OIL AND GAS INDUSTRY SPECIAL EDITION cAPITAL Editor: Kate Glaze March 2014 Special Oil and Gas Industry Edition

Carrington Coleman’s Oil and Gas Practice IN THIS ISSUE Our oil and gas experience runs deep. We’ve been doing Dallas Drilling Ordinance Makes significant work for companies in the oil and gas business for J.R. Ewing Persona Non decades, handling deals of all kinds, resolving disputes, and Grata ...... 1 advising clients effectively in building and protecting their energy Jorge I. Gutierez businesses and holdings. We’ve worked in the international energy industry, as well, and have the experience to meet our clients’ needs — whatever, and wherever, they may be. Maneuvering The Traps Of CFIUS To Enable Chinese Investment In With respect to energy deals, Carrington Coleman can help guide clients in all areas including: U.S. Energy Assets ...... 4 acquisitions & divestitures; energy project finance (both debt and equity); lending transactions; David G. Drumm joint development and exploration agreements; farm-outs; entity formation & capitalization; acquisitions of processing plants, pipelines, and other midstream facilities; oil & gas leasing; environmental counseling on compliance and remediation; and mergers & acquisitions. San Antonio Court of Appeals Issues Important Opinion in When things don’t go as planned, we have the experience and knowledge—and importantly, Chesapeake Royalty Dispute . . . 5 the trial lawyers—to guide our clients through. We’ve worked extensively with independent Richard A. Rohan exploration and production companies in all of the following: disputes with landowners, under joint operating agreements, with investors, or with purchasers of oil and gas; defending clients in critical suits involving fiduciary duties, financings, buyout negotiations, mergers, and Dealing With Suspense Accounts domestic and foreign operations; counseling boards of directors and executives in critical For Mineral Interest Production. . 7 business litigation and corporate governance matters; and counseling creditor’s committees, Corbet F. Bryant, Jr. trustees, and secured lenders in insolvency proceedings involving oil and gas companies.

Dallas Drilling Ordinance Makes J.R. Ewing Persona Carrington Coleman Welcomes Non Grata Jorge Gutierrez Jorge’s practice primarily focuses By Jorge I. Gutierrez on representing small and mid- 214.855.3056 | [email protected] sized independents operating in Dallas may be home to the Ewing family, the barons of the oil and gas industry, but the City the Texas shale plays and the of Dallas rolled up the welcome mat to J. R.-wannabe’s. In December 2013, the Dallas City Permian Basin. He is Board Council amended its natural gas drilling ordinances, which now make it difficult, at best, to Certified in Oil and Gas Law by the 1 develop minerals within the city limits. Texas Board of Legal Specialization and prior to The amended ordinances added and tightened drilling rules in a variety of ways, but the most becoming an attorney had a career significant is a 1,500-foot setback between “protected use” areas such as homes, businesses and churches and operation sites for drilling rigs and compressor stations. To provide some in corporate and investment perspective, 1,500 feet is more than a quarter of a mile; it is the length of five football fields. banking, where he primarily This distance is five times the buffer zone under the old ordinance, and it is two and half times advised oil and gas companies in the buffer zone established in the City of Fort Worth. Dallas and the City of Flower Mound raising senior secured debt. now have the distinction of having the strictest setback distances in North Texas.

The amended ordinances have important implications for mineral owners, the oil and gas industry, and the taxpayers in Dallas. Unfortunately for these constituencies, their voices were not nearly as loud and influential as those of industry opponents.

How Did We Get Here? The City of Dallas adopted the central elements of its natural gas drilling ordinances in 2007, at a time when activity in the Barnett Shale was racing at full speed. Throughout the region, mineral owners were offered ever-increasing bonus payments as consideration for an oil and gas lease. At the time, market prices for natural gas were approaching historically high levels, which translated into large royalty checks for the mineral owners. continued on page 2

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continued from page 1

Not wanting to miss out on the action, in 2008, the City of Dallas solicited bids to grant oil and gas leases covering city-owned land. The city ultimately selected certain oil and gas companies, which paid tens of millions of dollars for the rights to explore, develop and produce the oil and gas minerals, if any, on thousands of acres of city-owned land.

These companies applied for city-issued permits to begin their respective drilling programs, but the applications languished for years. It seems the delay was due to growing complaints, inside and out of City Hall, from groups opposed to the oil and gas industry. Finally, the City Council declared that it could not make a decision until it determined whether the city’s natural gas drilling ordinances were outdated. To that end, the City Council created a Gas Drilling Task Force in June 2011, and directed it to review the city’s gas drilling and production regulations and determine whether updates or revisions were necessary.

The task force took its charge seriously. Between July 2011 and February 2012, the group met 22 times. 2 This included hearing presentations from federal and state regulatory agencies, from other North Texas cities, and from the gas drilling industry and environmental and neighborhood groups. 3 In May 2012, four years after the city granted its oil and gas leases, the task force presented the City Council with recommended amendments to the gas drilling ordinances.

At that point, the City Plan Commission (the “CPC”) began to review the proposed revisions. 4 It is unclear to the author what transpired after May 2012, as the CPC did not commence the first of eight topic workshops until May 2013. Finally, in September 2013, the CPC recommended to the City Council that it adopt certain amendments to the natural gas drilling ordinances. However, the CPC-endorsed amendments went beyond the recommendations of the task force in certain important respects.

Summary of Amendments The Dallas Gas Drilling Task Force and CPC recommended many amendments to ordinances regulating the operations for gas drilling and production, mostly addressing environmental and nuisance issues. On their face, those provisions seem reasonable, albeit duplicative, in some cases, of existing regulations at the state level. However, the value of those requirements is made worthless because of the practical effect of the other amendments that were adopted. Specifically, the council adopted the CPC’s setback requirements and expanded definition of protected uses that are subject to the setbacks. These create an impossibly high hurdle for oil and gas companies. The table below summarizes changes to the protected use definition and setback requirements, comparing the adopted amendments against the original ordinance and the recommendations of the task force.

With respect to the measurement of the setbacks, the beginning point of the 1,500-foot distance is the boundary line of the “operation site” of gas drilling, production and associated operational activities, as that operation site was identified in the specific use permit application. The ending point of the setback distance depends on the nature of the protected use, varying from (i) the property line, (ii) the closest point of a structure housing the protected use when the activities are conducted exclusively inside, or (iii) the closest point of a physical barrier or demarcation that establishes a boundary of the protected use when the activities are not exclusively inside. 6

In all cases, the setback distance is measured from the beginning point to the end point in a straight line, without regard to intervening structures or objects.

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The amended ordinances also added a requirement to the specific use permit-granting process. Before issuing such a permit, the CPC and City Council must consider the proximity and potential impact of the proposed gas drilling and production use to an “Environmentally Significant Area.” This is a new term that is defined to include, among other factors, an area: - with slopes greater than three to one; - containing endangered species of either flora or fauna; - identified as wetlands or wildlife habitat; or - containing more than 1,000 inches of trunk diameter of protected trees, in the aggregate, within a 10,000 square foot area. To be included in the aggregate calculations, a tree must have a trunk diameter of six inches or more. In light of the city’s dense population and development, it will be difficult, at best, for an oil and gas company to locate an operations site that satisfies the quarter-mile setback requirement. The most likely locations are undeveloped tracts of land owned by the city, except that much of that land falls under the “public park” category. However, even assuming the operator and the tract in question satisfy the setback and other requirements, the issuance of a specific use permit for operations on a public park requires the approval of 3/4 of the council. Given the adamant opposition to mineral development voiced by 9 of the 15 council members that voted in favor of the amended ordinances, it is unlikely such a permit will be issued.

The Result: Dallas Loses All told, it is estimated that the City Council heard 100 hours of public input on this matter, in addition to the public and private meetings of the Gas Drilling Task Force and the CPC. These extensive deliberations lend the appearance that city officials and appointees sought to In the end, Dallas make an informed decision after identifying and scrutinizing the relevant issues and weighing the competing interests of environmentalists, property owners, and the oil and gas industry. Taxpayers and other owners of mineral However, the drawn-out process, coupled with public comments from city officials and the interests in the city ultimate city staff recommendations, tend to indicate that industry opponents were working to ensure the amended ordinances, once adopted, were sufficiently strict to effectively ban limits will suffer natural gas drilling in Dallas. The long timeline can also be viewed as an attempt to slow-play from the actions the process in hopes that drilling companies would simply go away. If true, industry of the City Council. opponents were successful. XTO Energy Inc., which was granted oil and gas leases covering city-owned lands, ultimately abandoned its plans and the leases terminated before the company could commence drilling operations.

In the end, Dallas taxpayers and other owners of mineral interest in the city limits will suffer from the actions of the City Council. When oil and gas companies resume actively drilling natural gas wells, those companies will invest their capital in communities that set reasonable (and achievable) restrictions on drilling and production activities. The actions of the council deprive Dallas taxpayers of the financial benefits gained by other Texas communities, including business relocations, jobs, and tax-generating investments. The Dallas taxpayers and other mineral owners will also be deprived of the lease royalty attributable to natural gas that would otherwise be produced within the city limits.

In the near term, Dallas taxpayers may be faced with a more definite financial hit. Trinity East Energy, LLC paid the City of Dallas approximately $19,000,000.00 in bonus for the oil and gas leases it took in 2008, and then alleges it spent millions more in preparing a development plan. 7 After the City Council denied the company’s permit application, Steve Fort, president of Trinity East, said the company was evaluating its legal options, because, according to Mr. Fort, “We feel like we paid for something here that we’re not receiving.” 8

Unlike the typical J. R. Ewing cliff hangers, we didn’t have to wait long to learn what happened next. On February 13, 2014, Trinity East filed a lawsuit against the City of Dallas alleging breach of contract, fraud, and an unconstitutional taking. The company seeks to recover $30,000,000 it invested in this project plus the recovery of lost profits. 9

Rest assured that this is not the last we’ve heard on this matter. For the sake of Dallas taxpayers and mineral interest owners, we hope that there is a happy ending to this story. ______1. Dallas City Ordinance 29228, www.ci.dallas.tx.us/cso/resolutions/2013/12-11-13/13-2139.PDF . 2. City of Dallas City Council Agenda Item #96, December 11, 2013. 3. Id. 4. The City Plan Commission is responsible for making recommendations to the City Council regarding planning and zoning matters. 5. The reference is to the Texas Parks and Wildlife Code Chapter 26 (“Protection of Public Parks and Recreational Lands”). In general, under Chapter 26, before a city can allow a party to use a public park for some other purpose, the city must conduct a public hearing and determine that there is “no feasible and prudent alternative” to the proposed use of such land and the proposed project includes all reasonable planning to minimize harm to the land, as a park, resulting from the proposed use. 6. Examples of physical barriers or demarcations include fencing around activity areas (e.g., playing fields or pools) or edges or boundaries of maintained areas adjacent to trails, golf courses, or active recreation areas. 7. “Dallas Debate Shows City Power to Limit Drilling,” The Texas Tribune, October 18, 2013. 8. Id. 9. Trinity East Energy, LLC v. City of Dallas , Texas, Cause No. DC-14-01443, District Court, Dallas County, Texas, K-192ND Judicial District.

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Maneuvering the Traps of CFIUS to Enable Chinese Investment in U.S. Energy Assets

By David G. Drumm 214.855.3032 | [email protected]

It was only six years ago that the U.S. was focused on increasing To mitigate the risk of uncertainty as to whether an acquisition is imports to meet its demand for oil and natural gas, as U.S. oil vulnerable to being set aside by the President or not, CFIUS was production had been falling for decades. 1 Since then, with the created to screen transactions and advise the President. development and refinement of technologies used in oil and gas exploration, drilling, and production activities, the tables have FINSA was enacted in the wake of the withdrawal of a bid to turned. The U.S. Energy Information Administration reports that acquire California-based oil and gas company, Unocal, in 2005, natural gas production from new wells is outpacing declines in by the Chinese government-owned China National Offshore Oil existing wells and that the gap between domestic oil production Corp. (“CNOOC”). The bid was met with loud objection from and consumption is beginning to narrow, and that U.S. production politicians worried that the deal threatened national security. of oil and gas has surpassed that of traditional power players like CNOOC withdrew its bid as a result of complications and delays Russia and Saudi Arabia. 2 associated with the CFIUS process prior to the enactment of FINSA. This growth in U.S. reserves and production has led to foreign investors trying to get a collective foot in the door of the U.S. FINSA provides a more definite process for foreign acquirers to industry. 3 The capital inflow is coming from several sources, but obtain a clear answer as to whether their proposed acquisition a significant amount is from Asian countries, and China, in will be permitted, as opposed to the uncertainty of the process particular, has been one of the most active investors in the U.S. CNOOC was presented with in the Unocal takeover bid. Under energy industry. 4 Key factors driving Chinese investment the FINSA procedures, an acquirer can make a filing of its include that China has surpassed the U.S. as the largest energy intended acquisition with CFIUS, which starts a 30-day time clock consumer, crude oil imports account for over half of total Chinese for CFIUS to either approve the transaction or to commence an demand, and its domestic hydrocarbon production is declining. 5 investigation within a 45-day period following the initial 30-day For U.S. oil and gas companies, the foreign investment provides review period. The goal is for there to be certainty as to whether the money required to fund capital improvements, infrastructure CFIUS will recommend to the President that the transaction presents a national security threat within no later than the build-out, and new projects. 6 combined 75-day period and hopefully, within the shorter 30-day period. Most foreign investment has taken the form of acquiring a non- controlling interest in a U.S. company, rather than buying an In determining whether to investigate a pending acquisition filed existing company or creating a foreign-owned startup company. under FINSA, CFIUS will focus primarily on the following three This strategy allows the investor to learn alongside the U.S. factors: partner and rely on it to maneuver the complex regulatory framework, but avoid assuming all of the risk associated the (a) whether control over a U.S.-owned business is being venture. Generally speaking, the U.S. government is receptive to acquired, foreign investment, but there have been well-reported objections resulting from transactions that were blocked by the Committee (b) whether the U.S. business being acquired is in possession on Foreign Investment in the United States (“CFIUS”). As a of “national security assets” or “critical infrastructure,” and result, CFIUS was developed a reputation for being a deal killer. 7 (c) whether the foreign acquirer of control is perceived as likely Regulatory Review to control or restrict access to the acquired assets for purposes Prospective investors are naturally concerned with the need for of political or military advantage, as opposed to maximizing U.S. regulatory approval for any acquisitions and in particular the profits for its shareholders. approval of CFIUS. CFIUS is an inter-agency committee that is authorized to review transactions that could result in control of a The pattern of application of these factors in the reported cases U.S. business by a foreign person (“covered transactions”), in coming before CFIUS in the case of potential Chinese buyers order to determine the effect of such transactions on the national has been along the following lines: security of the United States. 8 CFIUS was created initially under Executive Order issued in 1975, and then by statute under the 1. If the foreign investor acquires a 51% or greater interest Foreign Investment and National Security Act of 2007 (“FINSA”), in producing oil and gas wells, it will be considered to have which amended the provisions of Section 721 of the Defense acquired control over a United States business. By reducing the Production Act of 1950. percentage ownership acquired to the range of 35-40%, it may be possible to obtain an understanding with the CFIUS staff, even There is no actual requirement that a foreign investor obtain the before a formal filing, that the proposed acquisition is not a approval of CFIUS or any other U.S. federal government agency “covered transaction” subject to the jurisdiction of CFIUS. prior to making its acquisition of U.S. energy assets. The risk, However, with a 51% interest, there is no question that control is however, is that the President of the United States could act to being acquired and that CFIUS has jurisdiction to evaluate the unwind the acquisition after it is closed if the President acquisition. determines that such transactions present “credible threats to United States national security” under FINSA.

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2. Producing oil and gas wells are considered to constitute $1.4 billion venture with Devon for a 30% interest in certain shale “critical infrastructure” if they represent “major energy assets.” assets; and Chinese state-owned Sinochem Group’s $1.7 billion There is no safe harbor threshold in terms of valuation or quantity investment for a 40% stake in certain of Pioneer Natural of production that determines whether “energy assets” are “major” Resources’ shale assets. or “minor,” although obviously the smaller the acquisition, the more likely that the assets will determined not to be “major.” Given the fundamentals of the American energy industry, there Other factors would include whether pipelines or processing and should be continued strong foreign-investor interest in oil and gas transmission facilities are being acquired which serve critical assets in this country. When proposed transactions are properly military and other industrial installations to the point that if they structured to meet the established guidelines of CFIUS, foreign are shut off, there is no alternative source of supply. investors should consider the U.S. energy industry is open for business. 3. Historically, acquisitions of a controlling interest in a ______U.S.-owned business by Chinese acquirers have been given 1. Theresa A. Einhorn, “Developments and Trends In Oil and Gas Financing greater scrutiny than acquisitions by non-U.S. acquirers from 2013,” 31st Annual Review of Developments in Business Financing, American Bar Association Business Law Section, Spring Meeting 2013. nations that have historically been military allies of the United 2. Charles Dewhurst and Clark Sackschewsky, “Globalization of US Energy,” States. However, “covered transactions” by Chinese nationals Oil & Gas Financial Journal, February 2014. have been frequently approved by CFIUS, particularly where 3. “Globalization of US Energy,” Oil & Gas Financial Journal, February 2014. 4. See “Globalization of US Energy,” Oil & Gas Financial Journal, February CFIUS is satisfied that the acquirer is not subject to the control of 2014; Dave Fehling, “Why Foreign Companies Love Texas (Hint: Oil & Gas),” the Chinese government. StateImpact Texas, December 11, 2013; Ryan Dezember and James T. Areddy, “China Foothold in U.S. Energy,” Wall Street Journal, March 6, 2012. 4. The chances of approval are increased if (a) a Chinese 5. “Developments and Trends In Oil and Gas Financing 2013,” 31st Annual Review of Developments in Business Financing, American Bar Association Business buyer is owned by private shareholders and not the Chinese Law Section, Spring Meeting 2013 government, and (b) the quantity of assets being acquired by the 6. “Globalization of US Energy,” Oil & Gas Financial Journal, February 2014. buyer is relatively small and therefore less likely to constitute 7. Doug Guthrie, “CFIUS: Often Misunderstood and Maligned,” Forbes, December 20, 2013. “major energy assets.” 8. See http://www.treasury.gov/resource-center/international/Pages/ Committee-on-Foreign-Investment-in-US.aspx for information concerning the origins 5. A buyer could acquire nonproducing mineral leases or of CFIUS and its acquisition screening criteria and policies. unleased minerals and drill wells to produce them without being 9. Committee on Foreign Investment in the United States, Annual Report to Congress, Report Period: CY 2012, December 2013. under the jurisdiction of CFIUS, because in that case, they would 10 . Id. not be acquiring a U.S. business. The regulations under CFIUS 11 . Id. are clear that acquisitions of hard assets which are not being 12 . Id. 13 . Id. Hong Kong is reported as a separate country in the CFIUS report. operated as a business at the time of the acquisition do not 14 . Id. constitute a covered transaction.

CFIUS’s Track Record A review of statistics from CFIUS indicates that this committee is San Antonio Court of Appeals not a deal killer as it has been characterized. Between 2008 and Issues Important Opinion In 2012, there were a total of 538 notices filed with CFIUS that were Chesapeake Royalty Dispute deemed “covered transactions,” and on average, 31% were subject to further investigation. 9 In some cases, during the investigation process, the parties to a transaction will re-file their By Richard A. Rohan notice after addressing initial concerns of CFIUS. For example, 214.855.3043 | [email protected] in 2012, CFIUS reviewed 114 notices of transactions and all were approved except for 22. 10 With respect to those 22 covered The San Antonio Court of Appeals recently issued an important transactions, the parties withdrew their notices, but 10 re-filed opinion in a royalty dispute between a prominent Fort Worth later in 2012 and were concluded successfully and two were family and Chesapeake Exploration L.L.C. and its affiliate, refiled in 2013. 11 Of the remaining 10 cases, the parties Chesapeake Operating, Inc. (“COI”). In Chesapeake Exploration abandoned the transaction for commercial reasons or in light of LLC v. Hyder, the Hyders successfully advanced the argument that Chesapeake was not entitled to deduct post-production CFIUS’s national security concerns. 12 expenses from the royalties reserved by them out of an oil and gas lease entered into in 2004. Hyder leased approximately The most recent report of CFIUS indicates that 39 acquisitions 1,000 acres of land in Johnson and Tarrant Counties to Four were filed by Chinese acquirers and three by Hong Kong Sevens Oil Company, Ltd., which lease was later assigned to acquirers. 13 Twelve of those acquisitions were in the industry 14 Chesapeake and COI. The royalty clause that applied to wells sector “mining, utilities, and construction.” located on and producing from the leased premises granted Hyder a 25% royalty and provided “the royalty reserved herein by Since the failed bid in 2005 by CNOOC to acquire Unocal, [Hyder] shall be free and clear of all production and post- CNOOC and other Asian companies have successfully closed on production costs and expenses . . . or any other costs and substantial transactions in the U.S. oil and gas industry. This expenses incurred between the wellhead and [Chesapeake’s] includes Chinese state-owned SINOPEC’s $2.2 billion joint point of delivery or sale of such share to a third party.” (Opinion, venture with Devon Energy for a 33% interest in certain shale p. 4) At trial, both parties stipulated that Chesapeake incurred assets; two transactions between CNOOC and Chesapeake unaffiliated third-party transportation costs of $1.75M between the Energy valued at $2.2 billion and $1.3 billion for a 33% interest in point of delivery and point of sale. certain shale assets; Japanese company Sumitomo Corporation’s continued on page 6

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continued from page 5 language, effectively exclude post-production costs notwithstanding the general rule that royalties are subject to such costs. Perhaps more significant is the court’s ruling in In its suit, Hyder argued that the “free and clear” language connection with a cross-appeal point brought by Hyder to claim a precluded Chesapeake from deducting these transportation costs royalty on gas that was lost and unaccounted for. Such gas is from Hyder’s royalty. Chesapeake countered that the language lost between the wellhead and the point of sale. Although such “any other costs and expenses incurred between the wellhead gas is produced, it is not sold, because it never reaches the point and [Chesapeake’s] point of delivery or sale of such share to a of sale to the third party. Nevertheless, Hyder sued for royalties third party” was disjunctive and allowed Chesapeake to deduct on this lost gas. In support of its argument, Hyder contended costs and expenses incurred after the point of delivery but before there was a transfer of gas at the wellhead between COI and the point of sale to a third party. The trial court disagreed with another Chesapeake affiliate, Chesapeake Energy Chesapeake following a bench trial, and the San Antonio Court Manufacturing, Inc. (“CEMI”). As a result, Hyder argued, the of Appeals affirmed the trial court’s ruling. wellhead is the point at which Chesapeake actually received a price for its gas, thereby triggering Hyder’s entitlement to a In its discussion, the Court of Appeals noted that a royalty is royalty thereon. normally subject to post-production costs, including transportation costs, but that parties were free to modify this The court rejected Hyder’s argument. In doing so, the court general rule by agreement, citing the landmark case of Heritage concluded that even if production were measured at the Resources, Inc. v. NationsBank , 939 S.W.2d 118, 121-22 (Tex. wellhead, because COI and CEMI were affiliates, this transfer of 1996). Applying traditional contract rules of construction, the gas between affiliates “does not constitute a sale to a ‘third court rejected Chesapeake’s interpretation because it ignored the party.’” (Opinion at 14) (Significantly, Hyder and Chesapeake “free and clear” language in the royalty clause and was therefore stipulated that COI and CEMI are affiliated companies. As a contrary to the plain reading of that clause. To the extent the consequence, the questions whether they were affiliates, and general rule permitted deduction of post-production expenses whether a transfer among them constituted a transfer to a third from an oil and gas royalty, the court found the parties had party, were not litigated to the court.) Without a third-party sale, modified the general rule in their agreement by expressly Chesapeake owed no royalty obligation to Hyder. excluding post-production costs and expenses. It is important to note that the Hyder lease contained a lease A second royalty provision in the lease reserved for Hyder “a royalty clause that is more explicit than most leases, in terms of perpetual, cost-free (except only its portion of production taxes) describing the type of post-production costs and their overriding royalty of five percent (5%) of gross production deductibility, as well as the treatment of sales to affiliates. obtained” from wells that, while drilled on the leased premises, Nevertheless, this ruling by the Court of Appeals may prove were producing from land adjacent to or near the leased significant in other litigation matters pending against premises (“off-lease wells”). The parties disagreed as to the Chesapeake, and in other royalty cases, where the issue in meaning and scope of the term “cost-free.” Chesapeake again dispute is where and when in the production/post-production contended that “cost-free” applied to production costs, but not to process ought a sale to be counted for purposes of calculating post-production costs, which under the general rule in Texas the price paid for minerals and the resulting royalty to be paid to were deductible from the payment of overriding royalties. Hyder royalty owners. Claims asserted by litigants against countered that “cost-free” referred to all costs, including post- Chesapeake, and in other royalty litigation generally, often production costs. pertain to affiliate transfers of petroleum products, and the impact such transfers have on royalties owed. One recurring contention As to this claim as well, the court sided with Hyder and held that is that the price utilized by the lessee to calculate royalties is the “cost-free” meant free of all costs, including post-production result of a transfer to an affiliated entity at an artificially low price, costs. The court began its analysis recognizing that post- and that a downstream purchase by an unaffiliated party must be production costs are normally borne proportionately by both the used in order to calculate the correct royalty (sometimes after operator and the royalty interest owners, citing Martin v. Glass, adjusting for costs to get the oil or gas to the point of sale 571 F. Supp. 1406, 1415 (N.D. Tex. 1983), aff’d , 736 F.2d 1524 downstream). In the Hyder opinion, the court recognizes the (5th Cir. 1984). Again, however, the court noted that under distinction between an affiliate “sale” and one to an unaffiliated Heritage , parties to an oil and gas lease were free to modify the third party. As alluded to above, the court’s observation that COI general rule by agreement. Chesapeake argued that the trial and CEMI are affiliated may not in itself carry much if any court erred by failing to take account of the general rule when precedential value in other Chesapeake litigation, since that construing the royalty at issue, and that the term “cost-free” must affiliation was stipulated to by the parties. But the differential be construed in light of the general rule that an overriding royalty, treatment afforded by the court to affiliated vs. non-affiliated while free of production costs, is subject to post-production costs. sales may prove to be a significant point in subsequent royalty Chesapeake cited a number of state court cases from Texas and litigation. Oklahoma in support of its position. The Court of Appeals, however, distinguished them based upon differences in the The principle holdings from the Hyder opinion, therefore, are that royalty language found in each of those cases from the parties to an oil and gas lease are free to modify the general rule overriding royalty language in the Chesapeake-Hyder lease. The in Texas that royalties are subject to post-production expenses. court concluded that Chesapeake’s proffered interpretation would The court also provides examples of language that successfully render the term “cost-free” meaningless and would require it to, accomplish such a modification. A corollary pronouncement by in effect, rewrite the parties’ agreement. the court, that transfers of oil and gas between affiliates did not create a third-party sale sufficient to trigger a lessee’s obligation The court’s rulings on the two royalty provisions provide comfort to pay a royalty, may find its way into other royalty lawsuits going to royalty owners that they may, through express royalty forward.

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order which include the name, address, and taxpayer Dealing With Suspense Accounts identification number of the payee, the fractional interest, the For Mineral Interest Production description of the property, and the effective date of the division order as well as a provision authorizing suspension of payment in the event of a title dispute or adverse claim on the production By Corbet F. Bryant, Jr. 15 claimed by the payee. The operator also has the duty to 214.855.3008 | [email protected] provide specific detailed information on payment stubs to royalty 16 A “suspense account” is a tool often used in double entry owners. accounting to park funds temporarily during a period of Texas courts have declined to impose a fiduciary duty on uncertainty about the identity of the owner or difficulty in 17 delivering the funds. 1 It is widely used by businesses to cope operators holding production proceeds. Operators have often with currently held unclaimed monies and intangible rights as commingled those varied as uncashed dividend checks, unused gift or loyalty funds and used them A “suspense account” reward cards, and pre-paid burial services. State officials, such for internal business 18 is a tool often used as the Texas Comptroller, regularly employ suspense accounts operations. for taxes paid under protest 2 and similar funds. Suspense in double entry accounting The wise operator accounts are not a recent innovation. Texas courts have to park funds reviewed the use of suspense funds involving Texas citizens will establish and enforce standard since at least 1900. 3 temporarily during a procedures based upon the statutory period of uncertainty Operators’ Use of Suspense Accounts requirements to be Operators 4 use suspense accounts for problems concerning about the identity of followed by trained mineral proceeds for the full range of mineral interests: royalties, employees who are the owner or overriding royalties, production payments, bonuses, delay rentals, collecting signed difficulty in delivering shut-in royalties, minimum royalties, net revenue interests, and division orders and working interests. The issues that might create the need for a the funds. 5 information from suspense account include a cloud on title, a bad address, a royalty interest failure of an owner to provide a tax identification number, and owners. Such compliance offers a safe harbor for the operator in pending litigation over the interest. the event of litigation by a royalty owner.

The Texas Natural Resources Code A second portion of Texas statutory law that bears upon specifies the required conduct of disbursement of mineral proceeds is the Texas escheat statute operators as to production revenues, set forth in the Texas Property Code. That Code creates a including holding funds in suspense. presumption of abandonment for proceeds held for three years The operator must keep books showing while unclaimed by the owner. 19 An operator must determine the amount of oil and gas produced and abandoned property in its possession as of June 30 each year the sales price. 6 That information may 7 and deliver that property to the Texas Comptroller no later than be inspected by any royalty owner. November 1 of that year. 20 The operator must begin paying royalty owners by 120 days after 8 Besides complying with the Natural Resources Code and the end of the month of first production. Thereafter, payment is Property Code, an operator will want to minimize overhead costs due by 60 days after the end of each month oil is sold or 90 days and risks of paying proceeds twice. It also should want to after the end of each month gas is sold, unless the contract maintain its reputation for good business practices and not 9 between the operator and royalty owner states otherwise. The become known for “slow pay.” Striking the right balance among operator may also wait until the end of the month in which at all of those sometimes competing goals can be challenging. least $100 in due payments have accumulated, but no later than 10 12 months. Royalty Owner Remedies On occasion a royalty owner may accept an operator’s use of a Payments may be withheld in suspense without interest beyond suspense account. Suspense may seem fully justified if the those time limits only in any of three circumstances. The first is royalty owner has failed to do a necessary act such as furnish a where there is a dispute concerning title that would affect social security number. Also, if the hang-up results from bitter distribution of payments. 11 The second is when there is litigation over title, the owner may take some comfort that at least reasonable doubt that a payee may have sold its share of the owner’s adversary is not getting the suspense funds. More production or may not have clear title to the interest in the often, however, the royalty owner will feel frustration with the lack proceeds. 12 The third justification for withholding payment is a of payment the owner has been anticipating for months since requirement in a title opinion that places in issue the title, identity, learning of the initial production. or whereabouts of the payee which was not satisfied by the payee after a reasonable request by the payor for curative When that disappointment is severe enough to cause the royalty information. 13 owner to seek relief and no legitimate excuse for the delay is apparent, there are various avenues available. Since the Texas In addition, a signed division order from the payee is a Natural Resources Code prescribes the appropriate use of prerequisite to the duty to disburse proceeds. 14 The Natural suspense accounts by operators, a lawsuit for failure to pay Resources Code specifies the permissible contents of the division continued on page 8

Carrington, Coleman, Sloman & Blumenthal, L.L.P. • 901 Main Street, Suite 5500 • Dallas, Texas 75202 • www.ccsb.com Page 7 Capital - March 2014 Special Oil and Gas Industry Edition continued from page 7 should be based upon a violation of Chapter 91 of that Act. 16 . Tex. Nat. Res. Code Ann. §§ 91.501-502. Claims for conversion, breach of contract, and unjust enrichment 17 . HECI Exploration Co. v. Neil , 982 S.W.2d 881, 888 (Tex. 1998). Strangely, it has been imposed in a criminal context. Coleman v. State , 131 S.W.3d 303, are typically added. If the operator is contesting title, then a 308 (Tex. App.–Corpus Christi–Edinburg 2004, pet. ref’d ). count in the petition to quiet title is needed. A request for a 18 . See Mitchell Energy Corp. , 80 F.3d 976, 981 (5th Cir. 1996); Phillips declaratory judgment 21 is the standard vehicle to establish the Petroleum v. Adams , 513 F.2d 355, 360 (5th Cir. 1975). 19 . Tex. Prop. Code. Ann. § 75.101. royalty owner’s right to the mineral proceeds. 20 . Tex. Prop. Code. Ann. § 74.301. The operator is subject to audit by the State to ensure compliance with both the Texas Natural Resources Code and A demand letter must be sent at least 30 days before institution the Property Code. If another state enters the fray to battle Texas over 22 escheated mineral proceeds, the state of the last known address of the royalty of the lawsuit. The royalty owner should also review the lease owner has priority. Texas v. New Jersey , 379 U.S. 674, final decree 380 U.S. and division order to ensure that there are no alternate dispute 518 (1965). resolution steps required, either a mediation before filing or 21 . Tex. Civ. Prac. & Rem. Code § 37.001 et seq . arbitration in lieu of litigation. Venue for the suit is in the county 22 . Tex. Nat. Res. Code Ann. § 91.404(a). The written demand is not deficient 23 if the operator (or oil buyer) with the suspense account had all the information where the well is located. necessary to be apprised of the demand. Koch Oil Co. v. Wilber , 895 S.W.2d 854, 865 (Tex. App.–Beaumont 1995, writ denied ). In addition to the suspended monies, the successful plaintiff can 23 . Tex. Nat. Res. Code Ann. § 91.404(c). Oddly, a suit by a lessee-operator 24 25 for a declaratory judgment on the computation of royalties does not have to be recover attorneys’ fees and pre-judgment interest. The brought in the county of the well. Yzaguirre v. KCS Resources, Inc. , S.W.3d four-year statute of limitations applies. 26 532, aff’d on rehearing 53 S.W.3d 368 (Tex. 2001). 24 . Tex. Nat. Res. Code Ann. § 91.406. 25 . The interest is calculated at two percentage points above the New York If a third party has caused the creation of Reserve rate charged depository institutions, unless a different rate of interest the suspense account through claiming is specified in a written agreement between the payor and the payee. Tex. Nat. title, then that party should be the primary Res. Code Ann. § 91.403. It is not available if there was a legitimate title dispute. Concord Oil Co. v. Pennzoil Exploration and Production Co. , 966 defendant in a declaratory judgment suit S.W.2d 451, 461 (Tex. 1998); Headington Oil Co. L.P. v. White , 287 S.W.3d with tort claims against that party as may 204, 210 (Tex. App.–Houston [14th Dist.] 2009, no pet.). appear appropriate. Usually, the 26 . Koch Oil Co. v. Wilber , 895 S.W.2d 854, 864 (Tex. App–Beaumont 1995, writ denied ). operator, as stakeholder with the 27 . Tex. Civ. Prac.; & Rem. Code § 37.001, et. seq. suspense funds, is also joined in such a 28 . Tex Rule Civ. Proc. 43. lawsuit. Absent wrongful conduct by the operator, the award of attorneys’ fees would be only available against the miscreant third party based on the Declaratory Carrington Coleman’s Oil and Gas Attorneys Judgment Act, 27 not the Natural Resources Code. The operator could itself initiate an interpleader naming the parties claiming the royalties as defendants and placing the proceeds in the Transactions Litigation registry of the court. 28 Bonnie C. Barksdale Corbet F. Bryant, Jr. If an inability of the operator to identify the royalty owner or [email protected] [email protected] successfully deliver funds is the reason for the suspense account 214.855.3119 214.855.3008 and more than three years elapses, the operator will pay the monies into the state Comptroller’s office in accordance with the David G. Drumm Neil R. Burger Property Code. Thereafter, the royalty owner must pursue its [email protected] [email protected] remedies through the Comptroller’s office dealing with unclaimed 214.855.3032 214.855.3076 funds. ______Kate Glaze James E. Coleman, Jr. 1. Suspense accounts may also be used for costs, accounts receivable or [email protected] [email protected] other subjects which are doubtful or uncertain. 214.855.3145 214.855.3005 2. Sunoco Terminals v. Bullock , 756 S.W.2d 418 (Tex. App.–Austin 1988, no writ). Tex. Gov. Code § 403.035. Jorge I. Gutierrez 3. See New York Life Ins. Co. v. Scott , 57 S.W. 677 (Ft. Worth 1900, writ Thomas S. Connor [email protected] ref’d). [email protected] 4. Sometimes an operator may delegate to another entity, such as the 214.855.3056 214.855.3076 purchaser of production, the responsibility for disbursing payments from production revenues. If one well produces oil and gas, then two different Amanda L. Thurman Rodney H. Lawson production purchasing companies may be the source of royalty payments. [email protected] [email protected] Such delegation does not release an operator from its duties to the mineral 214.855.3143 interest owners unless a contract with the royalty owner expressly does so. 214.855.3054 Williams v. Baker , 767 S.W.2d 193, 196 (Tex. App.–Waco 1989, writ denied) The royalty owner has a security interest in the mineral proceeds which is very Jim A. Watson Alex More helpful in an operator or purchaser bankruptcy. Tex. Bus. & Com.. Code § [email protected] [email protected] 9.343. 214.855.3014 214.855.3053 5. E.g., a l is pendens. Manges v. Guerra , 673 S.W.2d 180 (Tex.1984). 6. Tex. Nat. Res. Code Ann. § 91.141(a). 7. Tex. Nat. Res. Code Ann. § 91.141(b). John R. Wilcox Richard A. Rohan 8. Tex. Nat. Res. Code Ann. § 91.402(a). [email protected] [email protected] 9. Id. 214.855.3001 214.855.3043 10 . Tex. Nat. Res. Code Ann. § 91.402(c)(1). 11 . Tex. Nat. Res. Code Ann. § 91.402(b)(1). 12 . Tex. Nat. Res. Code Ann. § 91.402(b)(2). Neal J. Suit 13 . Tex. Nat. Res. Code Ann. § 91.402(b)(3). [email protected] 14 . Tex. Nat. Res. Code Ann. § 91.402(c)(1). 214.855.3046 15 . Id. The division order may also include an indemnity and hold harmless provision from the owner protecting the payor. § 91.402(d).

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