The Arkansas Supreme Court ruled against landowners who challenged to the authority of a gas gathering system to use the power of eminent domain to acquire rights of way. In Ralph Loyd Martin Revocable Trust v. Arkansas Midstream Gas Services Corp., a landowner challenged whether a gas gathering system's condemnation was for a public use pursuant to Ark. Code Ann. 23-15-101. (2010 Ark. 480). The court ruled that the gas gathering system is for public use because the system was available to multiple royalty owners and working interest owners from many different drilling units with equal access for all at a fixed rate. In industry language, the gathering system was a "common carrier."
A gathering system provides a conduit for gas from a wellhead to reach larger interstate pipelines. Without the power of eminent domain, it would be difficult for the public to have access to natural gas. Landowners should be aware--as this case illustrates--that challenges to eminent domain cases for reasons other than the amount of compensation are seldom successful. It takes a truly egregious abuse of eminent domain to mount a successful challenge on the merits. Just 5 years ago, the United States Supreme Court upheld a taking of property for purely economic reasons. See Kelo v. City of New London, 545 U.S. 469 (2005).
The Court also re-examined the Statutory Pugh Clause codified at Ark. Code Ann. 15-73-201. Southwestern Energy Production Co. v. Elkins, 2010 Ark. 481. A bit of background is necessary for those readers who do not understand the basics of oil and gas leases. When a well begins to produce, an oil and gas lease enters its secondary term. The secondary term continues until there is no longer a commercially viable oil or gas well. A lease holder may drill wells perpetually to extend the secondary term.
But suppose all of the drilling takes place on one tract, but the lease also covers tracts several miles away. A standard oil and gas lease always has some language to the effect that operations on one part of the lands extend to the whole of the leasehold. Therefore, a well on one part of the leasehold holds all lands covered by the lease into the secondary term. This idea is also incorporated into Ark. Code Ann. 15-73-201. If one area of the leasehold is very attractive and easy to develop, it may be decades before the operator gets around to developing the less attractive areas. This is a source of frustration for many landowners. Enter a Lousiana lawyer named Pugh. Lawyer Pugh drafted a simple clause to remedy the problem:
If at the end of the primary term, a part but not all of the land covered by this lease, on a surface acreage basis, is not included within a unit or units in accordance with the other provisions hereof, this lease shall terminate as to such part, or parts, of the land lying outside such unit or units, unless this lease is perpetuated as to such land outside such unit or units by operations conducted thereon or by the production of oil, gas or other minerals, or by such operations and such production in accordance with the provisions hereof.
Put simply, when operator finishes the drilling started in the primary term, the lease becomes severable, freeing up the lands the operator failed to develop.
In response to outrage by mineral owners who did not see all of their lands developed in a timely manner, the General Assembly enacted the following as Ark. Code Ann. 15-73-201:
Lease extended by production -- Scope
(a) The term of an oil and gas, or oil or gas, lease extended by production in quantities in lands in one (1) section or pooling unit in which there is production shall not be extended in lands in sections or pooling units under the lease where there has been no production or exploration.
(b) This section shall not apply when drilling operations have commenced on any part of lands in sections or pooling units under the lease within one (1) year after the expiration of the primary term, or within one (1) year after the completion of a well on any part of lands in sections or pooling units under the lease.
(c) The provisions of this section shall apply to all oil and gas, or oil or gas, leases entered into on and after July 4, 1983.
The plain reading of this statute is that an operator must continue drilling, or lose the lease. This is not quite a Pugh clause, but it is close. In the latest case examining this statute, the landowner plaintiffs attempted to re-argue the correct interpretation of the statute. The court did not see fit to alter the interpretation it adopted in Snowden v. JRE Investments, 2010 Ark. 276. That is, the plain reading of the statute prevailed, and in this case, the operator complied with what the statute required. Like the Snowden case, this case drew some dissenting opinions. The gist of those dissents is that the General Assembly meant to write a true Pugh clause, but as the dissenters note, it is up to the General Assembly to change its statutes, not the courts.
Landowners should not rely on the so-called statutory Pugh as true Pugh clause because it isn't one. When writing this law, the General Assembly compromised between the operator and landowner viewpoints. The statute ended the days landowners languishing over the operator sitting on a single well to hold a leasehold spread over a large area, but it also allowed the operator a reasonable cushion of time for development. Like all other aspects of an oil and gas lease, a landowner can negotiate for true Pugh clause.
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.
Wednesday, December 15, 2010
Sunday, December 12, 2010
Arkansas Oil and Gas Commission Approves Hydraulic Fracturing Rule, Places Moratorium on Enola Swarm Disposal Wells, Rules in Favor of Operators on Mineral Owner Contested Dockets
At its December meeting, the Arkansas Oil and Gas Commission adopted proposed rule B-19 to disclose the constituents of hydraulic fracturing fluids. There was little fanfare and little debate on the adoption of the rule. Representatives of CARE, The League of Women Voters, and Halliburton proposed changes to the proposed rule at the hearing. With minor modification, the Commission adopted the rule. The final proposed rule can be found here. The rule will take effect on January 15, 2011. This will make Arkansas the third state to require disclsoure of the chemical makeup of fracturing fluid.
In a Commission staff docket, Director Larry Bengal proposed a moratorium on new disposal wells in the following townships: 6N-12W, 6N-11W, 7N-11W, 7N-12W, 7N-13W, 7N-14W, 7N-15W, 8N-11W, 8N-12W, 8N-13W, 8N-14W, 9N-11W, 9N-12W, 9N-13W, Sections 7-36 of 8N-15W, Sections 25-36 or 9N-14W. These Townships are in the area of the Enola Swarm, a cluster of seismic activity that began in 1982 around the Faulkner County town of Enola. This was due to the existence of some circumstantial evidence that the disposal well activities may induce seismic activity. The Commission granted the moratorium. During the moratorium period, the Arkansas Geological Survey, the Arkansas Oil and Gas Commission, United States Geological Survey, and the Center for Earthquake Research and Information will study whether the disposal wells have some effect on seismic activity in the area. The oil and gas industry uses disposal wells to inject used drilling fluids deep into the earth so that fluids cannot migrate into fresh water aquifers or the biosphere. The Commission will hear the results of the studies at its July 2011 hearing.
There were several contested dockets at the December hearings, most of which were between operators, but there were three contested dockets involving a mineral owner's challenge to an integration order. In two of these dockets, the heirs of a long deaceased mineral owner made some novel arguments to the Commission about the remedy due them for being missed in an integration application, and in the other docket, the same heirs contested whether the operator exercised reasonable efforts to find the long dead mineral owner's heirs.
In the dockets testing the remedy available for being missed in an integration application, the operator conceded that it failed to determine the existence of the mineral owner's interest in the original integration proceeding. The heirs argued that they were entitled to punitive measures along with the right to split their election between participation for completed wells and leases for proposed wells. The Commission declined to extend punitive measures because the relief was out of the Commission's jurisdiction. The Commission recognized that the statutes requiring interest and penalties for operators who fail to pay royalties are causes of action in court rather than before the Commission. The Commission also upheld its policy of disallowing split elections for parties missed in the original integration.
In the docket testing reasonable efforts to locate missing mineral owners, the Commission placed the burden to prove the inadequacy of the efforts on the heirs. The heirs utilized two landmen to demonstrate how to find these particular missing heirs. In this case, the heirs were located in Texas. The only evidence in Arkansas of a link to Texas was the acknowledgement in the last deed of record from the heirs' predecessor in title. The heirs put on evidence that a search of the probate records in the Texas counties shown in the acknowledgment would have turned up the heirs. The operator put on evidence of its efforts, which were extensive and included some search of Texas records, but not the probate records in the counties shown on the deed acknowledgment. The Commission ruled that the heirs did not meet their burden to show that the operator's heirs were unreasonable.
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.
In a Commission staff docket, Director Larry Bengal proposed a moratorium on new disposal wells in the following townships: 6N-12W, 6N-11W, 7N-11W, 7N-12W, 7N-13W, 7N-14W, 7N-15W, 8N-11W, 8N-12W, 8N-13W, 8N-14W, 9N-11W, 9N-12W, 9N-13W, Sections 7-36 of 8N-15W, Sections 25-36 or 9N-14W. These Townships are in the area of the Enola Swarm, a cluster of seismic activity that began in 1982 around the Faulkner County town of Enola. This was due to the existence of some circumstantial evidence that the disposal well activities may induce seismic activity. The Commission granted the moratorium. During the moratorium period, the Arkansas Geological Survey, the Arkansas Oil and Gas Commission, United States Geological Survey, and the Center for Earthquake Research and Information will study whether the disposal wells have some effect on seismic activity in the area. The oil and gas industry uses disposal wells to inject used drilling fluids deep into the earth so that fluids cannot migrate into fresh water aquifers or the biosphere. The Commission will hear the results of the studies at its July 2011 hearing.
There were several contested dockets at the December hearings, most of which were between operators, but there were three contested dockets involving a mineral owner's challenge to an integration order. In two of these dockets, the heirs of a long deaceased mineral owner made some novel arguments to the Commission about the remedy due them for being missed in an integration application, and in the other docket, the same heirs contested whether the operator exercised reasonable efforts to find the long dead mineral owner's heirs.
In the dockets testing the remedy available for being missed in an integration application, the operator conceded that it failed to determine the existence of the mineral owner's interest in the original integration proceeding. The heirs argued that they were entitled to punitive measures along with the right to split their election between participation for completed wells and leases for proposed wells. The Commission declined to extend punitive measures because the relief was out of the Commission's jurisdiction. The Commission recognized that the statutes requiring interest and penalties for operators who fail to pay royalties are causes of action in court rather than before the Commission. The Commission also upheld its policy of disallowing split elections for parties missed in the original integration.
In the docket testing reasonable efforts to locate missing mineral owners, the Commission placed the burden to prove the inadequacy of the efforts on the heirs. The heirs utilized two landmen to demonstrate how to find these particular missing heirs. In this case, the heirs were located in Texas. The only evidence in Arkansas of a link to Texas was the acknowledgement in the last deed of record from the heirs' predecessor in title. The heirs put on evidence that a search of the probate records in the Texas counties shown in the acknowledgment would have turned up the heirs. The operator put on evidence of its efforts, which were extensive and included some search of Texas records, but not the probate records in the counties shown on the deed acknowledgment. The Commission ruled that the heirs did not meet their burden to show that the operator's heirs were unreasonable.
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.
Thursday, December 2, 2010
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.
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.
Thursday, September 30, 2010
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.
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.
Tuesday, September 7, 2010
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.
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.
Tuesday, August 24, 2010
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.
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.
Wednesday, August 18, 2010
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. This is an expensive and time consuming undertaking and it requires a staff of many professionals including attorneys and title searchers. To make this an economically feasible endeavor, my company takes a fee from the property recovered. This enables my company to keep doing business and avoids any out of pocket expenses by people like you.
I believe you have claims to minerals in Arkansas. I would like the opportunity to discuss this with you at your earliest convenience. Please give me a call at 555-555-5555.
Best Regards,
John Heir Finder
The prospect of easy and needed money with no strings attached is enough to entice anyone to at least make the call. One who makes the call might ask “what exactly do I own and how much money can I expect.” Almost uniformly, the answer will be “now if I told you that, you wouldn’t need me.” At this point, a savvy person would simply get on the internet and figure out the mystery for themselves. A Google search would lead that person to the Arkansas Oil and Gas Commission (AOGC). A call to the AOGC would lead that person to the oil and gas producer escrow account records maintained by the AOGC. A review of those records, a little family research on the phone and internet, and viola! The savvy person discovers their great uncle Leo who lived in Arkansas to whom an Oil and Gas Company owes $100,000. A call to the Oil and Gas Company reveals that Leo owned 80 acres of minerals. The savvy property owner then hires an attorney, cures his title with an affidavit or probate, collects the $100,000, and enjoys the ownership of great uncle Leo’s 80 mineral acres in the Fayetteville Shale.
Not everyone, however, is savvy. Most will regard the money found as money they didn’t have and agree to whatever the heir finder proposes as what might seem to be a nominal reward for their trouble. In many cases, this is justifiable because most people don’t understand the esoteric world of oil, gas, and mineral ownership. The solicited follow up phone conversation leads the unenlightened property owner to accept the terms of the agreement offered to them. Many times, the heir finder represents the property is “a hassle” or that proving the claim will be “difficult” to sway the property owner to agree. A few days after the telephone conversation, a contract arrives in the mail with a quitclaim deed for some portion (usually half) of the minerals. Only after execution and return of the contract and deed, the property owner learns from the heir finder that the property owner’s great uncle Leo owned 80 mineral acres that was under production with $100,000 in royalties and bonus owed at the time of the agreement. To the property owner’s shock, they may learn the heir finder simply trolled the records of the AOGC and located them using free internet resources such as the Social Security Death Index or FamilySearch.org, putting nearly zero time and effort for the fee charged by the finder/locator. Fifty thousand for a few hours of effort is fantastic work if you can get it, but it smacks of injustice. Is there any recourse for the property owner?
The aggrieved property owner’s first recourse is the Uniform Unclaimed Property Act (UUPA). Arkansas is one of many states that adopted the Act, but Arkansas is unique in that it adopted the Act in essentially the same form as suggested by the Uniform Commission on State Laws. The UUPA is found at Ark. Code. Ann. § 18-28-201 et. seq. The UUPA limits compensation for property covered by the to 10% of the property's value and places other restrictions on the manner of making the contract. More importantly, this non-attenuated version of UUPA includes strong protections for property owners who are solicited for the location of actively producing mineral interests. These provisions are found at Ark. Code. Ann. § 18-28-225. Under the Act, “property” is any money held by someone with a duty to do so in their ordinary course of business. Clearly, an oil and gas producer who sells gas and retains the proceeds under a pooling order of the AOGC is doing so in the ordinary course of their business. Once the order is effective and the lease bonus payable, the Act protects the property owner because there is money available from the interest, making it “property” under the Act. Any contract, "the primary purpose of which is to locate, deliver, recover, or assist in the recovery of property” that includes “mineral proceeds not then abandoned” or “a portion of the underlying minerals” is void. Under Ark. Code. Ann § 18-28-403, mineral proceeds become “abandoned” after 5 years of escrow with the producing Oil and Gas Company’s. Thus, under the fact sketch above, there is simply no valid contract between the property owner and the heir finder because the UUPA does not permit any of the compensation called for by the agreement. As of the posting date of this writing, there is probably no production from the Fayetteville Shale that qualifies as “abandoned.” The property owner should be able to set aside any mineral deeds and obtain restitution of all non-abandoned mineral proceeds paid to the heir finder. The UUPA, while untested in the Arkansas Courts, is a powerful weapon for property owners victimized by unjust heir finding contracts.
A second statutory recourse is the Deceptive Trade Practices Act codified at Ark. Code Ann. § 4-88-101 et. seq. The Act provides a cause of action against anyone who “knowingly” takes “advantage of a consumer who is reasonably unable to protect his or her interest because of…ignorance… or a similar factor.” The Act further prohibits the use of “any deception, fraud, or false pretense” and “the concealment, suppression, or omission of any material fact with intent that others rely upon the concealment, suppression, or omission.” There is also a catch all provision prohibiting “any other unconscionable, false, or deceptive act or practice in business, commerce, or trade.” A property owner may obtain full restitution and reasonable attorney’s fees under the Act. If the property owner is elderly (defined by the Act to be more than 60 years old) or disabled as defined by the act, punitive damages are available. The aforementioned provisions of UUPA are likely cognizable under the Deceptive Trade Practices Act, providing a means for a property owner to obtain reasonable attorney’s fees and possible punitive damages in addition to restitution.
An aggrieved property owner’s final avenue of relief is the common law. It is possible to rescind the contract for unilateral mistake if it is shown the heir finder engaged in misconduct. A court can entertain a claim that the contract was unconscionable. Contract-based common law remedies provide for reasonable attorney’s fees. Where the heir finder makes representations about the property based on superior knowledge, the property owner may have a claim for constructive or actual fraud, depending on the specific facts. Claims of fraud are difficult and expensive to litigate, but provide the possibility of punitive damages.
Aggrieved property owners should act quickly to preserve their rights. The real estate recording acts will protect subsequent purchasers of minerals. If the heir finder leases, mortgages, or sells the minerals to a third party, it will be nearly impossible to recover the minerals (though restitution from the heir finder is still possible). Additionally, each of the claims above have a statute of limitations of between 2 and 5 years. The longer the property owner waits, the more difficult it becomes to recover property lost under an heir finding agreement. After enough time, all claims to regain the property will become barred by limitations.
This post should also be considered by independent landmen, attorneys, and anyone else in the mineral-buying business. Most consider the practice of looking up lost heirs as shrewd business, but few are aware of the UUPA and the serious consequences of failing to make full and transparent disclosures about the property to the lost heirs of a mineral owner. Property owners with letters in hand from heir finders or lost property locators should contact an attorney prior to signing or agreeing to any heir finding or property location agreement.
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.
Dear Sir/Madam,
I am with a company that helps others find lost property. This is an expensive and time consuming undertaking and it requires a staff of many professionals including attorneys and title searchers. To make this an economically feasible endeavor, my company takes a fee from the property recovered. This enables my company to keep doing business and avoids any out of pocket expenses by people like you.
I believe you have claims to minerals in Arkansas. I would like the opportunity to discuss this with you at your earliest convenience. Please give me a call at 555-555-5555.
Best Regards,
John Heir Finder
The prospect of easy and needed money with no strings attached is enough to entice anyone to at least make the call. One who makes the call might ask “what exactly do I own and how much money can I expect.” Almost uniformly, the answer will be “now if I told you that, you wouldn’t need me.” At this point, a savvy person would simply get on the internet and figure out the mystery for themselves. A Google search would lead that person to the Arkansas Oil and Gas Commission (AOGC). A call to the AOGC would lead that person to the oil and gas producer escrow account records maintained by the AOGC. A review of those records, a little family research on the phone and internet, and viola! The savvy person discovers their great uncle Leo who lived in Arkansas to whom an Oil and Gas Company owes $100,000. A call to the Oil and Gas Company reveals that Leo owned 80 acres of minerals. The savvy property owner then hires an attorney, cures his title with an affidavit or probate, collects the $100,000, and enjoys the ownership of great uncle Leo’s 80 mineral acres in the Fayetteville Shale.
Not everyone, however, is savvy. Most will regard the money found as money they didn’t have and agree to whatever the heir finder proposes as what might seem to be a nominal reward for their trouble. In many cases, this is justifiable because most people don’t understand the esoteric world of oil, gas, and mineral ownership. The solicited follow up phone conversation leads the unenlightened property owner to accept the terms of the agreement offered to them. Many times, the heir finder represents the property is “a hassle” or that proving the claim will be “difficult” to sway the property owner to agree. A few days after the telephone conversation, a contract arrives in the mail with a quitclaim deed for some portion (usually half) of the minerals. Only after execution and return of the contract and deed, the property owner learns from the heir finder that the property owner’s great uncle Leo owned 80 mineral acres that was under production with $100,000 in royalties and bonus owed at the time of the agreement. To the property owner’s shock, they may learn the heir finder simply trolled the records of the AOGC and located them using free internet resources such as the Social Security Death Index or FamilySearch.org, putting nearly zero time and effort for the fee charged by the finder/locator. Fifty thousand for a few hours of effort is fantastic work if you can get it, but it smacks of injustice. Is there any recourse for the property owner?
The aggrieved property owner’s first recourse is the Uniform Unclaimed Property Act (UUPA). Arkansas is one of many states that adopted the Act, but Arkansas is unique in that it adopted the Act in essentially the same form as suggested by the Uniform Commission on State Laws. The UUPA is found at Ark. Code. Ann. § 18-28-201 et. seq. The UUPA limits compensation for property covered by the to 10% of the property's value and places other restrictions on the manner of making the contract. More importantly, this non-attenuated version of UUPA includes strong protections for property owners who are solicited for the location of actively producing mineral interests. These provisions are found at Ark. Code. Ann. § 18-28-225. Under the Act, “property” is any money held by someone with a duty to do so in their ordinary course of business. Clearly, an oil and gas producer who sells gas and retains the proceeds under a pooling order of the AOGC is doing so in the ordinary course of their business. Once the order is effective and the lease bonus payable, the Act protects the property owner because there is money available from the interest, making it “property” under the Act. Any contract, "the primary purpose of which is to locate, deliver, recover, or assist in the recovery of property” that includes “mineral proceeds not then abandoned” or “a portion of the underlying minerals” is void. Under Ark. Code. Ann § 18-28-403, mineral proceeds become “abandoned” after 5 years of escrow with the producing Oil and Gas Company’s. Thus, under the fact sketch above, there is simply no valid contract between the property owner and the heir finder because the UUPA does not permit any of the compensation called for by the agreement. As of the posting date of this writing, there is probably no production from the Fayetteville Shale that qualifies as “abandoned.” The property owner should be able to set aside any mineral deeds and obtain restitution of all non-abandoned mineral proceeds paid to the heir finder. The UUPA, while untested in the Arkansas Courts, is a powerful weapon for property owners victimized by unjust heir finding contracts.
A second statutory recourse is the Deceptive Trade Practices Act codified at Ark. Code Ann. § 4-88-101 et. seq. The Act provides a cause of action against anyone who “knowingly” takes “advantage of a consumer who is reasonably unable to protect his or her interest because of…ignorance… or a similar factor.” The Act further prohibits the use of “any deception, fraud, or false pretense” and “the concealment, suppression, or omission of any material fact with intent that others rely upon the concealment, suppression, or omission.” There is also a catch all provision prohibiting “any other unconscionable, false, or deceptive act or practice in business, commerce, or trade.” A property owner may obtain full restitution and reasonable attorney’s fees under the Act. If the property owner is elderly (defined by the Act to be more than 60 years old) or disabled as defined by the act, punitive damages are available. The aforementioned provisions of UUPA are likely cognizable under the Deceptive Trade Practices Act, providing a means for a property owner to obtain reasonable attorney’s fees and possible punitive damages in addition to restitution.
An aggrieved property owner’s final avenue of relief is the common law. It is possible to rescind the contract for unilateral mistake if it is shown the heir finder engaged in misconduct. A court can entertain a claim that the contract was unconscionable. Contract-based common law remedies provide for reasonable attorney’s fees. Where the heir finder makes representations about the property based on superior knowledge, the property owner may have a claim for constructive or actual fraud, depending on the specific facts. Claims of fraud are difficult and expensive to litigate, but provide the possibility of punitive damages.
Aggrieved property owners should act quickly to preserve their rights. The real estate recording acts will protect subsequent purchasers of minerals. If the heir finder leases, mortgages, or sells the minerals to a third party, it will be nearly impossible to recover the minerals (though restitution from the heir finder is still possible). Additionally, each of the claims above have a statute of limitations of between 2 and 5 years. The longer the property owner waits, the more difficult it becomes to recover property lost under an heir finding agreement. After enough time, all claims to regain the property will become barred by limitations.
This post should also be considered by independent landmen, attorneys, and anyone else in the mineral-buying business. Most consider the practice of looking up lost heirs as shrewd business, but few are aware of the UUPA and the serious consequences of failing to make full and transparent disclosures about the property to the lost heirs of a mineral owner. Property owners with letters in hand from heir finders or lost property locators should contact an attorney prior to signing or agreeing to any heir finding or property location agreement.
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.
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