Integration necessary and no cause for concern for mineral owners

Occasionally, I receive questions from people who are upset because they got a letter from a lawyer for an oil and gas company stating that the oil and gas company applied to the Oil and Gas Commission to integrate their land. The letter includes a legal notice giving the date and time for a hearing along with instructions on how to notify the Commission of any opposition to the integration. The first reaction from most getting these letters is that they’ve been sued or the oil and gas company is taking something from them. Neither is the case, and being subject to an integration is no cause for concern.

The hearing before the Oil and Gas Commission is the culmination of months and sometimes years worth of work on the part of the oil and gas company. The company has to identify an area prospective for oil and gas, run title on the area, attempt to lease everyone in the area, and attempt to get all other companies with leases in the area to agree to the operation of the unit before going to the Commission. I will omit identification of the geology, and start with running title.

Running title is ordinarily a precursor to leasing and a must prior to integration. In order to know who owns the oil and gas, a company must check the land records at the county courthouse or in a private title plant. In some cases, oil and gas companies simply buy out a private title plant. This happened in a few instances in Fayetteville Shale Counties, allowing the plant owners to retire wealthy. The oil and gas company examines the title back to when the United States owned the land. Once they determine ownership, the companies send out landmen to make a lease offer to the mineral owner.

If the landowner and landman agree to a lease, the landowner is out of the integration process. The lessee becomes the only “interested party” in the integration. If the landowner says “no thanks” to the lease, the landman will haggle and persist for a time, sometimes until the landowner cuts off communication with the landman. At some point between negotiating and persisting, the company meets its obligation to make “reasonable efforts” to lease. There is no published case on how far a company has to go to lease, but it probably isn’t a high bar to clear. Once the company makes reasonable efforts to lease, the company (assuming it meets other requirements) may apply to the Oil and Gas Commission to “integrate” the unleased interest.

The term “integrate” is a polite term for “compulsory pooling.” The Oil and Gas Commission holds a power granted by statute to compel parties in a prospective oil and gas unit to come to an agreement as to how to share costs and revenues for the production oil and gas from the unit. The proceeding before the Commission is administrative in nature. Thus, nobody is being sued. The company seeking to operate the drilling unit is the “operator” or “applicant.” The unleased mineral owners and uncommitted working interest owners (other companies with leasehold interests) are “interested parties.” A lease mineral owner or not interested because the oil and gas lease effectively transfers the mineral owner’s interest to the control of the lessee.

A company seeking to integrate drilling unit must hold a majority leasehold acreage interest in the unit. They must prepare an application documenting their efforts to lease the unleased parties, documenting efforts to get other companies with acreage in the unit to agree to the operation of the unit, listing the drilling costs of the first well, listing the highest bonus and royalty it paid in the unit, and detailing the geological risk of drilling the well. The company gives notice of the pending integration to all interested parties by certified mail and by publication in the newspaper. Once the applicant submits the application and notice delivered, the company goes to hearing before the Oil and Gas Commission.

The hearings are usually uneventful. The company and its attorney will present the application to the Commission, and a landman representative of the company will be present to answer questions about the company’s acreage position in the unit and efforts to lease. The Commission usually has few questions for the company and will approve the application if it is in order.

Occasionally, a landowner will object or otherwise appear before the Commission at the hearing for one reason or another. The most common complaints are ownership disputes and surface use issues. The Commission has no jurisdiction to resolve either problem. The Commissioners will listen to the complaint, though they cannot take any legally binding action on ownership of surface use issues. I’ve seen this happen many times. Once the landowner finishes speaking, one of the Commissioners will explain why they cannot take action.

Sometimes, the landowner will bring an attorney. I’ve seen many times where an attorney unfamiliar with the Commission’s powers will make a number of arguments about the propriety of the proceeding. Perhaps the greatest misconception among general practice attorneys is that the Commission’s proceeding is an eminent domain proceeding. Pursuing this line of reasoning, they present arguments about the amount of compensation paid. An integration proceeding is not a “taking” under the Constitution. The proceeding is an exercise of police power by the state to prevent the drilling of unnecessary wells and the waste of a non-renewable resource.

Yet another angle taken by attorneys representing landowners is that the lease bonus and royalty stated by the applicant is not the highest paid in the section. The best known case of this is where the United States received $8,000 an acre for their acreage in a unit, and the landowner’s attorney argued that should be the highest bonus paid. The statute authorizing integration says the terms of the integration “shall be upon terms and conditions which are just and reasonable.” In that case, the attorney didn’t realize the “just and reasonable” applies to both the applicant and the unleased mineral owner. Most of Commissioners were appointed to serve because they are industry professionals. Because of their own experiences and their hearing of integration applications, they have extensive knowledge what bonus and royalty is reasonable. A common bit of industry knowledge is that leases from the United States are always sold at an extreme premium in producing areas. The Commissioners took this into consideration, and they chose to accept the applicant’s highest bonus and royalty rather than that paid to the United States.

The only points of dispute in an integration that are likely to make any headway with the Commission are deficiencies in the contents of the application or lack of a majority interest. If a landowner finds a deficiency, the applicant will move to amend the application or delay the proceeding until they can correct the deficiency. At best, this type of objection will simply buy the landowner a bit more time to find a better lease than what will be offered by the Commission. Theoretically, the landowner could object or dispute more technical things in the application such as the geological risk or the drilling costs, but doing so would require the retention of an expert such as a petroleum geologist or drilling engineer.

After the hearing, the Commission will enter and order setting forth the integrated party’s options. The applicant sends out a lease form and election letter to each unleased interest. The interested parties have 15 days after the order to make their election. For an unleased mineral owner, the options are to affirmatively accept the commission lease at the applicant’s highest bonus and royalty, do nothing and being deemed to accept the lease, participate in the well, or affirmatively reject the lease and be deemed “non-consent.” The choice to participate makes the interest owner a partner in the well. As a well partner, the interest owner must pay Joint Interest Billing Statements (JIBS) issued by the operator for well costs. For example, if well #1 costs $2,000,000 and the participating owner owns 64 acres out of a 640 acre unit, the JIBS for that owner for well #1 will be $200,000. The non-consent choice subjects the unleased mineral owner to a geological risk factor penalty of 300% to 600%. That is, the non-consenting interest gets all of the money attributable to the interest from the well, but has to forfeit 1 to 6 times the cost that would have been paid had the owner participated with the interest. In the example above, Well #1 would have to pay out 6 to 12 million before the non consenting interest sees their first payout. Typically risk factors are 300% to 400%.

Uncommitted working interest owners may either participate in the well or be non-consent. The same risk factor is imposed on non-consenting working interest owners as non-consenting mineral owners except that the royalty is paid out to the lessor and the remaining balance of the revenue goes to satisfy the risk factor.

Integration and oversight by the Oil and Gas Commission provides an important function. Without regulation, profit demands that everyone drill as many wells as possible as quickly as possible. In order to prevent the drainage by neighboring tracts, each and every landowner has an incentive to drill their own well. As a result, several expensive wells could drain one pool, scarring the surface estate of each Tract and decreasing the overall profitability of the enterprise by drilling unnecessary wells. Further, excessive wells decrease the reservoir pressure leading to lower overall recovery and the intrusion of fossil brine causing the resource to become less recoverable.

Landowners who are noticed for Integration should not be alarmed. Integration is a not a lawsuit, and nothing will be lost by being a party. Integration is fair and efficient means to give every interested party a fair share of production while minimizing economic waste, damage to the surface estate, and maximizing the overall recovery from the pool of oil or gas.

For more information about integration, consult the Arkansas Code in title 15, section 72 along with Arkansas Oil and Gas Commission Rule B-43.

The ads that appear on this site were placed by Google and are not endorsed by the author or otherwise approved by the author.

The above represents the opinion of the author and not of any organization or group to which the author may belong. This material is general information, and it is not intended to create any lawyer-client relationship. Neither the transmission nor receipt of this information is an offer to extend representation by the author. Any information, opinion, and comment provided herein should not be taken as legal advice or relied upon by the reader for any purpose. The author is licensed in the state of Arkansas. Commentary on cases and law from jurisdictions where the author does not hold license to practice are for demonstrative or scholarly purposes and do not represent the author is licensed or accepts cases in the applicable jurisdiction. If you are need of legal services, you should contact a licensed attorney in your jurisdiction.

Arkansas Oil and Gas Commission Puts Hydraulic Fracturing Disclosure Rule Up for Comment

Following Wyoming’s lead, on September 28, 2010, the Arkansas Oil and Gas Commission initiated a rulemaking to require producers to disclose the constituents of hydraulic fracturing fluid. The proposed rule B-19 is up for public comment, and if adopted, it will make Arkansas the second state to require the disclosure of the chemical constituents of fracing fluid.

The proposed rule will apply to all new wells. The rule sets requirements on casing and cementing to protect freshwater aquifers. The requirements include specifications on casing strength, depth, and cementing. The operator will have a duty to report any change in annulus pressure that might indicate a casing failure or any exceeding of the rated casing pressure to the AOGC within 24 hours. Any incident from the prior month will be reported at the next monthly meeting of the AOGC. The commission will have the discretion to take action as it sees fit to remediate the incident and prevent future incidents.

The rule also addresses wastes not already regulated by the Arkansas Department of Environmental Quality. The rule regulates the use of RCRA exempt materials and fluids used in fracturing. This includes storage in leak free containment vessels, reporting of spills, and a report of any spill to the AOGC with immediate remediation.

Under the rule, following the completion of a frac job, the operator must report a considerable amount of physical data regarding the frac job. This includes maximum pump pressure, volumes of fluid, volume of proppant, type of fluid, type of proppant, calculated fracture height. The rule will require the operator to furnish the types of additives in the frac fluid, the name of the additive, MSDS sheets, Chemical Abstract Numbers (CAS), and concentrations of the additives.

Finally, the rule imposes requirements on contractors who engage in hydraulic fracturing. Specifically, the rule mandates that contractors be authorized to do business in Arkansas, file Organization Reports as required by the AOGC, and provide MSDS and CAS numbers for the chemicals used in fracing.

The Wyoming rule requires the operator to file a form prior to initiating a well fracing, and the state retains the right to require testing of the well casing prior to fracing. The operator must provide the state detailed information about the constituents of fracing fluid, but the operator may request confidentiality from public disclosure. Under the rule, the state will know the classification, CAS numbers, rate, and concentration of every constituent of fracing fluid. In addition, the rule requires the operator to keep records of each frac job, including physical measurements of pressure at the surface, downhole, and in the production casing annulus. The operator must report any annulus pressure that exceeds 500 psi immediately. The rule further requires the reporting of the disposition of any fluids recovered from the frac job.

The Arkansas and Wyoming rules are similar in many respects. Their purpose is to collect data regarding critical control points in the frac job which might lead to the intrusion of frac fluids into groundwater, to insure proper storage and disposal of frac fluids, and to inform the public of the exact composition of frac fluid. There is no doubt the new rule will go far to keep the public’s confidence, but it will be a burden on oil and gas producers.

For better or worse, hydraulic fracturing garners controversy. E&P companies should monitor the ongoing EPA study, the Waxman and Markey congressional investigation of fracing, and the any proposed fracing regulations of oil and gas producing states such as Arkansas, Louisiana, Texas, Oklahoma, North Dakota, Wyoming, Colorado, West Virginia, and Pennsylvania where there are active tight oil and gas plays. If the states take proactive measures to police fracturing and gain the public’s confidence, federal regulation might be avoided.

The ads that appear on this site were placed by Google and are not endorsed by the author or otherwise approved by the author.

The above represents the opinion of the author and not of any organization or group to which the author may belong. This material is general information, and it is not intended to create any lawyer-client relationship. Neither the transmission nor receipt of this information is an offer to extend representation by the author. Any information, opinion, and comment provided herein should not be taken as legal advice or relied upon by the reader for any purpose. The author is licensed in the state of Arkansas. Commentary on cases and law from jurisdictions where the author does not hold license to practice are for demonstrative or scholarly purposes and do not represent the author is licensed or accepts cases in the applicable jurisdiction. If you are need of legal services, you should contact a licensed attorney in your jurisdiction.

EPA Rulemaking for Disposal of Coal Combustion Residuals Progresses

The EPA is nearing the end of a lengthy saga to regulate coal combustion residuals also commonly known as “fly ash.” The EPA issued a proposed rule on June 21, 2010, and began a series of nationwide hearings to receive public input on August 30, 2010.

The EPA proposes to regulate the disposal of fly ash in landfills and surface impoundments under the the Resource Conservation and Recovery Act (RCRA). The justification for the use of RCRA is toxicity. Certainly, the 2008 retention pond failure in Harriman, Tennessee is not far from the EPA’s memory. The EPA cites the Harriman accident as one of its proven damage cases, noting that “[s]ampling results for the contaminated residential soil showed arsenic, cobalt, iron, and thallium levels above the residential Superfund soil screening levels.” According to the EPA, fly ash contains potentially toxic metals such as Antimony, Arsenic, Barium, Beryllium, Cadmium, Chromium, Lead, Mercury, Nickel, Selenium, Silver, and Thallium. The EPA proposes two competing approaches under RCRA: 1) As a “special waste” under subpart C of RCRA; 2) As a “solid waste” under subpart D of RCRA.

The former option is the more expensive one for ratepayers. Under subpart C, the federal government or the states (under state implementation plans) will issue permits to dispose of fly ash. The permitting body will have authority to impose financial assurance, monitoring requirements, and closure requirements. Additionally, the permitting agency will have enforcement authority. In general, the EPA will require liners to separate the disposed of fly ash from the soil, a leachate collection system, and groundwater monitoring systems for new landfills and additions to existing landfills. For existing landfills, the EPA will require only groundwater monitoring wells.

The subpart C regulation requires retrofitting of existing surface impoundments with a liner and the impounded waste to meet land disposal restrictions. This, in effect, phases out surface impoundments within 5 years of the final rule. Additionally, the subpart C option imposes requirements on storage and transport of fly ash.

The subpart D option attenuates the authority of the state and federal government, lowering the costs to generators and ratepayers. The subpart D option does not require permits. Instead, citizens (including states) will enforce the regulations through citizen suits. There will be no direct requirement for financial assurance unless the EPA uses authority under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA). There are no requirements for storage and transport of fly ash. New and existing landfills are treated substantially the same under subpart D and subpart C. Surface impoundments receive less scrutiny under subpart D. The rule requires existing impoundments to retrofit with liners within 5 years or close, but there are no land disposal requirements to meet and a retrofit will allow the facility to continue to receive fly ash. New impoundments will require a liner, but there are no land disposal restrictions.

Because coal remains America’s largest power source, the EPA faces a difficult rulemaking. According to the Energy Information Institute, coal accounts for 337,300 megawatts or about 30% of the USA’s electricity generating capacity. In Arkansas, coal accounts for about 50% of electric generation capacity. America’s coal burning generates 136,000,000 tons of fly ash per year, with 37% or 50,320,000 tons recycled for uses like road base and cement. About 22% or 29,920,000 tons goes into surface impoundments (large ponds filled with fly ash sludge), 8% or 10,880,000 tons as filling for abandoned mines, and 34% or 46,240,000 tons in landfills. Presently, there is no federal regulation of fly ash disposal. The stakes are high for the electric power generators and the ratepayers who rely on them, as the cost of disposal under proposed federal regulations will range from $587,000,000 to $1,500,000,000 per year adding between 0.2% to 0.8% to consumers’ electric bills. The rate figures published by the EPA are averages. Doubtlessly, Arkansas ratepayers will suffer disproportionately because of Arkansas’ higher than average coal generation capacity.

The ads that appear on this site were placed by Google and are not endorsed by the author or otherwise approved by the author.

The above represents the opinion of the author and not of any organization or group to which the author may belong. This material is general information, and it is not intended to create any lawyer-client relationship. Neither the transmission nor receipt of this information is an offer to extend representation by the author. Any information, opinion, and comment provided herein should not be taken as legal advice or relied upon by the reader for any purpose. The author is licensed in the state of Arkansas. Commentary on cases and law from jurisdictions where the author does not hold license to practice are for demonstrative or scholarly purposes and do not represent the author is licensed or accepts cases in the applicable jurisdiction. If you are need of legal services, you should contact a licensed attorney in your jurisdiction.

Recent Wind Leasing Activity in Arkansas

It surprised me to learn that a commercial wind generation project exists in Arkansas. David Smith gave a lengthy write up of the project in the August 22, 2010, Democrat Gazette. TradeWind Energy proposes to erect 165 foot tall wind turbines on Star Mountain in Searcy County. Why is this surprising? Based on the figures from National Renewable Energy Laboratory (NREL), Arkansas has less than spectacular potential for commercial wind generation. The data show Arkansas to have around 9,200 megawatts of capacity for turbines 80 meters above the ground with a Gross Capacity Factor of 30% or more (30% is the threshold at which commercial potential begins). This places Arkansas at about the 44% percentile among the lower 48 states. Contrast this with other states such as Texas (1,901,529 MW), Oklahoma (516,822 MW), and Kansas (952,370 MW). The potential in Arkansas is appreciably better at 160 meters above the ground. At 160 meters, Arkansas rates at about the 57th percentile with about 50,000 megawatts of capacity.

The available land area for wind development in Arkansas is about 1.34% and 7.25% at 80 and 100 meters, respectively. Contrast this to states like Nebraska and Kansas (91% and 89%, respectively at 80 meters and up) where one can put a wind turbine just about anywhere.

As for specific areas of interest in Arkansas, the average wind speed maps published by the NREL show most of the higher average wind speeds to be in the highest elevations in the state (Ouachita, Boston, and Ozark Mountains). If a wind project locates in Arkansas, it is very likely to happen in an area like Searcy County. The turbines will be very tall and on top of mountains and ridges. A company that locates in Arkansas will face large construction costs because of the difficulty in constructing on mountain and ridge tops. This cost could be offset by close proximity to transmission lines in locales with higher than average wind speeds.

Even though the potential for wind energy in Arkansas is limited, the fact there is activity merits consideration of wind leasing. With a 30% federal production tax credit for wind energy and the availability of USDA Rural Energy for America Program grants to fund up to 25% of a qualified wind project, the interest in marginal wind areas like Arkansas will continue. I will give the anatomy of a wind lease and compare it to the oil and gas lease with some considerations for landowners and their attorneys.

Much like an oil and gas lease, the wind lease has a “primary term” or upfront period where the operator assesses the potential to develop the resource. In an oil and gas lease, the operator may come upon the land to conduct seismic surveys, drill test wells, and so forth. The equivalent of the primary term in a wind lease is the “development period,” “option period,” or “option phase.” In this post, I’ll call it the “option period.” In the wind lease, the option period consists of coming upon the property to measure wind speeds over time, constructing apparatuses for measurement, and conducting necessary environmental surveys. The term “option period” is a fitting label because the operator pays for the right to investigate the site, but is under no obligation to develop the property. During the option period, the wind operator will pay base rent to the land owner for the right to “explore” the property for wind potential. Base rent is much like an oil and gas lease’s bonus or delay rental payments. If the site meets the operator’s standards, the operator will carry the lease into the next phase.

Following the option phase is the construction phase. This is a unique aspect of wind leases. The construction phase is akin to the waning hours of the oil and gas lease’s primary term where the oil and gas company must begin drilling a well. To keep the wind lease in force, the wind company must begin construction of the wind plant. This might include things like site clearing, road building, and general construction activities. This is the oil and gas equivalent of “commencing operations” and “continuous operations.” A poorly negotiated lease may not limit the construction period or provide additional money for the construction phase. If this is the case, the landowner may find his or her land encumbered by the lease with no serious prospect of royalties. A landowner friendly wind lease should provide some limit on the amount of time the operator has to construct the wind turbines and should provide additional compensation above the base rent.

Once the operator constructs the wind turbines, the lease enters the operation phase–the oil and gas lease equivalent of the secondary term–where the wind operator begins to produce electricity. This phase is sometimes called the “operation period,” “generating period,” or “generating phase.” It is in this phase where the landowner begins to collect royalties from electricity sales. In general, the royalty paid to the landowner will be the higher of the base rent or a percentage of the power sold to the grid. The operation phase should last for the life of the wind turbines or some pre-determined length of time. The operation phase will likely last decades. The landowner should obtain a fixed time limit on the operation phase along with a constraint on the useful life of the turbines such as the ability of the operator to turn a profit off power generation.

The final phase of the wind lease life cycle is the decommissioning phase. Other terms are the “termination phase,” “termination period,” “reclamation phase,” or simply “decommissioning.” Once the wind project becomes obsolete or unprofitable, the operator should remove the wind turbines and restore the site to its original condition. Under Arkansas law, an oil and gas lease carries an implied duty to restore the land to its original state after the end of the secondary term. It is very likely Arkansas Courts would impose the same implied duty on a wind operator, but it is better to obtain an express covenant in the lease itself. Also, unlike oil and gas operators who answer to the Arkansas Oil and Gas Commission (AOGC), a wind operator answers no regulatory body with regard to abandoned operations. By rule and statute, the AOGC requires financial assurance from an oil and gas well operator to plug wells and remove equipment in the event the operator becomes insolvent. Without a governing body to compel financial assurance, a landowner may find themselves with several abandoned wind turbines on their property costing hundreds of thousands of dollars to remove. A landowner should require the operator to post financial assurance to guarantee the removal of the equipment at the end of the operating phase.

A landowner friendly lease should address the problems inherent to each of the phases. The problem of surface use and damages is inherent at every phase, and the lease should provide some general provisions on compensation for surface use interference and damages. Many of the standard clauses addressing this issue in oil and gas leases are directly applicable to a wind lease. A landowner should also seek a general indemnity from the wind operator and require the wind operator to carry insurance in an amount sufficient to satisfy potential claims. Much like an oil and gas lease, the wind lease royalty clause should be carefully drafted and scrutinized. The royalty clause should address what the operator can and can’t deduct from the landowner’s royalty.

There are many challenges and rewards facing a landowner who has the prospect of a wind project on their property. Noise, aesthetic concerns, interference with communications signals, and the threat of nuisance lawsuits from neighboring landowners are a few challenges that come to mind. Landowners should also be prepared for the location of power substations and transmission facilities on their land in addition to the turbines. The rewards are also considerable. The landowner has the potential to make a “windfall” profit and the satisfaction of being part of the “green economy.” The landowner should weigh the challenges and rewards carefully, and consult with the attorney of their choice prior to signing a wind lease.

The ads that appear on this site were placed by Google and are not endorsed by the author or otherwise approved by the author.

The above represents the opinion of the author and not of any organization or group to which the author may belong. This material is general information purposes, and it is not intended to create any lawyer-client relationship. Neither the transmission nor receipt of this information is an offer to extend representation by the author. Any information, opinion, and comment provided herein should not be taken as legal advice or relied upon by the reader. The author is licensed in the state of Arkansas. Commentary on cases and law from jurisdictions where the author does not hold license to practice are for demonstrative or scholarly purposes and do not represent the author is licensed or accepts cases in the applicable jurisdiction.

Finder’s Fees and “Lost” Mineral Rights in Arkansas–What to Know When You’ve Agreed to an Heir or Property Finding Contract.

In tough economic times such as these, a letter like this in the mail provides welcome news:

Dear Sir/Madam,
I am with a company that helps others find lost property.  I believe you have claims to minerals in Arkansas.  Our fees are just 40% of the amount of the property recovered.   Please give me a call at 555-555-5555.
Best Regards,
John Heir Finder

What’s wrong with this picture?

By Arkansas law, a non-attorney cannot accept a fee of more than 10% in an heir-finding contract.  In other words, the “finding” portion of the fee can only be 10%.  The example solicitation is 4x times the fee for a non-attorney heir finder.   The non-attorney heir finder will not be able to represent you in Court.  You may have to pay for the attorney on top of the heir finder’s fee!

If you’ve signed a contract with a non-attorney heir finder that is in excess of 10%, then you may have a case under the Arkansas Unclaimed Property Act.  Give attorney Mark Robinette a call at 501-251-1076 for a case evaluation.  You can recover all of your money in excess of the 10%, sometimes more!

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