury case changes that.

In this case, Denbury Green received a T-4 permit from the Texas Railroad Commission to construct and operate a CO2 pipeline at the Texas-Louisiana boarder and extending to the Hastings Field in Brazoria and Galveston counties. As part of the permit application, the company checked a box which indicated that the pipeline would be used as a common carrier, instead of as a private line. After receiving the permit, Denbury Green visited part of the proposed location where the pipeline would be put. However, the owners of the land in question, Texas Rice Land Partners, refused to give the company access. Denbury Green and the Texas Rice Land Partners had previously negotiated on the company’s use of the land, but they had not reached agreement. Denbury Green sued to have access to the site to survey in preparation for condemning the pipeline easement.

The case eventually made its way up to the Texas Supreme Court. Denbury Green argued that it should be deemed a common carrier with the power of eminent domain because the permit issued by the Railroad Commissions deemed it as such. However, the Supreme Court rejected that argument. They noted that “the T-4 permit alone did not conclusively establish Denbury Green’s status as a common carrier and confer the power of eminent domain.” Instead, the Court stated that whether or not a pipeline company is deemed a common-carrier is a judicial question. The Railroad Commission’s granting of a permit is an administrative tool based upon the self-reporting of the company involved. Such a process is not subject to the adversarial testing present in the judiciary to determine if the company will actually use the pipeline for public purposes.

The Court reiterated that the extraordinary power of eminent domain cannot be taken lightly. It explained that landowners cannot be subject to a forcible taking of their private land “with such nonchalance via an irrefutable presumption created by checking a certain box on a one-page government form. Our Constitution demands far more.” The Court went on to declare that a pipeline company must do more to conclusively establish itself as a common carrier. Not only is the permit insufficient, but merely making the pipeline available for public use is also insufficient. In many cases, a pipeline will never actually serve a purpose for anyone other than the company building it. Therefore, mere claims that it could be used by others cannot be a loophole to get around the constitutional requirement that eminent domain power not be available for mere private purposes.

This decision may have significant effects on all future negotiations where a common carrier permit is involved or the use of eminent domain power is threatened. While the permit’s indication of common-carrier status will remain prima facie valid, a landowner may now challenge that status. At that point, the burden shifts to the pipeline company to prove that there is a reasonable probability that the pipeline will actually serve the public and not that it may serve the public “in theory.” Many more pipeline companies will need to negotiate with landowners much more, shall we say, earnestly, now that their ability to forcibly take an easement or right-of-way via eminent domain may be limited.

See Our Related Blog Posts:

Talk to an Oil and Gas Attorney Before You Sign That Lease

Have a Texas Oil and Gas Attorney Review Your Pipeline Easement

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October 17, 2011

Texas Supreme Court Sheds Light on Duty of Owner of Oil and Gas Leasing Rights

It is incumbent upon a Texas oil and gas lawyer to keep abreast of all relevant decisions from appellate courts and the state’s highest court. Proper advocacy demands that attorneys understand changes in the law and be able to incorporate those changes in their legal representation. Lawyers must have an awareness of all the legal tools at their disposal so they can provide zealous advocacy and competent representation for a client, whether in a dispute, guiding a landowner through the negotiation process for a lease, preparing a mineral deed or a number of other tasks.

There remain many areas of Texas oil and gas law with questions that are unanswered, and our courts are frequently providing guidance on those issues. For example, the Texas Supreme Court recently handed down a decision in Lesley v. Texas Veterans Land Board that provided further clarification on the rights and responsibilities that executive rights holders owe to mineral owners.

A mineral estate is basically a bundle of various property rights. One of those rights is known as the “executive right”, which is the ability to enter into an oil and gas lease. This is distinct from other rights of mineral ownership, such as the right to collect royalties, bonus or delay rentals pursuant to an oil and gas lease. More often than not a single owner will possess all of these rights, meaning they can choose to lease and will receive payment for royalties due under that lease. However, these rights can be split between one or more persons or entities. When those rights are split, the holder of the executive right owes a duty of “utmost fair dealing” to other owners of a mineral interest.

In the Lesley decision, the Texas Supreme Court elaborated on what that duty actually encompasses. 1004076_the_american_dream.jpg The case involved a mineral estate that had been split between several parties with each owning part of the mineral estate but only one having the executive right. In other words, several parties would receive royalties upon the lease of the minerals, but only one party had the power to actually negotiate and sign the lease. The executive right holder was a land developer who had turned the property involved into a subdivision of over 1,200 lots. When those lots were sold to others, the deeds included restrictive covenants which prohibited “commercial oil drilling, oil development operations, oil refining, quarrying or mining operations.” Evidence was presented in the case which suggested that the subdivision was sitting on $610 million worth of minerals that cannot be reached from outside the subdivision. The non-executive interest holders sued the executive interest holder because the restrictive covenants essentially made it impossible for the land to be leased and for mineral owners to develop their minerals and receive royalties.

The original plaintiffs argued that the use of restrictive covenants amounted to a breach of the duty they were owed by the executive interest holder. Put more succinctly, the Court was presented with the question of whether inaction by the executive interest holder was a breach of any duty to the mineral owners. In answering this question, the Court did not provide a general rule, but instead explained that under certain circumstances, the failure to lease would constitute a breach of the executive holder’s duty of utmost fair dealing to the mineral owners. In this case, the Court ruled that the restrictive covenants included in each deed when a person bought land in the subdivision were unnecessarily restrictive, because they essentially prohibited all future leases. In the Court's view, this was a step too far that unfairly harmed non-executive mineral rights owners.

The Court did not go so far as to declare that all inaction on the part of the executive rights holders amounted to a breach of duty, just that the restrictive covenants in this case went too far. This is an interesting decision in another sense, for this reason: the buyers of land in the subdivision were given a copy of the restrictive covenants before they bought their land, as is required by law. However, the deeds from the developer to each buyer did not contain a reservation of the executive rights! Since a grant of minerals ordinarily conveys all the rights in the mineral estate, the failure of the developer to reserve the executive rights, in writing, in the deed to each buyer, was a big reason why the buyers won.

The Lesley decision may be important to you if you own minerals, but not the right to lease them.

Why You Should Have a Texas Oil and Gas Attorney Review Your Oil and Gas LeaseOil and Gas

Leasing in the Eagle Ford Shale in Texas

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October 13, 2011

Several Panels to Study Effects of Fracing

Practicing oil and gas law in Texas competently also requires being aware of the "bigger picture" in which I work. One component of that bigger picture these days is the issue of energy independence.

Energy independence has become a major political issue in recent years, and has resulted in increased efforts to find ways to reduce the United States’ dependence on importing foreign oil to meet our nation’s energy needs. Renewable energy sources and nuclear solutions have been discussed as alternatives to importing oil, but our country’s natural gas reserves are also an important part of our national energy policy moving forward. Ancillary to this national discussion, the production of natural gas, and in particular, the practice of hydraulic fracturing, or fracing, has come under attack.

105313_oil_drilling_rig.jpgNatural gas is often contained within dense shale formations underground, and fracing is a process used to extract those reserves of natural gas. The process itself involves the use of water combined with sand and chemicals and pumped into the shale formations to fracture them and allow the release of the gas held in the rock.

To my knowledge (and I research this issue), there has never been a documented case of the fracing process injuring a water well. Those who suggest otherwise (such as the producers of "Gasland") are not being honest with the public or themselves. I wrote a previous article on this blog outlining the reasons for my statement.

Notwithstanding the lack of evidence of injury to water wells, there has been so much hysteria generated by this issue, that in depth studies by experts are welcome.

The New York Times reports that U.S. Secretary of Energy Steven Chu has appointed a panel of seven individuals to perform the study. John Deutch is the chairman of the panel, and is a professor and dean of science at the Massachusetts Institution of Technology. He was the undersecretary of Energy in the Carter administration and the deputy secretary of defense and director of the Central Intelligence Agency during the Clinton administration. He is also a member of the board of directors at Raytheon and Cheniere Energy. Deutch is tasked with finding ways to improve the safety of fracing and providing advice to state and federal agencies that will enable them to safeguard citizens’ health. Given the lack of industry experience of Mr. Deutch, one wonders if the results of this particular study will be accurate, or merely political fodder.

On the other hand, the Houston Chronicle reports that the University of Texas will also be studying the effects of fracing and the effectiveness of current regulations at making fracing a safe process. Chip Groat, the current dean of the Jackson School of Geosciences at the University of Texas is leading this study. Dr. Groat was the head of the United States Geological Society during the Clinton and Bush administrations, and will bring his expertise in understanding complex natural water systems to bear on the issue of hydraulic fracturing.

Finally, the Environmental Protection Agency has also been tasked with studying the effects of fracing on public and environmental health, and formed a panel of 22 people to provide advice and recommendations on the study plan. Dr. David A. Dzombak, a Senior Professor of Environmental Engineering at Carnegie Mellon University in Pennsylvania was named as the chairman of the panel. He is the faculty director of the Steinbrenner Institute for Environmental Education and Research, and has served on the EPA’s Science Advisory board for four years. His expertise is in aquatic chemistry, the transport of chemicals in water, soil, and sediment, and the restoration of watersheds and rivers.

Hopefully, given the range of relevant experience and knowledge of at least some of the people involved with these studies, if there are real problems with fracing, they can be identified, and the hysteria regarding fracing can be put to rest.

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September 27, 2011

Additional Offshore Workplace Safety Regulations Proposed by DOI & BOEMRE

An experienced oil and gas lawyer understands how politics influences the rules and regulations placed upon those working in the energy industry. Unfortunately, that political influence means that decisions about how the industry is regulated are often not guided by common sense, logic, and fair-minded decision-making. Instead, oil and gas regulations are frequently spurred by knee-jerk, reactionary administrators who are more concerned with appeasing loud public voices than making choices that are necessary and reasonable in light of all the information.

One is hard pressed to turn on a television news channel or flip open a newspaper without hearing or reading some story vilifying oil and gas companies and calling for new measures to control their activities. A cruel caricature is often painted of those who work in the energy industry which ignores the fact that these individuals are regular citizens working each day in a business that remains vital to national productivity. The unflattering and inaccurate public portrayal of the industry often causes appointed bureaucrats to impose new regulation after new regulation on these businesses. To make matter worse, those making these regulatory decisions are rarely knowledgeable about the day-to-day activities of those working in this field, and they usually ignore the effect that their arbitrary rules have on the business.

464816_oil_rig.jpg For example, the US Department of Interior (DOI) and Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) announced a spate of new workplace regulations recently for all offshore oil and gas producers. As reported last week in the Oil and Gas Journal, these new regulations will require certain actions be performed on these rigs in an apparent effort to improve workplace safety. These include guidelines for reporting unsafe work conditions, stop-work action procedures, safety audit requirements, and a variety of other mandates. While everyone can agree that safety should always be prioritized, heaping new requirements on the industry is rarely the best way to achieve that goal.

If history is any indication, these new rules from federal regulators will likely do little to address the actual safety goals and instead only stifle each company’s ability to respond on its own to the unique safety challenges that it faces on the ground. As those working in the field of oil and gas law know, when push comes to shove it almost always makes more sense for those actually working in these environments to decide the ideal safety protocols instead of regulations being handed down on high from those walking the halls in Washington D.C.

When announcing the new regulations, BOEMRE Director Michael R. Bromwich also took the time to attack those who have asked questions about the bureau’s slow-walking of permits. He cited the total number of overtime hours worked by employees in his office as proof that the agency was working as quickly as possible to evaluate plans. Of course, the fact that employees are logging a certain number of hours in no way exonerates the bureau from serious concerns that it is unfairly managing the application process. There remain persistent criticisms by legitimate sources that BOEMRE is sitting on permits.

After decades of experience as a Texas oil and gas lawyer helping owners and lessors on a variety of issues, I have come to appreciate the hard work conducted day in and day out by those running these industries. It is disappointing to learn of new regulations that are continually thrown upon these businesses, and are usually drafted by those who have little understanding of how the industry actually operates. In the end, these regulations are likely to do more harm than good.

See Our Related Blog Posts:

A Texas Oil and Gas Attorney Reviews Proposed New Onshore Drilling Regulations

Texas Oil and Gas Operator Obtained Deepwater Drilling Permit After Federal Drilling Moratorium

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September 26, 2011

The Oil and Gas Depletion Allowances and the Effect of Obama's Proposed Cancellation of Percentage Depletion Allowance

43011_oil_drilling_rig_4.jpg Texas oil and gas attorneys are watching with trepidation as Obama seeks to cripple domestic mineral production with his ill-conceived policies. In our previous post, we discussed the Obama administration's push to eliminate some of the tax subsidies that oil and gas producers in the United States currently enjoy. One of the subsidies that will be cut -- if the President's Fiscal Year 2012 Budget is approved -- is percentage depletion for oil and gas wells, or the "oil depletion allowance" as Speaker Boehner recently called it. According to an article on Texas Insider, the Office of Management and Budget (OMB) estimates that repealing percentage depletion would generate 607 million dollars in 2012, and 11.2 billion dollars over the next decade, in additional tax revenue. While that extra income would surely help the federal government's bottom line, it is not a smart policy due to the adverse affects it will have on oil and gas exploration and ultimately, retail gas prices. Before we can address these potential effects, however, it is helpful to have an understanding of what the "oil depletion allowance" is.

Depletion allowances let the owner of an asset account for the portion of that product as it is used up. Depletion allowances are similar to depreciation in that they provide cost recovery for capital investments -- it is a tax structure to ensure that the financial burden of using resources is not borne by businesses in a lump sum. There are two types of depletion allowances available to oil and gas producers: cost depletion and percentage depletion. Cost depletion allows a taxpayer to recover the actual capital investment through the period of income production of the oil and/or gas reserves, and the cumulative amount recovered through cost depletion cannot exceed the taxpayer's original capital investment. The other form of depletion is percentage depletion, which allows oil and gas producers and mineral rights owners to recover a portion of the mineral that is used up, or depleted, at a rate of fifteen percent of the average daily gross income from their operation each year. Unlike cost depletion, cumulative depletion deductions under the percentage model can be greater than the original capital investment made to exploit those resources.

The White House's 2012 budget seeks to eliminate percentage depletion for oil and gas wells, leaving only cost depletion as a means for recovering such capital investment costs for the domestic independent oil and gas industry. The effects of such a change would be substantial. According to the Independent Petroleum Association of America (IPAA), removing percentage depletion as an option for small oil producers would force these companies to reduce their drilling budgets anywhere from twenty to thirty-five percent. The IPAA goes on to say that the independent oil industry accounts for almost four million jobs in the United States, and that the elimination of percentage depletion will increase taxes and result in fewer employment opportunities for Americans. Furthermore, the IPAA asserts that the elimination of percentage depletion will increase our nation's dependence on foreign oil and result in less governmental revenue going forward.

This is yet another example of short-sightedness on the part of the current administration. Yes, eliminating percentage depletion might raise additional revenue in the short run, but at the cost of American jobs and independence from foreign oil, two things that are in short supply these days. It is likewise disheartening to hear Obama decry the depletion allowance as some kind of tax break that only benefits "big oil" (whoever that is), when the largest portion of our domestic oil and gas production comes from small, independent companies.

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August 16, 2011

Texas Oil and Gas Operator Obtains Deepwater Drilling Permit After Federal Drilling Moratorium – Part II

Texas oil and gas attorneys are watching the recent series of drilling moratoriums by the federal government with great interest. In a recent blog post, I discussed the legal background behind the first deepwater drilling moratorium and the litigation that followed.


Because a federal judge ruled that the first deepwater drilling moratorium should be set aside as “arbitrary and capricious” under the Administrative Procedure Act ("APA"), the U S Department of the Interior ("DOI") was left with a choice: either lift the deepwater drilling moratorium completely, or try to instate a new moratorium that might pass APA muster.

In an unsurprising move, the DOI issued a second deepwater drilling moratorium. The second moratorium banned exactly the same activities as the first moratorium, although it used slightly different grounds to do so. While the first moratorium banned activities occurring at depths greater than 500 feet, the second moratorium restrained all rigs that use subsea blowout preventers or surface blowout preventers on a floating facility. In reality, the second moratorium restrained precisely the same rigs as the first moratorium. The DOI defended their second attempt by explaining that, although the second moratorium was similar in effect to the first moratorium, the second moratorium did address the technical concerns highlighted in the District Court's first order.

In November 2010, the DOI lifted the second moratorium. However, despite the fact that the moratorium was lifted, the DOI was slow to issue new permits for activities covered by the two moratoriums.

In light of what the Louisiana District Court deemed “purposeful defiance” of its ruling, the Court held that the DOI was in "contempt of court." In its contempt ruling, the District Court noted that “each step the government took following the Court's imposition of a preliminary injunction showcases its defiance.” In light of what the District Court viewed as “dismissive conduct,” Judge Feldman held that the plaintiffs had demonstrated the government's contempt by clear and convincing evidence. Judge Feldman's contempt order was dated February 2, 2011. Later that month, the DOI started issuing the first deepwater drilling permits since the BP disaster.

Many in the oil and gas industry are still unhappy. They note that the only projects being permitted right now are those that were already given the green light before the BP oil disaster.

This saga is sure to continue in the coming weeks and months, although slowly, more and more drilling permits are being granted. For example, Texas-based Exxon Mobile recently became the fourth company cleared for drilling.

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August 6, 2011

Texas Oil and Gas Operator Obtains Deepwater Drilling Permit After Federal Drilling Moratorium – Part I

747363_texas_detail.jpgAs a Texas oil and gas attorney, I have followed with great interest the actions of the US Department of Interior (DOI) to finally lift the post-BP Oil Spill moratorium on deepwater drilling. It has been a long and legally complex road, but finally the DOI has taken the initial steps necessary to end the moratorium and re-start deepwater drilling in the Gulf of Mexico. So far, three deepwater drilling projects have been approved. A project sponsored by a Texas corporation, ATP Oil & Gas, was one of the lucky three.

In my next two blog posts, I'll discuss the legal background behind the two deepwater drilling moratoriums issued by the Obama administration, the litigation challenging those moratoriums, and the current state of deepwater drilling operations.

Immediately after the BP oil spill disaster, the DOI issued a “Moratorium Notice to Lessees and Operators,” which: 1) directed oil and gas lessees and operators to cease drilling new deepwater wells; 2) prohibited the spudding of any new deepwater wells; and 3) notified oil and gas lessees and operators that, with only a few exceptions, no new deepwater drilling permits would be issued for six months. The moratorium affected deepwater drilling operations occurring at depths greater than 500 feet, and operators whose wells fell under the moratorium were told to take the next safe opportunity to secure their wells, cease operations, and temporarily abandon their wells until they received further guidance from the DOI. It is interesting to note that, at this point, Salazar had no real proof of what had caused the problems with the BP well.

US Secretary of Interior, Ken Salazar, argued that the moratorium was justified in light of the recent environmental disaster in the Gulf, at least until a thorough safety review could be completed.

The DOI's drilling moratorium was challenged in the US District Court for the Eastern District of Louisiana by a group of plaintiffs who perform various services to support oil and gas drilling. The plaintiffs argued that the drilling moratorium did nothing to improve environmental safety in the Gulf of Mexico, and that the moratorium unfairly and hastily punished all deepwater drillers for the allegedly unsafe practices of one company.

Continue reading "Texas Oil and Gas Operator Obtains Deepwater Drilling Permit After Federal Drilling Moratorium – Part I" »

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July 30, 2011

President's Push for Removal of Oil Industry Tax Breaks Could Adversely Effect Small Domestic Oil Producers

As a Texas oil and gas attorney, I am keenly interested in the political climate in which the oil and gas industry operates. Politics has a lot to do with how much oil and gas this country produces. For example, in the White House's proposed Budget for the Department of Energy in fiscal year 2012, Barack Obama set forth a budget that "eliminates inefficient fossil fuel subsidies." The administration did so as a part of its ongoing plan to shift the nations energy policy toward investments in "clean energy sources" like photovoltaics and wind power generation. This issue is one that has gained even greater notoriety when Republican House Speaker John Boehner recently informed ABC News that he was open to eliminate one of these tax breaks -- the " oil depletion allowance" -- for large oil companies as a measure to help maintain the fiscal health of the government. He went on to state that he was open to evaluating the President's proposed subsidy cuts as well. In response, the President wrote a letter to Speaker Boehner and other Congressional leaders asking them to support the elimination of the oil and gas industry tax subsidies.

670680_oil_pumpjack.jpg In the aforementioned interview, Speaker Boehner stated that small and independant oil producers in the United States need the "oil depletion allowance." Representative Boehner went on to say that smaller oil firms need those subsidies to continue the current rate of exploration for new sources of petroleum reserves within U.S. borders. A later statement issued by his office stated that Boehner wishes to increase the amount of energy produced in the country to free the country from the market vagaries of oil sourced abroad, and that the President's proposed plan would boost gas prices higher. Should the budget be approved unamended by Congress, around 4 billion dollars worth of subsidies and tax breaks will disappear, and the ramifications of such a move could have an adverse effect on our recovering economy.

Boehner's statements to ABC illustrate the importance of evaluating all sides to this issue, and highlight the fact that the domestic oil industry is not solely comprised of billion dollar corporations. In fact, according to the Independent Petroleum Association of America (IPAA), small scale oil producers do the majority of oil exploration in the United States. Such organizations employ only twelve individuals on average, but they drill ninety-five percent of new oil wells, and produce two-thirds of our nation's domestic oil and natural gas. In our next post, we will examine the existing "oil depletion allowance," the proposed budget's tax subsidy cuts, and the effect such changes could have on independent oil producers in the US.

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June 30, 2011

"Alternative Energy"-A Question of Terminology?

As a Texas oil and gas attorney, I have authored a series of articles on this site concerning the pros and cons of alternative energy. As I prepared to return to the topic, I began to ponder a more general question. When we use the phrase “alternative energy” or “alternative fuels,” what exactly do we mean? Any lawyer will tell you that words have very precise meanings: when you are using a word, it is very important that you are clear what you mean when you use that word. Let us avoid the error of the Cheshire Cat in Alice in Wonderland, who made words mean anything he chose! Therefore, in writing about alternative energy, I have to ask two important questions: first, an alternative to what? And secondly, what alternative?

The dictionary defines alternative in one usage as “different from the usual or conventional.” So when we speak of alternative energy, we are talking about sources of energy different from the usual or conventional sources. But “usual or conventional sources” can mean different things.


Alternative energy is often spoken of in relation to oil. With every spike in the price of oil and the resulting rise in the price of gasoline, the usual cries are heard: we are too dependent on imported oil, our economy is too vulnerable to increases in energy costs as a result of that dependence, and for our own economic and national security we need to reduce that dependence. The natural choice, at least in the near future, would be to develop our own domestic sources of oil. That choice, however, has been to date choked off because of environmental concerns: exploration in the Alaskan National Wildlife Refuge was rejected by Congress, and the moratorium on new oil exploration in the Gulf imposed by the Obama administration after the Deepwater Horizon spill are the two most prominent examples of the roadblocks placed by environmentalists and their allies in Washington. So, it would seem that, for some, alternative energy does not mean using alternative sources for the current dominant energy source of oil.

In addition to developing new sources of oil, alternative energy can mean expanding the use of existing sources of energy. Three such sources are coal, natural gas, and nuclear power. Each has their advocates. Coal is still plentiful in the United States, and efforts are underway to develop clean coal technology designed to reduce emissions claimed to contribute to man-made global warming. Natural gas is also plentiful, given current estimates of reserves, and it is also the cleanest burning of the fossil fuels with almost no greenhouse gas emissions compared to coal or oil. Finally, in spite of safety concerns over the last several decades, nuclear energy has gained it's advocates as the energy source least likely to contribute to global warming. All three sources are proven technologies and have the production and delivery infrastructure in place to reduce oil's percentage of America’s energy production. But none of them are particularly popular among environmentalists who advocate the reduction of greenhouse gas emissions; coal and natural gas are still fossil fuels that are non-renewable and are claimed to exact a toll on the environment in their production and use. As far as nuclear energy—well, the vast majority of environmentalists have nothing good to say, pointing to issues involving waste disposal and fears of some catastrophic Chernobyl-type disaster. These, then, are not the alternatives that advocates of alternative energy intend when they speak of alternative energy.

What, then, are the alternatives acceptable to the main advocates of alternative energy? The key words to remember are "renewable" and "green." Acceptable alternatives are those that can be reproduced or, ideally, can never run out. In addition, they cannot be based on any source that could possibly harm the environment. That automatically excludes hydroelectric power, which is renewable and uses existing technology, but involves altering the physical environment and the habitats of various forms of wildlife (remember the story of the Snail Darter?). So, what's left? Solar power and wind power. These two (along with ethanol to a lesser extent) are the gold standard of acceptable alternatives. Both are renewable and are sources that appear to do no harm to the environment.

Other than being renewable and green, what else to solar and wind have in common? What do they share that make them impractical as alternatives to fossil fuels? We'll look at those questions over the next few weeks.

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April 29, 2011

Oil Depletion Allowance Mischaracterized as a "Subsidy"

As a Texas oil and gas attorney, I am deeply concerned at the constant beating the oil and gas industry takes from Obama and his administration. Obama paints oil and gas companies as Machiavellian monoliths, with their CEO's sitting around in tails and top hats like the millionaire in the Monopoly game. I can't recall a president as antagonistic to the industry since Jimmy Carter's ill-informed and destructive policies resulted in a great deal of oil production being driven from the United States. However, Obama may surpass Carter in his destructiveness. This is the behavior of a misguided idealogue and a demagogue, especially because the announced basis for these policies is so inaccurate. Obama's speeches appear calculated to generate some kind of "us against them" mentality. But it is not a case of "us against them". We are them. Most of our oil and gas comes from smaller, independent producers, not the big companies. This assault will cost us jobs and energy at a time when both are in short supply.

The latest assault on the oil and gas industry is Obama's announcement that he wants to end "oil and gas subsidies". I think this is Obama-speak for eliminating the depletion allowance. However, Obama does not apply the same view towards all the other subsidies the federal government hands out. For example, most informed people are aware that the real estate debaucle and resultant depression of the last few years is a direct result of the goal of Democrats to buy votes by making sure everybody bought a house, whether they could afford it or not. This policy was expressed in the insistence of a Democratic Congress that Fannie Mae and Freddie Mac lower their standards in loan qualification (if they are breathing and have a copy of their last utility bill, they qualify), and in the easy money policy of the Federal Reserve. We all know how that turned out. Incredibly, both those policies are still in place. Not only are these policies still in place, but now we have other federal programs to bail out the people who could not afford their mortgage in the first place. This is insanity!

I ran across a quote by Glenn Reynolds recently, that put it far better than I could. Professor Reynolds is a law professor at the University of Tennessee. His blog, Instapundit, is the source of many thoughtful comments. Here is a quote from his blog regarding subsidies:

The government decides to try to increase the middle class by subsidizing things that middle class people have: If middle-class people go to college and own homes, then surely if more people go to college and own homes, we’ll have more middle-class people. But homeownership and college aren’t causes of middle-class status, they’re markers for possessing the kinds of traits — self-discipline, the ability to defer gratification, etc. — that let you enter, and stay, in the middle class. Subsidizing the markers doesn’t produce the traits; if anything, it undermines them. I don’t think Obama grasps this.

This is spot on. Thanks to Professor Reynolds for putting it so well!

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February 28, 2011

Texas and Congress Take on EPA in Greenhouse Gas Battle

129524_industrial_misc__2.jpgLike many Texas oil and gas attorneys, I am keenly interested in the struggle unfolding between the EPA, Congress and the State of Texas. In a previous blog post, I discussed the EPA's recent efforts to regulate greenhouse gasses across the nation. Today, I'll describe the State of Texas' and the US Congress' responses to the EPA's new greenhouse gas rules.

The EPA's greenhouse gas regulations require the states to implement a federally mandated greenhouse gas permitting system. Under EPA greenhouse gas regulations, new, large power plants that are already required to obtain pollution permits must also obtain a greenhouse gas permit. The permit would require those new power plants to implement the newer technologies available to control carbon dioxide emissions.

Most states agreed to implement the EPA's new greenhouse gas plan. Texas and Wyoming, on the other hand, filed legal challenges to the program.

Texas Governor Rick Perry publicly refused to go along with the EPA. Governor Perry's spokeswoman called the EPA's plans “misguided,” “unnecessary,” and “burdensome,” and said that the the permitting system threatens “hundreds of thousands of Texas jobs” and imposes “increased living costs on Texas families.”

The EPA caught wind of Perry's refusal and took matters into their own hands. Because it was clear that Texas would not implement the new greenhouse gas rules, the EPA decided to take over Texas' greenhouse gas permit program. So, new power plants that are required to get a greenhouse gas permit under the EPA's greenhouse rules would need to get that permit directly from the EPA, rather than the State of Texas.

Continue reading "Texas and Congress Take on EPA in Greenhouse Gas Battle" »

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February 15, 2011

EPA Takes Aim at Texas Greenhouse Gas Emissions

1109803_power_plant.jpgMuch to the chagrin of many Texans, the US Environmental Protection Agency (EPA) recently decided to regulate greenhouse gasses around the nation. This decision was a long time in the making and has important implications for the State of Texas and the whole nation. In this blog post, I'll describe the legal backdrop of greenhouse gas regulation, and I'll summarize the EPA's proposed plans to tackle greenhouse gasses.

Greenhouse gasses are heat trapping gasses that some scientists believe cause global warming. Carbon dioxide is one of the most abundant greenhouse gasses, and some climate change experts believe that the compound's increased presence in the Earth's atmosphere causes global climate change. The compound is created naturally through human and animal respiration, and it is also a natural by-product of combustion. When humans burn things, like coal, oil or natural gas, carbon dioxide is released into the atmosphere. It is not yet definitely proven, in my mind, that man-made carbon dioxide has any appreciable impact on the earth's temperature.

In the 2007 US Supreme Court case Massachusetts vs. EPA, the Court held that the EPA is required to study greenhouse gas emissions and determine whether greenhouse gas regulation is appropriate under the Clean Air Act (CAA).

The Supreme Court held that CAA section 202(a)(1) applies to greenhouse gasses, in addition to more traditional pollutants. The Court cited Section 202(a)(1) which requires the EPA Administrator to set emission standards for "any air pollutant" . . . "which in his judgment cause[s], or contribute[s] to, air pollution which may reasonably be anticipated to endanger public health or welfare." While the Supreme Court did not hold that the EPA must regulate greenhouse gasses, it did require the EPA Administrator to take the first step and determine whether or not greenhouse gasses are reasonably anticipated to endanger public welfare.

In 2009, the EPA Administrator made two important findings. The Administrator found that current and projected concentrations of six key, well-mixed greenhouse gasses 1) contribute to man-made global warming, and 2) threaten the public health and welfare of current generations. Remember that under Massachusetts v. EPA's interpretation of the CAA, the EPA must regulate air all pollutants that are reasonably anticipated to endanger public health or welfare. Once the EPA determined that greenhouse gasses lead to global warming, the EPA was poised to set emissions standards for greenhouse gasses, as required by Massachusetts v. EPA's interpretation of the CAA.

Continue reading "EPA Takes Aim at Texas Greenhouse Gas Emissions" »

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February 5, 2011

A Rational Analysis of Ethanol-Part Two

This week we continue our examination of ethanol as an alternative energy source. As a Texas oil and gas attorney, I am particularly interested in the impact that a shift from fossil fuels to alternatives would have on our economy and on our society. It is an unavoidable fact that we are a fossil fuel-based society; any shift from fossil fuels to alternative energy sources will have costs associated with them. While we don't know what all those costs will be, our experience with ethanol shows that the costs—at least in the early stages of development—can at best limit, and at worst outweigh, any benefits gained from the use of alternative fuels.

What are some of the costs of using ethanol as an alternative energy source? After looking at the issue, I believe there are three primary costs:

• The cost to us as taxpayers
• The cost to us as consumers
• The cost to our environment

These costs are well documented in study after study, but you never hear about them in the media. The media and the public seem to have bought the idea of limitless and cost-free benefits accruing to our society. There are some benefits, as other studies have shown. But if we don't look at the costs, how can we decide if the benefits are worthwhile?

What are the costs to us as taxpayers? In order to encourage ethanol production, Congress has approved generous subsidies to farmers and refiners. Since 1978, the Volumetric Ethanol Excise Tax Credit (VEETC) has provided refiners with an incentive to blend corn ethanol with gasoline. According to the the Government Accountability Office, in 2008 the government gave a total of $4 billion dollars in subsidies for corn-based ethanol; in 2009 the figure jumped to $6 billion dollars. Ethanol production in that year replaced a mere 2% of the U.S. gasoline supply. The average cost to the taxpayer was the equivalent of $82 a barrel, or $1.95 a gallon on top of the gasoline price. According to the Congressional Budget Office, the cost of replacing one gallon of conventional gasoline was $1.78 per gallon for corn ethanol in 2009. In addition to the tax credit, there is the Renewable Fuels Standard (RFS) which currently requires 36 billion gallons of renewable fuel (primarily ethanol) to be blended with gasoline by 2022 as well as a tariff on the importation of ethanol which functions much the same way a tax would, by increasing the cost of imports to consumers.

Continue reading "A Rational Analysis of Ethanol-Part Two" »

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December 18, 2010

An Analysis of the Latest Federal Debaucle Analyzed by a Texas Oil and Gas Lawyer

As a Texas oil and gas attorney, I have spent 33 years observing the Texas Railroad Commission, the agency in Texas that regulates oil and gas drilling, production and pipelines (among other things). In my experience, the Railroad Commission is tough and efficient. I have never seen them act as a rubber stamp for the oil and gas industry. Each time I have assisted a client with a complaint to the Railroad Commission, I have been pleased with their grasp of the situation and their sensitivity to consumers. In my experience (and even though I don't always agree with them), they do a good job.

The demonstrable competency of the Railroad Commission is one reason that the most recent intrusion by the federal government into Texas' affairs is especially disturbing. I am speaking, of course, of the emergency order issued on December 7, 2010 by the Environmental Protection Agency (the "EPA") to Range Production Company, forcing a cessation of it's activities in Parker and Hood Counties, Texas. This latest arrogance by the feds is unconscionable. In support of my statement, (and lest you think I am being extreme here), please consider the following:

Item One: The EPA order shuts down legitimate business operations, puts people out of work, and interrupts the production of a clean and environmentally sound fuel. So, you might assume the EPA had some evidence for what they are doing. You would be wrong.
7152_tap.jpg The EPA has apparently viewed the "documentary" (and I am using that term very loosely) called "Gasland" and taken it for fact. Certainly, many homeowners who live near wells have watched it, and probably thought it was factual. The truth is that most of what is depicted in this film is patently false. For example, in at least two scenes, homeowners in Colorado are shown lighting their tap water on fire, presumably due to contamination from gas well drilling, fracking or production.The truth is that these occurrences were thoroughly investigated by the Colorado Oil and Gas Conservation Commission (the "COGCC"). The result of the investigation? There was methane in the water from naturally occurring methane deposits. The drilling of, fracking for and production of gas from wells in the vicinity had nothing, I repeat, NOTHING, to do with it. You can read a summary of the COGCC's report here.

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October 15, 2010

A Texas Oil and Gas Attorney Looks at Ethanol-Part One

When discussing the issues involved in national energy and environmental policy, the subject of alternative energy frequently comes up. As a Texas oil and gas attorney, I follow these discussions with great interest. The outcomes of our decisions about alternative energy sources will eventually effect anyone even tangentially connected with the oil and gas industry in this country. That's why a balanced evaluation of the proposed alternatives to fossil fuels is so important. In this first of several blogs about alternative energy, we'll be looking at one of the most widely used today—ethanol.

Ethanol, or grain alcohol, has been around as a fuel for well over a century. Henry Ford's first vehicle, the Quadricycle, was designed to run on pure ethanol; later, his Model-T could run on pure ethanol, gasoline, or a mixture of both. In fact, Ford continued to be an advocate for ethanol as a motor fuel well into the 1920s, long after cheap and plentiful gasoline became the fuel of choice. The low price of gasoline until the 1970s dampened the further use of ethanol (save for a brief time during World War II). This changed with the gasoline price shocks of the 1970s. Interest in ethanol revived, spurred by government subsidies targeting the development of synthetic fuels. When gasoline prices plummeted in the 1980s, research into the commercial production of synthetic fuels stopped to a great extent. Interest in ethanol, however, remained.

The interest in ethanol, at least through the 1990s and early 2000s, was not as a replacement for gasoline but as a fuel additive for environmental reasons. The Clean Air Act of 1990 and the Alternative Motor Fuels Acts mandated the use of oxygenates to reduce carbon emissions from automobiles. The two most widely used oxygenates were MTBE (methyl tert-butyl ether) and ethanol. By the early 2000s, however, the EPA mandated the phasing out of MTBEs because of fears of groundwater contamination. Today, ethanol is the most widely used gasoline additive, with most areas requiring a blend of 10% ethanol and 90% gasoline.

1278475_corn_on_stalks.jpg With the rising price of gasoline worldwide, along with fears of man-made climate change, the possibility of ethanol partially—or fully—replacing fossil fuels for motor vehicles has gained great currency. From 2007 to 2008, ethanol's share in global gasoline-type fuel used increased from 3.7% to 5.4%; in 2009 world production reached 19.5 billion gallons. The world leaders in ethanol production are Brazil and the United States, with a combined 80% share. (See Executive Summary: "Assessing Biofuels" UNEP 2009). Ethanol can be produced from a wide variety of grains and other feedstock such as corn (the predominate source in the United States) and sugar cane (the predominate source in Brazil), along with sugar beets, sorghum, switchgrass, wheat, cotton, and even the waste left over from harvesting (referred to as cellulose waste). While the production of ethanol from these other sources is in the research stage, commercial production of ethanol in the United States from corn is commonplace.

Production of corn ethanol in the United States is driven by statutory mandate and government subsidies. Oil refineries are required by law to use ethanol to blend with gasoline to reduce carbon emissions. The problem is that ethanol is very expensive to produce; according to a 2005 Department of Agriculture study, a gallon of ethanol costs an average of $2.53 to produce; by contrast, a gallon of gasoline takes only an average of $1.95 to produce. As of 2007, ethanol subsidies amounted to 42% to 55% of ethanol's wholesale market price. This means that the real cost of producing a gallon of ethanol is almost $4.00 per gallon. Without the subsidies, ethanol would not be economically viable to produce as a fuel, much less to use as a fuel additive.

In spite of the costs involved, the advocates of corn-based ethanol continually tout its benefits to the economy and the environment. Ethanol, they say, reduces toxic emissions and the growth of greenhouse gases in the atmosphere, leads to American energy independence from imported foreign oil, aids farmers and rural communities by increasing demand for their crops, and is responsible for the creation of thousands of new jobs in communities all across the nation.

Are these benefits real? Are they worth the cost? And, finally, what are the real costs of ethanol production? I'll look at these in my next blog.

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September 25, 2010

A Texas Oil and Gas Attorney Examines the Pros and Cons of Alternative Energy

Although I am primarily a Texas oil and gas attorney, I am interested in all energy sources, and I am especially interested in the ongoing national discussion about what are called alternative energy sources. One of the hottest topics in the world of energy is the discussion of alternatives to fossil fuels. While the definition of "alternative energy" has changed over time, the discussions today center on energy sources other than oil, gas and coal, and include such energy sources as solar, wind, biomass, hydrogen, and geothermal energy. These discussions are presumably driven by concerns over America's dependence on imported oil and the effects of allegedly manmade climate change. Often, advocates of alternative energy sources make extravagant claims when touting their alleged benefits when compared to fossil fuels. One alternative energy website says that alternative energy sources “have no undesired consequences”; in fact, some people claim that alternative energy sources “are renewable and are 'free’ energy sources." The move from traditional to alternative energy sources is not only touted as the solution to a whole host of environmental problems, but the Obama administration says the “green jobs” resulting from this shift are a key to economic recovery and the basis of a strong middle class.

Alternative energy sources seem to offer the world a future environment free of the deleterious effects of obtaining and burning fossil fuels and an economy growing rapidly and unfettered on the back of unlimited and free (e.g. no cost) energy and a green jobs revolution. It sounds almost too good to be true.

The question is: is it? Is alternative energy a “no cost” solution to all our environmental, energy, and economic problems? Well, as Robert Heinlein popularized in his classic science fiction novel, The Moon is a Harsh Mistress, TANSTAAFL (“there ain't no such thing as a free lunch.”). Everything comes with a cost—even in the Brave New World of alternative energy. These costs seem to get lost in the hype.

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September 8, 2010

Why You Should Have a Texas Oil and Gas Attorney Review Your Oil and Gas Lease!

As the price of oil creeps back up, the pace of oil and gas leasing has picked up as well. As a Texas oil and gas attorney, I regularly get calls from folks who ask me why they should go to the expense of having an attorney review their oil and gas lease. Here are the reasons I hear for not consulting an attorney, and my response to each, explaining why consulting an attorney is important:

1. "The landman told me that the lease was just a standard form". Watch my lips on this one: there is no such thing as a standard oil and gas lease. The landman may have meant that the lease they offered was standard for that particular landman, or for the particular oil company the landman was representing. However, there is simply no such thing these days as a standard, industry-wide form.

2. "The lease did not look that complicated". If you are not an oil and gas lawyer, do you really know what the terms in that lease mean? Do you know when words in the lease have one meaning in ordinary use and another meaning in the oil and gas industry? Even more important: do you know what's missing?

3. "I'm getting the bonus and royalty I want, so why should I care about the fine print?" The truth is that what is in the body of the lease, in the "fine print", can have a greater impact on your pocketbook in the long run than the amount of the bonus or royalty. In some cases, depending on the lease, the financial gains to you of a few changes in the lease can result in much greater compensation to you than what you receive in bonus and royalty!

4. "The lease said it had a term of only three years, and that's not very long so I didn't think what the lease said was that important". Oil and gas leases have a "primary term" of between two to five years. The oil and gas company, with some exceptions depending on the exact language of the lease, must drill a well within that time that is capable of producing oil or gas in commercially paying quantities. If they do not, (again, subject to various exceptions and extensions used in some leases), then the lease expires. If they successfully drill a well within the primary term that is capable of producing oil or gas in commercially paying quantities, then the lease will go on for so long as the well produces in commercially paying quantities. That means that the term of that lease may go on past your lifetime. Since it is possible that the oil and gas lease you sign may go on for a long, long time, isn't it just common sense to make sure that it's a lease you can live with for that long?

oil%20and%20gas%20well%20at%20sunset6%20%2800000869%29.JPG 5. "The landman was just so nice". Yes, he was nice. It is his job to be nice. If he wasn't nice, he would have been fired a long time ago. Secondly, whether the landman was nice or not, the landman's legal allegiance is to the oil and gas company the landman represents, and not to you.

6. "It costs too much to see a lawyer". There are many oil and gas attorneys in Texas whose fees are not only reasonable, but whose rates are a fraction of the amount of damage that can be done to your land because of an improper agreement. In addition, the attorneys fees are sometimes offset by the increased bonus payment as the result of a lease negotiated by an attorney. Finally, this lease may last your lifetime. Doesn't it make sense to be sure you can live with it?

7. "The oil and gas company promised me everything I wanted, so I didn't care if it was actually written in the oil and gas lease". Unfortunately most (there are a few exceptions) verbal promises by the oil and gas company or its landman are not enforceable under Texas law.

8. "The landman told me I had to sign right away, or they would withdraw their offer and I wouldn't get the money they were offering". It usually takes a while to lease all the acreage that the oil and gas company is required to lease before they drill. There is rarely a situation where it is truly a case of "sign right now or no deal".

9. "My mineral interest is so small, the oil company wouldn't make any changes anyway". It is certainly true that someone who owns many acres and owns 100% of their minerals will have more leverage with the oil company than someone who owns a small fractional interest in a few acres. However, sometimes even small interests count, when it is just those interests or acres that the oil company needs to make up its production unit. Secondly, many times owners of small interests, such as family members, go together and retain me to negotiate their lease, and together, they have more leverage than they did acting individually. In my office, the cost to review, evaluate and negotiate a lease is the same whether it's for one family member of twenty. Finally, most oil and gas companies are reasonable, and are open to making reasonable changes even when your interest is small. The key is to have someone who is experienced and who knows what changes are appropriate to ask for given the size of your interest. Even small changes can make a big difference in the overall fairness of a lease.

10. "I want to negotiate my own lease and save the money I would have spent on an attorney." Unless you have experience in negotiating an oil and gas lease, you are almost always not going to get the best deal for yourself. Landmen can spot an inexperienced person a mile away, and they are not going to cut you any slack! Remember, their loyalty is to the oil company, and not to you.

If you get an offer from an oil and gas company or its landman, simply smile and say: "Thank you. I will seriously consider this. I will send it to my attorney promptly and we will be in touch with you soon". And then call your attorney!!

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September 3, 2010

A Texas Oil and Gas Attorney Reviews Proposed New Onshore Drilling Regulations

As a Texas oil and gas lawyer, I have followed with interest the proposals to add new regulations for onshore, as well as offshore, drilling in the wake of the Gulf of Mexico oil spill. Several initiatives to tighten federal regulation of offshore drilling are making their way through the halls of Congress. These bills are perhaps inevitable, considering the magnitude of the spill, the confused federal and BP response to the spill and the adverse public reaction to both the spill and the subsequent mitigation and clean up efforts. At the same time, however, environmental groups and some in Congress are using the push for new offshore drilling regulations to call for tighter federal rules for onshore oil and gas drilling. These new regulations are designed to make it more difficult for oil and gas companies to start drilling in the first place, and to more closely monitor their post-drilling operations for alleged threats to public health and the environment.

It's perhaps a little too simplistic to blame the BP spill for the new regulatory push onshore. Given the Obama administration's stated goals of favoring alternative energy and the environment over the pro-drilling energy policies of the Bush administration, perhaps new regulations were inevitable. But the debate appears to have taken on greater urgency in some quarters. As Kevin Book of Clear View Energy Partners says (referring to shale drilling), “the perception of risk has changed, and the reason for it can be summed up in one word—Macondo.”

The first signal of new regulations to come surfaced in May, when Interior Secretary Ken Salazar announced tighter regulations for oil and gas drilling on public lands. These new rules make it much more difficult for oil and gas companies to obtain drilling approval, and drilling on certain public lands would require a period of public comment. While environmental groups praised the regulations as reversing the allegedly destructive Bush administration drilling policies, the Independent Petroleum Association of the Mountain States (now the Western Energy Alliance) stated in a press release that the new rules would “delay the development of clean, domestic natural gas on Western federal lands.”


The desire for tighter regulations focused Congress' attention on two bills introduced over a year ago. One, the Consolidated Land, Energy, and Aquatic Resources Act (the CLEAR Act), passed the House on July 30, 2010 and went to the Senate. Among other things, the bill requires oil and gas companies engaged in drilling on federal lands to adopt “best management practices” designed to minimize threats to health and the environment; requires public disclosure of the chemicals used in drilling or hydraulic fracturing (often referred to as "fracing" in the oil industry or "fracking" by the media); and repeals 2005 legislation allowing companies to drill on public lands without a full environmental review process. Another bill, the Fracturing Responsibility and Awareness of Chemicals Act (the FRAC Act), originally introduced last summer, specifically targets the practice of hydraulic fracturing by removing the exemption of the practice from regulation by the EPA under the Safe Drinking Water Act. This bill and a companion bill introduced at the same time in the Senate have never come up for a vote. Similar language was stripped from the CLEAR Act, but the Clean Energy Jobs and Oil Company Accountability Act, introduced in the the Senate by Majority Leader Harry Reid (D-Nev.) would require companies to make their fracing formulas public on the Internet.

While the ultimate fate of all these bills has yet to be determined, these initial efforts to increase federal regulation of onshore drilling spurred calls for even further regulation. In late July 2010 a number of environmental groups, including the National Audubon Society, the Natural Resources Defense Council, and the Sierra Club, sent a letter to Senate Majority Leader Harry Reid and Speaker of the House Nancy Pelosi, urging the passage of new onshore drilling regulation to target what they call the damaging environmental and health effects of current practices. In addition, they urged an end to tax benefits for oil and gas companies, more federal money for research into public safety and environmental protection, and an end to “fast-track” approval of oil and gas drilling on federal lands.

What impact will increased federal regulation have on domestic oil and gas drilling? Only time will tell. Oil and gas companies oppose federal regulations, saying that existing state regulations are quite sufficient to protect the environment and public health and safety. Marc Smith, the executive director of the Western Energy Alliance, points out the folly of giving more oversight of onshore drilling to the same federal regulators who failed to prevent the BP oil spill: “It doesn't make sense to take more control away from state oil and gas regulators and give it to the federal agency that just oversaw the worst environmental catastrophe in the history of our nation.” Here in Texas, for example, we have the Texas Railroad Commission, which does an excellent job of regulating oil and gas drilling and production. Industry representatives also claim that the regulations embodied in the CLEAR Act will make drilling on public lands more expensive, increase Government control over the market, and create a new and unnecessary layer of bureaucracy.

There is an economic and national security aspect of these proposed regulations that sometimes gets lost in the debate. If regulations for onshore drilling are increased, oil companies will need to spend more time and money in compliance. That means the cost of oil and gas and the products derived from oil and gas will increase for consumers. In addition, increased regulation will almost certainly mean fewer wells will be drilled, and this will result in even greater unemployment for workers in the oil and gas industry and all the many industries that service the oil and gas companies (the majority of which are small businesses). Ultimately, if the higher regulatory cost leads to lower domestic production, we will have to increase, rather than decrease, our reliance on Mid-East oil. This factors should make us consider carefully: is increased reulation is really the direction we should be heading?

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June 27, 2010

A Texas Oil and Gas Attorney Looks at the Gulf Oil Spill

As a Texas oil and gas attorney, I have had occasion from time to time to observe the environmental, administrative and legal ramifications of an onshore oil spill, usually caused by vandalism or malfunctioning equipment. Along with everyone else in the world, I am horrified as the tragedy in the Gulf of Mexico unfolds, and along with everyone along the Gulf, I am intensely frustrated that the spill has not been stopped yet.

Something else, besides the damage to persons, property and the environment, concerns me. Specifically, there is a lynch mob mentality about BP that has this country in its grip. They have been tried and found guilty in the court of public opinion, and the tar and feathers await.

I am not going to defend BP. They have a long history of regulatory problems. Moreover, from what we know so far, it appears that a couple of very stupid and very negligent decisions by BP may have caused this disaster. However, as John Adams famously said in the Novanglus Essay No. 7, we are "a government of laws, not of men." We also live under state and federal constitutions that promise that we are innocent until proven guilty. Nothing about the cause of this spill or who is responsible has been proven yet. We would be better served by focussing our attention on stopping the spill at this point, rather than flogging BP.

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April 18, 2010

Why You Should Have a Texas Oil and Gas Attorney Review That Oil and Gas Lease Before You Sign It!

As a Texas oil and gas attorney, I regularly get calls from folks who, long after they have signed an oil and gas lease, are upset with an oil and gas company for something the company is doing or not doing. In most cases, once we review the oil and gas lease, it becomes obvious that they have already given permission for the oil company to do what they are doing in the language of the lease they signed.

I customarily ask these folks why they did not have an attorney look at the lease before they signed it. I have been making a list of the reasons they give. Here are the reasons I hear most often, and my response to each one:

1. "The landman told me that the lease was just a standard form". Watch my lips on this one: there is no such thing as a standard oil and gas lease. The landman may have meant that the lease they offered was standard for that particular landman, or for the particular oil company the landman was representing. However, there is simply no such thing these days as a standard, industry-wide form.

2. "The lease did not look that complicated". If you are not an oil and gas lawyer, do you really know what the terms in that lease mean? Do you know when words in the lease have one meaning in ordinary use and another meaning in the oil and gas industry? Even more important: do you know what's missing?

3. "I'm getting the bonus and royalty I want, so why should I care about the fine print?" The truth is that what is in the body of the lease, in the "fine print", can have a greater impact on your pocketbook in the long run than the amount of the bonus or royalty. In some cases, depending on the lease, the financial gains to you of a few changes in the lease can result in much greater compensation to you than what you receive in bonus and royalty!

4. "The lease said it had a term of only three years, and that's not very long so I didn't think what the lease said was that important". Oil and gas leases have a "primary term" of between two to five years. The oil and gas company, with some exceptions depending on the exact language of the lease, must drill a well within that time that is capable of producing oil or gas in commercially paying quantities. If they do not, (again, subject to various exceptions and extensions used in some leases), then the lease expires. If they successfully drill a well within the primary term that is capable of producing oil or gas in commercially paying quantities, then the lease will go on for so long as the well produces in commercially paying quantities. That means that the term of that lease may go on past your lifetime. Since it is possible that the oil and gas lease you sign may go on for a long, long time, isn't it just common sense to make sure that it's a lease you can live with for that long?

5. "The landman was just so nice". Yes, he was nice. It is his job to be nice. If he wasn't nice, he would have been fired a long time ago. Secondly, whether the landman was nice or not, the landman's legal allegiance is to the oil and gas company the landman represents, and not to you.

6. "It costs too much to see a lawyer". There are many oil and gas attorneys in Texas whose fees are not only reasonable, but whose rates are a fraction of the amount of damage that can be done to your land because of an improper agreement. In addition, the attorneys fees are sometimes offset by the increased bonus payment as the result of a lease negotiated by an attorney. Finally, this lease may last your lifetime. Doesn't it make sense to be sure you can live with it?

7. "The oil and gas company promised me everything I wanted, so I didn't care if it was actually written in the oil and gas lease". Unfortunately most (there are a few exceptions) verbal promises by the oil and gas company or its landman are not enforceable under Texas law).

8. "The landman told me I had to sign right away, or they would withdraw their offer and I wouldn't get the money they were offering". It usually takes a while to lease all the acreage that the oil and gas company needs before they drill. There is rarely a situation where it is truly a case of "sign now or no deal".

9. "My mineral interest is so small, the oil company wouldn't make any changes anyway". It is certainly true that someone who owns many acres and owns 100% of their minerals will have more leverage with the oil company than someone who owns a small fractional interest in a few acres. However, sometimes even small interests count, when it is just those interests or acres that the oil company needs to make up its production unit. Secondly, many times owners of small interests, such as family members, go together and retain me to negotiate their lease, and together, they have more leverage than they did acting individually. In my office, the cost to review, evaluate and negotiate a lease is the same whether it's for one family member of twenty. Finally, most oil and gas companies are reasonable, and are open to making reasonable changes even when your interest is small. The key is to have someone who is experienced and who knows what changes are appropriate to ask for given the size of your interest. Even small changes can make a big difference in the overall fairness of a lease.

If you get an offer from an oil and gas company or its landman, simply smile and say: "Thank you. I will seriously consider this. I will send it to my attorney promptly and we will be in touch with you soon". And then call your attorney!!

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February 20, 2010

A Texas Oil and Gas Lawyer Considers Greenhouse Gases

As a Texas oil and gas attorney, I have viewed the "global warming" debate with growing alarm. When the United Nations International Panel on Climate Change ("IPCC") initially issued its fourth report, I was concerned because the IPCC is made up primarily of politicians, not scientists. Next, I read the report thoroughly and then did my own research. My independent research led me to the conclusion that the IPCC's findings were in large part: 1) based on no research at all; 2) were based on non-peer-reviewed research; or 3) illogical, tenuous or unjustified extrapolations from unrelated research. Despite these problems with the report, large numbers of people wanted to join the IPCC and Al Gore in proclaiming that global warming was caused by manmade greenhouse gases. It is even more alarming at how many people continue to chant this mantra, even after the flawed science (or lack of science) behind the IPCC's report has been revealed. 1252053_country_road.jpg

Recent news has demonstrated to an even greater degree just how ill-conceived, biased and misguided the IPCC's report was. Notwithstanding the evidence of how flawed the IPCC's report is, the EPA, at the direction of the Obama Administration, has sought to treat greenhouse gases as toxic, and to regulate them.

Major industries in Texas, including agriculture and oil and gas production, unquestionably produce some carbon dioxide. The idea of regulating the greenhouse gases, and in particular, the CO2, produced by these industries as a toxic substance is irresponsible, however. Not only is this kind of regulation misguided and politically motivated, the economic costs of regulation could be staggering, especially in this recession. Why would the federal government want to beat on us when we're down??

It is especially heartening to see the Texas Governor, Rick Perry, take on the EPA by bringing suit to stop EPA from regulating greenhouse gases in Texas. Many of us are cheering for him!

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October 30, 2009

Oil and Gas Leasing in the Eagle Ford Shale in Texas

Texas oil and gas attorneys and mineral owners may see more leasing activity in 2010 in the Eagle Ford Shale, a field in southern Texas that oil and gas companies have known about for some time, but that is just now being explored. The field is named after the city of Eagle Ford, Texas, hometown of Bonnie Parker of "Bonnie and Clyde" notoriety. (The city of Eagle Ford was incorporated into the City of Dallas in 1956).

Several oil and gas operators, beginning with Petrohawk Energy Corporation, and including many of the larger companies (Anadarko Petroleum Corporation, XTO Energy Inc., Chesapeake Energy Corporation and several others), are quietly signing up leases and drilling exploratory wells. The "word on the street" is that the cost of drilling a gas well in the Eagle Ford Shale may be substantially less than in the Barnett Shale or the Haynesville Shale, although drilling in the heavy clay present in portions of the Eagle Ford shale presents its own challenges.

The Eagle Ford Shale underlies large portions of Texas, but it doesn't always contain gas. Currently, leasing appears to be limited to Colorado, Dewitt and Karnes Counties. Other counties that may see leasing activity include Bee, Dimmit, Goliad, LaSalle, Lavaca, Live Oak, McMullen, and Webb Counties. An increase in the price of gas (which, given the large amount of current reserves, probably won't happen for a while) would certainly accelerate activity in this play.

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October 5, 2009

A Texas Oil and Gas Lawyer Sees More Activity in Store for 2010

As a Texas oil and gas attorney, I have observed that it has been a slow year so far for leasing and drilling activity. But some experts are predicting a change on the horizon for 2010. An article this morning by Jamaal O'Neal in the quotes Professor Ken Morgan, Texas Christian University geology professor and director of the TCU Energy Institute, as saying that higher oil and gas prices may be ahead for 2010. The article quotes research by Baker Hughes that natural gas, which was selling for $10.00 per thousand cubic feet or more in mid 2008, is currently selling for as low as $3.60 per thousand cubic feet. A barrel of crude oil that sells for about $69.00 currently, was bringing $150.00 a barrel during the summer of 2008. Professor Morgan opines that the large amount of natural gas reserves, as well as the world-wide recession, has kept prices for oil and gas low.

Basic economics dictates that when prices are low, oil and gas companies are reluctant to expend the large sums necessary to drill new wells. They are not going to make the investment if they can't get a return. As the world economy recovers, demand for oil and gas will increase, the price of oil and gas will increase and the drilling of new wells will once again generate sufficient returns to support the cost of drilling. Once oil and gas companies begin to drill again, mineral owners will begin to get calls from landmen working for the oil and gas companies, seeking new leases. I may be a bit optimistic, but I see leasing and drilling activity in Texas picking up by March and April 2010.

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September 5, 2009

A Texas Oil and Gas Lawyer Watches Prices Rise and Fall

As a Texas oil and gas attorney for many years, I have seen many booms come and go. During a "boom" period, prices for oil and gas increase. The increase in prices encourages exploration of new sources of oil and gas and development of existing sources. Mineral owners tend to see much more leasing activity during boom periods, and oil and gas companies are much more amenable to entering into leases that are fair to both mineral owner and operator. Conversely, when prices of oil and gas are low, exploration and development sags, leasing activity falls off and when a mineral owner is offered a lease, it is usually a very one-sided lease that favors the oil and gas operator and is very unfair to the mineral owner. oil%20wells.htm We are just coming off a very down period for oil and gas exploration and development in many areas of Texas. I have counseled many mineral owners over the years during these down periods who were offered leases that were, frankly, onerous. In most cases, my client decided to decline the oil and gas company's offer, and await a better offer. So far, each of these owners was ultimately offered a better deal, a fairer lease, and a lease with better compensation for their minerals because they waited. As in life, there are no guarantees in the oilpatch. For example, there is no guarantee that you will be offered another lease, although it is certainly likely that you will. There are some cases in which even a poor lease might be better than no lease at all, especially if you are faced with a situation where your minerals may be drained without compensation if you don't execute a lease. It is also important to realize that even in boom markets, you don't always get everything you want in a lease. It is always a matter of give and take. Frankly, only someone experienced in this area can give you the input to help you make an informed judgment about whether to lease or not, and if you do lease, on what terms.

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August 15, 2009

Texas Oil and Gas Attorneys Have Seen Booms Come and Go

Any Texas oil and gas attorney who has practiced for any length of time has been through the cycle many times: oil prices go up, and leasing and drilling activity increases. Oil and gas prices decline, and many oil and gas companies pull back on their leasing and drilling efforts. The past year has seen an especially extreme example of this cycle. Last summer, according to WTRG Economics, the price the operator received for oil in some areas of Texas reached $150.00 per barrel or more. According to the Energy Information Administration (a division of the Department of Energy), gas was going for $8.00 per mcf at the wellhead in some places. Leasing was going on at a frantic, almost giddy, pace and substantial primary term payments and royalty percentages were the norm. Then prices declined sharply, to less than $30.00 per barrel of oil and $3.00 per mcf for gas at the wellhead in many areas of Texas. Most operators pulled way back, some walking away from signed leases and others signing leases only at substantially reduced bonus and royalty levels.

Now the price of oil and gas is increasing, and phoenix-like, the Texas energy industry begins to rise from the ashes. This time, there are some dark clouds on the horizon, coming in from our nation's capitol, that do not bode well for the energy industry. President Obama, while proclaiming that he wants to achieve independence from foreign oil sources, is considering two things that would cripple our domestic oil and gas industry. Specifically, he wants to eliminate intangible drilling costs and depletion allowance as deductions for oil and gas operators on their federal income tax. He wrongly calls these "subsidies", in an attempt to gain support for this policy.

314930_out_of_business.jpg The deduction for intangible drilling costs allows oil and gas companies to deduct the cost of exploring for oil and gas from later oil and gas income. These costs include such things as seismic tests, surveys, engineering fees, wages, etc. The intangible drilling cost deduction encourages oil and gas companies to explore for new energy sources. The depletion allowance allows oil and gas companies to deduct a portion of the value of their mineral deposits as those deposits are used up, just as the owner of a machine used to produce goods is allowed to depreciate his machine.

It took decades for the domestic energy industry to recover from the ill-conceived, poorly timed and wrongly executed policies of Jimmy Carter. President Carter's policies drove many smaller companies out of business, and encouraged other producers and refiners to move outside of the United States. When we experience those times of high gasoline prices in the United States, it is primarily Carter that we have to thank. Unfortunately, we now seem to have another President headed down this same irresponsible path.The announced policies of Obama are bad policy policy for at least four reasons: 1) most energy production in this country comes from small, independent companies, not "big guys" like Exxon or Mobil, and these small companies are going to be hurt badly by this policy; 2) these policies will result in much higher prices at the pump for consumers, who are having a hard enough time already; 3) Carter's policies drove the "big guys" overseas, and now Obama's policy would diminish the remaining independents; and 4) the higher energy prices will contribute in a big way to inflation. Is this really the way to achieve energy independence? I think not!

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May 8, 2009

Have a Texas Oil and Gas Lawyer Make Sure Your Royalties Are Correct

Part of what I do for clients as a Texas oil and gas attorney is to calculate oil and gas royalties so that they can be sure they are being paid correctly. I thought it might be useful to you to explain how an ownership percentage and royalty are calculated.

1. First, we take your percentage of mineral ownership in the land in question, and we multiply that by the number of surface acres in your entire tract. The resulting number is your net mineral acres. For example, if two relatives together own a one-half interest in a forty acre tract, or ½ times 40, they have twenty net mineral acres.

pump%20image.htm 2. Secondly, if the land is located in a pooling unit, (sometimes also called a pro-ration unit), we multiple the total number of acres in the tract by a pro-ration fraction. The reason for this is that each royalty owner in a pooling unit is only entitled to their proportionate share of the oil or gas produced by the entire pooling unit. A pooling unit is an area around a well that is set by the Texas Railroad Commission, and is intended to approximate the area drained by a producing well. Pooling units can range in size from 80 to 640 acres or more. For example, for a forty acre tract that is located in a 320 acre pooling unit, that forty acre tract is entitled to 40/320, or 0.12500, of the minerals (whether oil or gas or both) produced by that 320 acre unit.

3. Third, we multiply that result by the royalty fraction in the oil and gas lease you signed.

4. Finally, we divide that result by the number of current owners to determine what portion of the total production from the pooling unit each owner is entitled to.

By way of example, let’s say you and a relative own 20 net mineral acres in a 40 acre tract. Let’s also say that the pooling unit is 320 acres. This fraction in our example would be 40/320. Next we multiply that result by the royalty fraction in the oil and gas lease that was signed, which in our example is 1/6. Finally, we divide that result by the number of owners, which in our example is two.

Here is the calculation for our example in numeric form:

First, I convert the fractions to decimals so they are easier to multiply:

20/40 = 0.5

40/320 = 0.12500

1/6 = 0.166666

1/2 = 0.5

Next, I multiply out the calculation:

0.5 X 0.12500 X 0.166666 X .5 = 0.005206

The result of this calculation is that for every dollar of gas sold from the well, you and your sister in our example would each get 0.005206 of that dollar. This does not seem like much, but a good gas well can produce millions of BTU's of gas, and so the royalty payments can be substantial.

Oil and gas companies can and do make mistakes in calculating a mineral owner's royalties. If you think your royalties are not being calculated correctly, give me a call.

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May 2, 2009

Consult a Texas Oil and Gas Attorney Before You Sign that Pipeline Easement-Part Three

As oil and gas lawyers in Texas are well aware, there is a lot of pipeline construction going on in Texas as well as in other parts of the United States. I had a fascinating conversation not long ago with Victoria Myers, Senior Editor for The Progressive Farmer Magazine. If you have not looked at this publication before, it is really an excellent resource for folks who make a living from farming, as well as those "gentlemen (gentlewomen?) farmers out there. (You know who you are!) Since I am a Nebraska farm girl myself (Thayer County, to be precise), I find it especially interesting.

Victoria is the author of an article in an upcoming issue of Progressive Farmer regarding pipeline easements and rights-of-way. My discussion with her has caused me to update my list of issues involved in these kind of agreements by adding a few from her list. Here is the updated list:

Pipeline.JPG 1. Is the easement limited to a specific area, or is it a blanket easement over your entire property?
2. Is the pipeline going to be buried to an appropriate depth, in light of your future use of that property, what the pipeline will carry and the anticipated size of the pipeline?
3. Does the easement obligate the pipeline company to refill to the original contour of the land and maintain that contour as the fill packs down?
4. Is the pipeline company obligated to remove and save the top soil from the easement area separately, to replace the topsoil and reseed with whatever grass was there originally and in general to restore the easement area to its original condition?
5. Will any waterways or drainage tiles be impacted by the pipeline? If so, is the pipeline company obligated to repair these to their original condition and possibly pay damages for temporary loss of use?
6. If your land is used for agricultural purposes, can construction, installation and maintenance be performed when the ground is cold or frozen to reduce soil compaction?
7. Is there a "temporary work area" in addition to the easement itself? Are you receiving an additional payment for use of this area?
8. Pipeline installation can involve a lot of very heavy equipment which will compact the soil. Is the temporary work area situated so that the soil compaction is kept to a minimum? Are you being paid damages if the compaction that does occur prevents future crops in this area?
9. Will you be compensated for crop loss or crop damage caused by the installation and construction phase as well as by the permanent pipeline?
10. Is the pipeline company required to notify you prior to use of herbicides for brush or weed control?
11. If fences will be effected, is the pipeline company obligated to use temporary fencing and to restore the original fence to same or better than the original?
12. If fences must be cut, will a gate be installed that is of a design and quality suitable for the use of that gate?
13. Will you have rights to use the surface in any manner that does not interfere with the pipeline?
14. Will the pipeline company agree to avoid important trees and not to remove or trim trees without your consent?
15. Will the pipeline company agree to mark the pipeline route with durable and permanent markers?
16. Will the pipeline company agree to be responsible for any damages that are caused directly or indirectly by the installation, operation, maintenance or removal of the pipeline?
17. Does the easement terminate if it is unused for a certain length of time?
18. Will there be above-ground equipment along the pipeline route? If there is going to be above-ground equipment, are you going to be separately and appropriately compensated for it?
19. Will you get a separate payment for the easement and for damages?

These are just a sample of the kinds of serious issues involved in negotiating a pipeline easement or right of way agreement. Each of these can be major issues if not properly addressed in the easement. For example:

1. If there is no right on your part to declare an unused easement to be abandoned, that easement will show up on your title forever, even if it has not been used for many years. This can create a major impediment to future uses of your property. You can try to get a release of the easement, but the pipeline company may not exist any longer, and there may be no one to sign a release. You may even need to file a suit and obtain a court order to declare the easement terminated.

2. Above-ground equipment can include valves, gas compressors (that can be very loud and messy) loops or pig entry sites or measurement equipment that may interfere with irrigation equipment.

3. Regarding payments, currently easement payments are taxed as capital gains but damages payments are not taxable. If you get one check and the payment for the easement is combined with the payment for damages, the IRS may well assume that the entire payment is taxable.

4. Construction equipment may prevent irrigation of a field at a critical time. In fact, the construction phase may render the entire field unusable, with the resulting loss of the crop from that field. You need to be sure the compensation paid to you includes the value of the lost crop.

For all these reasons, many landowners consider it simply good insurance to consult an attorney before they sign a pipeline easement. The cost of an attorney is a small fraction of the amount of potential damages caused by pipeline construction. In many cases, an attorney will pay for themselves because they are able to negotiate more complete damage payments from the pipeline company.

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April 24, 2009

A Texas Oil and Gas Attorney Can Find Lost Oil and Gas Royalties

As a Texas oil and gas attorney, one of the things I do often, and really enjoy, is assisting people in locating oil and gas royalties due to them from old oil and gas leases signed by their ancestors. In a previous blog here, I discussed how these royalties get lost. Today I'd like to discuss how I go about determining whether you may have oil and gas royalties due to you and your family.

First, I will need to know the Texas county in which you believe your relative or ancestor owned property or minerals. In addition, if you have any written documentation regarding this ownership, I ask you to provide me with copies. Any documentation, such as an old deed, an old oil and gas lease, a will, an old tax statement, a plat, a survey, a copy of the county appraisal district map showing the land, a stub from an old royalty check, or even just an address, can be very helpful. It is certainly possible to research all counties in Texas, but since there are 254 counties in Texas, the expense would be substantial.

859795_himba_1.jpg Next, I research the status of your relative’s ownership of the real property that may be subject to an oil and gas lease or leases. Even if you already have a legal description of the property, it is essential to make sure that your relative has not, unknown to you, conveyed or transferred the property in question to a third party, or perhaps lost the property due to delinquent taxes. If we proceed without the precise legal description of each parcel of real property, or if the legal description is inaccurate or incomplete, or if your relative has sold or lost the property or the mineral interest, the time and expense involved in further work will be wasted.

Once we have completed the real estate research, I identify any oil and gas wells that have been or are located on your relative’s property. In addition, I determine whether your relative’s lease was part of a pooling or production unit. I obtain copies of the pooling documents so that I can calculate your relative’s ownership percentage and royalty.

If a well or wells have been identified, I then perform a royalty analysis. There are three components to this analysis. First, I determine the historical production from these wells. Secondly, I use historical price data to calculate the approximate income from the production from any wells. Thirdly, I use the ownership percentage formula to determine royalties due to you and your relatives.

The final step is to assemble a package of the research and transmit this with a demand letter to the well operator and/or owner to pay royalties to you and any relative who shares ownership of the minerals with you.

Sometimes we find property owned by your ancestor that has never been put in your name. If that is the case, there are simple legal procedures to cure this situation that I will be happy to discuss with you. These procedures will both clear title to family land (so future generations won't have to face these issues) as well as clear the way to getting oil and gas royalties paid to you instead of escheated to the State of Texas!

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April 17, 2009

Consult a Texas Oil and Gas Attorney Before You Sign that Oil or Gas Pipeline Easement-Part Two

As a Texas oil and gas attorney, I negotiate a large number of oil and gas pipeline easements and rights-of-way throughout Texas, as well as easements for other types of utility lines. While the landowner and I may not get everything we want in the negotiated agreement, it is almost always more fair than the agreement the pipeline company originally offered.

I also get a couple calls a month from someone who signed an oil and gas pipeline easement or right-of-way without consulting an attorney before they signed. Usually, they are seeing activity by the pipeline company that disturbs them and they want to know if the agreement they signed "lets them to do that?" The answer most of the time is "Yes". Their next question almost always is: "Can I cancel this agreement or get out of it somehow?" The answer to that question is usually "No".

Pipeline.JPG I am intrigued by why people would sign such a long term, complex, agreement, without legal advice. I have been cataloging the reasons I hear, out of curiosity. Here are some of the reasons I have heard thus far, and my parenthetical response.

1. "The landman was just so nice". (Yes, he was nice. It is his job to be nice. If he wasn't nice, he would have been fired a long time ago. Besides, have you ever been taken advantage of by someone who wasn't nice?)

2. "The contract did not look that complicated". (Well, if you are not an oil and gas lawyer, do you really know what those words mean? Do you know when words in the agreement have one meaning in ordinary use and other meaning in the oil and gas field? Even more important: do you know what's missing?)

3. "It costs too much to see a lawyer". (There are many oil and gas attorneys in Texas whose fees are not only reasonable, but whose rates are a fraction of the amount of damage that can be done to your land because of an improper agreement. In addition, the attorneys fees are sometimes offset by the increased pipeline company payment as the result of a negotiated agreement.)

4. "The pipeline company promised me everything I wanted, so I didn't care if it was in the easement". (Unfortunately most [though not all] verbal promises by the pipeline company or it's landman are not enforceable under Texas law).

5. "The landman told me I had to sign right away, or they would withdraw their offer and I wouldn't get the money they were offering". (It takes a long, long time to acquire all the right-of-way for a pipeline. There is rarely a situation where it is truly: "sign now or no deal".)

If you get an offer from a pipeline company or it's landman, simply smile and say: "Thank you. I will seriously consider this. I will send it to my attorney promptly and we will be in touch with you soon". And then call your attorney!!


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January 2, 2009

Find Oil and Gas Royalties!

As Texas oil and gas attorneys know, each year, probably hundreds of thousands, maybe even millions, of dollars in oil and gas royalties from wells produced in Texas are lost to their rightful owners through a process called escheat. Specifically, when oil and gas companies cannot find the correct owner of mineral royalties, they are required to turn this money over to the Texas Comptroller.

How this happens is not difficult to understand. Let's say Mom and Dad bought 100 acres in Texas many years ago. They got a deed to the land and the deed was filed in the deed records of the county where the land is located. They purchased both the surface and the minerals. A while later, they sign an oil and gas lease, and shortly after that, they began getting royalty checks. They don't tell their children about the royalties, or maybe they do and the children forget about them. Many years later, Mom and Dad die, leaving five children. Maybe Mom and Dad died without leaving a will, or maybe they both had wills, but none of the children, for whatever reason, decided to have the wills probated. The five children just assume they each now own a one-fifth share of Mom and Dad's land, or 20 acres each. oil%20and%20gas%20well%20at%20sunset6.jpg

Three factors now come into play that result in royalties to Mom and Dad being overlooked by the children. First, most oil and gas companies have certain minimum amounts of royalties that must accrue before they will send a check. If an individual mineral owner has a small share of the royalties on a well, checks may be sent out every few months, or even once a year. Secondly, all wells are shut down from time to time, for repairs or perhaps while a new gas pipeline contract is being negotiated. During this time royalty checks may not be sent out. One of the children or a grandchild may collect Mom and Dad's mail for a time after Mom and Dad die. At some point, they stop doing so, or perhaps the Post Office forwarding order expires and is not renewed. When royalty checks resume, they are returned to the oil or gas company as undeliverable. At that point, Mom and Dad's royalty account is put in suspense, or on hold. After a certain amount of time, the oil or gas company is required by the Texas Property Code to turn all accrued royalties over to the Texas Comptroller.

A third factor that contributes to royalties being overlooked by heirs is that the well that produces royalties for Mom and Dad may not be on the family land. In fact, the well may be a considerable distance away from the family land. The reason is that most oil or gas wells are required by law to be part of a pooling unit. The pooling unit may be as small as eighty acres, in the case of an oil well, or it may be several hundred acres in size, in the case of a gas well. When the well is a distance from the family land, it may not occur to the heirs that the family land is actually part of that well's pooling unit.

(Keep in mind that the oil and gas company must depend on the county deed records to determine property ownership. If Mom and Dad did not have wills, or if they did and they were not probated, or if the wills were probated but the executor of the wills did not prepare a deed transferring the family land to the heirs, or if deeds were prepared but were not actually filed in the county deed records, then nothing shows up in the deed records to show the change of ownership! In addition, keep in mind that it is the heirs' responsibility to keep the oil or gas company informed of changes in ownership. It is not the oil or gas company's job to keep up with the heirs!)

One day, a grandchild or great grandchild may decide to investigate whether royalties are due, and if so, from what company. They will want to be sure that any royalties are paid to the current heirs. The good news is that a Texas oil and gas attorney with experience in this type of investigation can do this for you. Usually, all that is needed is one document relating to the land, such as a deed, an old tax statement, a plat, a survey, a copy of the county appraisal district map showing the land, a stub from an old royalty check, or even just an address. With just this small bit of information, an experienced oil and gas attorney can determine whether this land is part of a pooling unit, whether the well in the unit is producing, and whether royalties are due. Your attorney can then get the records corrected both with the county and the oil or gas company so that royalties are sent to the current heirs.

My office charges a modest fixed fee for this kind of investigation. The payoff for a small investment might just be substantial, not only in terms of monetary return, but also in terms of having title to the family land cleared up for future generations! Please call me if you think there may be missing royalties in your family.

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October 31, 2008

Have a Texas Oil and Gas Attorney Review Your Pipeline Easement!

As a Texas oil and gas attorney, I have occasion to review and negotiate many oil and gas leases in Texas for clients all over the United States (hopefully before the lease has been signed). However, having an attorney review a pipeline easement is every bit as important. Here are just a few of the critical questions that a pipeline easement should address:

Pipeline.JPG 1. Is the easement limited to a specific area, or is it a blanket easement over your entire property?
2. Is the pipeline going to be buried to an appropriate depth, in light of your future use of that property, what the pipeline will carry and the anticipated size of the pipeline?
3. Does the easement obligate the pipeline company to refill to the original contour of the land and maintain that contour as the fill packs down?
4. Is the pipeline company obligated to remove and save the top soil from the easement area separately, to replace the topsoil and reseed with whatever grass was there originally and in general to restore the easement area to its original condition?
5. Will you have rights to use the surface in any manner that does not interfere with the pipeline?
6. Will the pipeline company agree to avoid important trees and not to remove or trim trees without your consent?
7. Will the pipeline company agree to mark the pipeline route with durable and permanent markers?
8. Will the pipeline company agree to be responsible for any damages that are caused directly or indirectly by the installation, operation, maintenance or removal of the pipeline?
9. Does the easement terminate if it is unused for a certain length of time?
10. Will there be above-ground equipment along the pipeline route? If there is going to be above-ground equipment, are you going to be separately and appropriately compensated for it?
11. Will you get a separate payment for the easement and for damages?

These can be major issues if not properly addressed in the easement. For example, if there is no right on your part to declare an unused easement to be abandoned, that easement will show up on your title forever, even if it has not been used for many years. This can create a major impediment to future uses of your property. You can try to get a release of the easement, but the pipeline company may not exist any longer, and there may be no one to sign a release. You may even need to file a suit and obtain a court order to declare the easement terminated.

In connection with above-ground equipment, this can include valves, gas compressors (that can be very loud and messy) loops or pig entry sites or measurement equipment (that may interfere with irrigation equipment).

Regarding payments, currently easement payments are taxed as capital gains but damages payments are not taxable. If you get one check and the payment for the easement is combined with the payment for damages, the IRS may well assume that the entire payment is taxable.

If you are the kind of person who takes out their own appendix, then by all means, negotiated your own pipeline easement. However, the small amount you pay an attorney to review and negotiate that easement now is very likely going to save you a lot of expense and distress in the future!

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October 17, 2008

Texas Oil and Gas Lawyers and Working Interest Owners: Beware of Those Assignments!

As an oil and gas attorney representing clients throughout Texas, I have had many occasions to draft an assignment of one party's interest in a well or a joint operating agreement to another, such as when a well is sold and the first operator's rights under the operating agreement are assigned to the new operator, or when the original owner of a non-operating working interest sells their interest to a new entity. Most assignments contain language that provides that the assignor is no longer liable for claims and expenses in connection with the wells after the date of the assignment, and also provide that the assignee indemnify the assignor for these expenses.

There is an old saying in the oil patch that once you have been involved with an oil or gas well, you are always potentially liable. A Texas Supreme Court case in 2006, as well as a federal court case in 2008, illustrate this point. In the first case, Seagull Energy E & P, Inc. v. Eland Energy, Inc., the Texas Supreme Court held that Eland, as an intermediate assignee of an oil and gas lease, remained liable for costs and expenses arising pursuant to a joint operating agreement, even though the costs occurred after Eland had sold and assigned all of its interest in the leases to an unrelated third party. The Court based its decision on two facts: 1) the joint operating agreement was silent on the question of the liability of a working interest owner after it sold its interest; and 2) the assignment did not contain a release of liability that was agreed to by both Seagull, as operator, as well as the new owner.

DSCF3070.JPG Not surprisingly, after this opinion was issued, oil and gas practitioners made certain that their forms met the criteria described in the Seagull case. Unfortunately, even terminology that met the Seagull criteria failed to protect a working interest owner in GOM Shelf, LLC v. Sun Operating Limited Partnership 2008 WL 901482 (S.D. Tex. 2008). In GOM, despite language in the joint operating agreement like that required by the Seagull decision, the Court held that: 1) the obligation to plug and abandon the wells accrued prior to the date of the assignment; and 2) the plugging and abandonment liability was not expressly released by the release language in the joint operating agreement. As a result, the former interest owner was held liable for plugging costs.

I guess there are really two lessons here. The first is to be careful who you sell your interest to. If the new interest owner is a thinly capitalized sham company trying to make a quick buck, who folds without meeting their obligations under the operating agreement and the Texas Railroad Commission rules, you may get the bill when the Railroad Commission is looking for someone to pay for well plugging and clean up. Secondly, it is probably good insurance to have an oil and gas attorney draft the necessary documents when you are selling or acquiring an interest in oil and gas properties. While in oil and gas law, as in life, there are no guarantees, you will at least have the full benefit of all protections offered by the law at that time. I can guarantee one thing: the cost of proper documentation is light years less than the cost of remediation of an abandoned well site.

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September 18, 2008

Talk to an Oil and Gas Attorney Before You Sign That Lease!

As an oil and gas attorney representing clients from all over Texas and from all over the world who have land in Texas, I have been getting quite a number of calls from people who signed a document before consulting an attorney and have lived to regret it, I'm sorry to say. It is apparent that there are a number of scams going on out there. One woman I talked to said that she was presented with a document that she was verbally told was merely permission to do seismic testing on her land. The document turned out to be an oil and gas lease. The terms were not very favorable to her and were substantially less than what the oil company was offering other lessors. Another woman called me recently to say that her elderly mother had signed a document that had been verbally represented to be an oil and gas lease. The document turned out to be a mineral deed, which means the woman had sold her minerals in their entirety forever!

859795_himba_1.jpgPlease folks, do not sign anything until you have a lawyer look at it. There are many honest oil companies and land men and women out there. However, even the honest oil companies are not going to offer you their best lease deal at first. In addition, oil and gas is an area that has its own language and concepts, and unless you have an oil and gas background, you are not going to be familiar with these. Finally, be aware that an oil and gas lease, in most cases, continues for as long as there is paying production, so that lease may be in place for your lifetime or longer.

Where a lease or deed has been obtained fraudulently, you may be able to sue to get the lease or deed canceled, but that is usually going to be a long, expensive and uncertain process. Please do yourself a favor: 1) do not sell your minerals, only lease them; 2) have an oil and gas attorney look at any document before you sign it, whether it is a seismic testing agreement, a pipeline easement or an oil and gas lease; and 3) please tell your elderly relatives to call you immediately if they are approached to sign anything, and not to meet with anyone about signing documents unless you are present.

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August 14, 2008

Texas Oil and Gas Lawyer Needed!

As a Texas oil and gas attorney representing clients from all over the country with oil and gas leases in Texas, I am continually amazed at how many people sign an oil and gas lease without reading it!

959230_himba_3.jpgMy flight instructor used to have a rule he would use when I was doing something bad while I had the plane and he wanted me to stop it immediately because I was getting ready to kill both of us. He called it "Rule 13" and it meant "Whatever you are doing, stop it!" To all of you folks out there who sign a lease without reading it, or who read a lease and don't understand it or who don't understand the legal ramifications of what you are signing, I would say: "Rule 13...Don't do that!". In most cases, I can negotiate with the oil company to make changes that will make the lease much more fair and much more favorable to you. In almost every lease I have negotiated, the oil company has accepted most, if not all, of these changes. For most leases, I charge a very modest set fee. Many of my clients find that the increase in their bonus or royalty check more than pays for my legal service. An oil and gas lease is a serious legal contract that is going to control your land, in many cases, for many years to come. So please seek legal advice before you sign that lease!

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