Introduction. The Royalty Clause. Gas Royalty Disputes on the Rise. A publication by Navigant s Energy Practice» April 2014.

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1 A publication by Navigant s Energy Practice» April 2014 Contents 1 Gas Royalty Disputes on the Rise 5 Natural Gas Market Charts 8 Legislative and Regulatory Highlights 10 About Navigant Gas Royalty Disputes on the Rise Introduction Litigation related to unconventional oil & gas plays has been steadily increasing. One of the most common types of disputes concerns the proper payment of royalties by producers to mineral rights owners. This article examines the royalty clause, the types of disputes that most commonly arise, and some of the factors leading to increases in royalty disputes, particularly in shale plays. The Royalty Clause Typically, the royalty rate is defined in the lease agreements as a fixed percentage point of the share of oil and gas production quantities, with 12.5% being the most common royalty rate percentage. However, royalty rates have fluctuated more in recent years, ranging from 12.5% to 25%, or even higher. In some areas of the country, bonuses have been as much as $25,000 or more per acre and royalty rates have approached 30% and higher. Example of a Common Royalty Cause» The royalties to be paid by Lessee are as follows: On oil, one-eighth of that produced and saved from said land, the same to be delivered at the wells or to the credit of Lessor into the pipe line to which the wells may be connected. Lessee shall have the option to purchase any royalty oil in its possession, paying the market price therefor prevailing for the field where produced on the date of purchase. On gas, including casinghead gas, condensate, or other gaseous substances, produced from said land and sold or used off the premises or for the extraction of gasoline or other products therefrom, the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold at the wells the royalty shall be one-eighth of the amount realized from such sale. 1 The contract language in the example (see callout box) addresses oil and gas resources separately due to the distinct nature of each product as well as the differences in what is required to deliver each product to market. Operators can store oil tanks near the well, or they can use small pipelines or trucks to bring to a central shipping point, from which it can be transferred to a mainline crude pipeline, railroad, truck or waterway carrier that delivers the product to refinery markets. Since natural gas is a more complicated product, operators cannot store it economically at the production site. Operators typically use gathering systems to aggregate natural gas, which is often compressed and processed before it can be injected into the longer haul pipeline facilities. Consequently, oil royalties can be paid in kind, while gas royalties are paid only by money. 1 American Association of Professional Landmen Form 675

2 A royalty clause contains provisions specific to natural gas that address the increased price and additional costs that will result from the marketing efforts, transportation, and processing necessary to complete a sale. These provisions are some of the most common drivers of gas royalty litigation. Common Types of Royalty Disputes Royalty calculation method: market value vs. proceeds. The royalty clause contract language previously quoted distinguishes between gas sold at the well and gas sold beyond the production field (i.e.,off- premises). Specifically, the royalty payment for natural gas sold at the well is based on proceeds received, while the royalty payment for gas sold off premises is based on the market value of the gas. This distinction has given rise to numerous lawsuits over the question of whether or not the market value can be different from the proceeds received. Essentially, if natural gas is sold off premises under the provisions of a long term contract, is the market value determined by the contract price (which may have been agreed upon months or years earlier) or the current market price (as might be evidenced by comparable transactions)? It s likely that producers originally intended the lease language to provide for royalties to be calculated on the contract price for natural gas sold both on and off premises while allowing for deductions of marketing, transportation, and processing when a market did not exist at the well or a better market existed elsewhere. However, royalty owners have questioned whether or not the market value could be higher than the amount realized under a contract sale. Courts have not ruled consistently on royalty calculation methods, but rather have adopted both approaches in different cases. Most states have followed the Texas Supreme Court ruling in Texas Oil and Gas Corp. v. Vela, 429 S.W.2d 866 (Tex. 1968), and held that market value requires the lessee to pay based on the current value of the natural gas at the time of production. The Vela Rule raises the possibility of royalty litigation any time there is a significant increase in the price of natural gas. Courts have also held that the inverse is true; when the market price of natural gas is lower than the contract price, lessees may pay royalties on the lower price. 2 Conversely, a few states follow what is called the Tara Rule, named after Tara Petroleum Corp. v. Hughey, 630 P.2d 1269 (Okla. 1981). In this case, the Oklahoma Supreme Court noted that royalties based on market prices at the well were inherently ambiguous given that natural gas must be sold by long term contracts whose prices could differ from current market prices. The court held that an arms-length contract established market value and could be relied upon to calculate royalties. Disputes over the determination of market value. Once courts established that market price may be different than proceeds received, disputes over the proper determination of market value followed. In Vela, the court established that market value should be determined by an analysis of comparable sales, taking into account time, quality, and availability to market outlets. Disputes can easily arise over these factors as well as other variables that could be used in determining market price. When comparable sales are not readily available or reliable, the netback method should be utilized to determine the market value at the wellhead. The netback method begins with the price of processed and delivered oil or gas, and then subtracts certain post-production costs incurred. In theory, a netback price subtracts the costs associated with bringing the oil or gas to market. This method has its own challenges, including, but not limited to: Can depreciation and an allowance for return on investment be deducted?; Can the cost of a processing facility be deducted?; How should those costs be allocated?; And, Can the processing facility cost be deducted even after it has been paid for?. 3 All of these issues are related to the next category of royalty disputes. Disputes over proper deductions to royalty payments. The sale of natural gas usually involves significant costs to get production from the wellhead to the pipeline. Costs can include transportation, dehydration, cleaning, processing, and compressing, among other things. 2 See Yzaguirre v. KCS Resources, Inc., 53 S.W.3d 368, 373 (Tex. 2001). 3 One case addressing these issues is Piney Woods Country Life School v. Shell Oil Co., 726 F.2d 225 (5th Cir. 1984), where the court determined that costs for a processing facility could be allocated to lessors, but only up to the point where the facility had been paid for. 2

3 While the lessee is obligated for the costs of production necessary to generate value at the well, which party bears the responsibility for costs subsequent to production? At what point has production occurred? And what postproduction costs are deductible? It is typically assumed that production occurs once gas has been captured and held, and the aforementioned additional expenses, as well as some taxes, depreciation, and other costs are shared proportionately by the lessor. One classic case addressing this particular issue is Piney Woods Country Life School v. Shell Oil Co., 726 F.2d 225 (5th Cir. 1984). Shell produced sour gas (gas containing significant hydrogen sulfide) on the Piney Woods lease and transported the gas to a processing plant where the impurities were removed, and then sold the processed sweet gas to a pipeline. The court stated that the lessor was entitled to royalty based on the value or price of unprocessed or untransported gas. On royalties at the well, therefore, the lessors may be charged with processing costs, by which we mean all expenses, subsequent to production, relating to the processing, transportation, and marketing of gas and sulfur. 4 The current trend is for lease clauses to specifically identify the cost categories to be deducted from natural gas transported for sale. However, states adopting the view reflected in Piney Woods have ruled that lessors can be charged post-production costs even in some cases where there is specific contract language to the contrary. 5 An alternative view that has been adopted in Oklahoma, Kansas, Colorado, and West Virginia relates to an implied covenant to market the natural gas. Courts in these states have ruled that production is not complete until a marketable product is held in a commercial marketplace. While some states may have adopted the marketable product rule, they don t necessarily agree on which costs can be deducted. Some states assume initial separation of gas from oil and water is part of production, while Arkansas 6, Kansas 7, and Oklahoma 8 view initial compression as a production activity. Disputes over associated transactions. Falling natural gas prices in the latter half of the 1980s sparked a wave of litigation referred to as take or pay litigation. During the 1970s, the shortage of available oil and gas led buyers to enter into contracts that required buyers to either take delivery of certain quantities of gas or pay for the product at contracted rates (even if the buyer chose not to take physical possession of the product). However, when prices sharply declined in the 80s, buyers attempted to circumvent high contract price purchase obligations. Numerous lawsuits ensued, billions of dollars changed hands, and a new question was raised: Are the royalty owners entitled to a share of the take or pay proceeds and settlements? Most courts decided that royalty owners were not entitled to a share of the proceeds because production had not occurred. 9 A few courts in Louisiana and Arkansas, however, ruled otherwise and held that royalty owners were entitled to a share. 10 While take or pay provisions are less common today, potential questions regarding royalty owners rights to proceeds from transactions related to production still exist. For example, will royalty owners be entitled to a share of incentive bonuses, supply bonuses, and profits from hedges and swaps? Trends in Royalty Litigation Litigation related to unconventional techniques has increased significantly since early 2011 (Figure 1) Q2 FIGURE 1: Q2 11 Q4 12 UNCONVENTIONAL OIL AND GAS CASES BY QUARTER Q Q Q Q Q Q F.2d at In Heritage Resources, Inc. v. NationsBank, 939 S.W2d 118 (Tex. 1996), the court ruled that transportation costs could be deducted in spite of language in the lease agreement that stated there shall be no deductions from the value of Lessor s royalty by reason of any required processing, cost of dehydration, compression, transportation, or any other matter to market such gas. 6 Hanna Gas and Oil Co. v Taylor, 759 S.W.2d Gilmore v. Superior Oil Co., 388 P.2d Wood v. TXO Prod. Corp., 854 P.2d Diamond Shamrock Exploration v. Hodel, 853 F.2d 1159 and Killam Oil Co. v. Bruni, 806 S.W.2d Frey v. Amoco Production Co., 603 So2d 166 and Klein v. Jones, 980 F.2d See Navigant Unconventional Oil & Gas Litigation Trend Reports,

4 As shown in Figure 2, royalty disputes continue to be the most pervasive type of unconventional oil and gas litigation. FIGURE 2: Q2 11 Q4 12 UNCONVENTIONAL OIL AND GAS CASES BY TYPE Q2 2011Q3 2011Q4 2012Q1 2012Q2 2012Q3 2012Q4 Royalty Disputes Other Breach of Contract Land & Lease Rights IP/Trademark Insurance Environmental/Product Liability Zoning/Regulator Securities/Stockholders Suits A number of factors have and will continue to give rise to royalty disputes in formations where unconventional methods of extracting oil and natural gas resources are being employed. The volume of new leases is significant, and some production regions include areas with smaller average parcel sizes, so pooling of leases is more prevalent, all of which can lead to more opportunities for disputed royalty calculations. In areas where production is occurring before pooling arrangements can be formed, allocation of costs and calculation of royalty payments are further complicated. In addition, lessors are also more sophisticated, have access to more information regarding lease terms, and are demanding more customized agreements. Greater variance in lease terms, higher volume of leases, and more complicated allocations all create a greater administrative burden for producers to accurately calculate royalty payments. However, it is perhaps the location of these new formations that is most likely to lead to royalty litigation. Many of the new shale plays are in states where a history of oil and gas royalty case law does not exist, as it does in Texas, Oklahoma, Louisiana and other states. Courts have looked to states with more established case law for guidance, but many of the issues outlined above have not been decided. Moreover, each state ultimately acts based on the applicable state laws and rules on behalf of its constituents and thus may not rely on laws from other jurisdictions. For example, Pennsylvania s Guaranteed Minimum Royalty Act has been the source of many disputes. The statute, which was updated and amended in 2010, requires producers to pay a minimum 12.5% royalty but allows for the deduction of certain expenses. The calculation of those expenses and other issues, however, remain in debate. In fact, the Pennsylvania Attorney General recently launched an investigation into complaints that producers were over-deducting expenses, using internal sales to misrepresent values and misrepresenting other data. Furthermore, there is still significant economic uncertainty regarding the value of shale gas and oil resources, costs to extract, level of conversion to natural gas, exporting of LNG and other factors. Economic and legal uncertainties create a challenge for operators in the drafting of leases as well as the administration of royalty payments. Since these uncertainties are likely to persist for some time, the risk of litigation over royalty issues could remain significant. Robert Lang About the Authors» Robert Lang is a Director in the Oil & Gas Disputes group in the Disputes and Investigations practice. He routinely provides expertise in a wide variety of oil and gas disputes dealing with matters throughout the product life The opinions expressed in this article are those of the authors and do not necessarily represent the views of Navigant Consulting, Inc. 4

5 Natural Gas Market Charts MONTHLY GAS INDEX PRICE DAILY GAS PRICE $/MMBtu $20 $18 $16 $14 $12 $10 $8 $6 $4 $2 $0 Mar-12 Jul-12 Nov-12 Mar-13 Jul-13 Nov-13 Mar-14 $/MMBtu $22 $20 $18 $16 $14 $12 $10 $8 $6 $4 $2 $0 Mar-12 Jul-12 Nov-12 Mar-13 Jul-13 Nov-13 Mar-14 Chicago Opal New York AECO-C SoCal Gas Henry Hub Sources: Navigant/Gas Daily Chicago Opal New York AECO-C SoCal Gas Henry Hub Sources: Navigant/Gas Daily March monthly index gas price decreased 13% last month, with Henry Hub at $4.86/MMBtu versus $5.58 for February. The March 2014 price exceeded the March 2013 price of $3.43/MMBtu by $1.43/MMBtu. The daily spot prices ended March about even versus the end of February, with Henry Hub at $4.50/MMBtu versus $4.53 for February. Price spikes in New York remained in the $20/MMBtu range. NYMEX FUTURES SETTLEMENT PRICES AT CLOSE MONTHLY PRICES: OIL AND NATURAL GAS GULF COAST $5.50 $24 Feb $18 $/MMBtu $4.50 Mar Apr $/MMBtu $12 $6 $3.50 Feb-14 May-14 Aug-14 Nov-14 Feb-15 $0 Feb-10 Feb-11 Feb-12 Feb-13 Feb-14 Sources: Navigant/NYMEX WTI (Cushing, OK), Crude Oil Henry Hub - Natural Gas Sources: Navigant / Platts The average 12-month strip price decreased by 8 cents, or down 2%, to $4.50/Mmbtu for the April strip. The most recent gas/oil price ratio grew to 3.3 times, with Henry Hub natural gas price at $4.86 versus WTI crude oil price at $ The ratio one year prior was 4.4 times. 5

6 Natural Gas Market Charts U.S. DRY GAS PRODUCTION CANADIAN WEEKLY NATURAL GAS RIG COUNT Bcf/day Rigs Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Sources: Navigant / EIA Sources:Navigant / Baker Hughes U.S. dry gas production last month continued at recent levels of near 68 Bcfd. Canadian natural gas rig count strengthened again versus seasonal patterns, and exceeds last year at this time by 54%, at 179 versus 116 rigs. U.S. POPULATION-WEIGHTED HDD U.S. GAS STORAGE 1,200 1, ,500 4,000 3,500 3,000 HDD Bcf 2,500 2,000 1, Degree days for the current month are projected from weekly degree days to date 1,000 0 Nov-13 Dec-13 Jan-14 Feb-14 Mar-14 NOAA Normal Actual Sources: Navigant / NWS CPC 500 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Range ( ) Sources: Navigant / EIA 2014 Continued cold weather pushed March heating degree days to 14% greater than normal, and seasonal HDDs to 7% greater than normal. Following continued strong withdrawals, U.S. storage inventories in March dropped to 13% below the lowest level at this time in the last ten years, at 896 Bcf versus 1,032 Bcf in

7 Natural Gas Market Charts CANADA GAS STORAGE U.S. MONTHLY NATURAL GAS DEMAND Bcf Bcf/d Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Range ( ) Sources: Navigant / Enerdata 40 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Sources: Navigant / EIA Strong Canadian storage withdrawals continued in March, bringing current storage levels 11% below the last nine years at this time, at 137 Bcf versus 154 Bcf in US gas demand levels have returned to within historical ranges following record levels (as restated by EIA) in January and February. U.S. WELLHEAD SHALE GAS PRODUCTION U.S. TEMPERATURE OUTLOOK Bcf/day Feb-13 Apr-13 Jun-13 Aug-13 Oct-13 Dec-13 Feb-14 Marcellus Eagleford Woodford Fayetteville Haynesville Barnett Shale Other Sources: Navigant/LCI U.S. shale gas production increased another 1.4% in February, to almost 36 Bcfd. The temperature outlook is for above normal temperatures for the West and the Southern U.S. Below normal temperatures are favored from Montana to the Great Lakes. 7

8 Legislative and Regulatory Highlights Northeast/Appalachia National FERC Issues Order Requiring Interstate Pipelines to Demonstrate Compliance with Capacity Release Offer Posting Requirements FERC Docket No. RP On March 20, FERC issued an Order to Show Cause to all interstate natural gas pipelines requiring them to demonstrate compliance with the requirement of FERC Order 636-A (1992) to post offers to release or to purchase released capacity, as currently reflected in FERC regulations contained at 18 Code of Federal Regulations Section 284.8(d). The OSC gives pipelines 60 days to demonstrate compliance, or to submit revised tariffs that comply. FERC issued the OSC as a result of its sampling of pipeline websites that followed the Commission s gaselectric coordination technical conferences, where parties had commented that it would be beneficial to be able to post offers to purchase transportation capacity. FERC Issues Proposed Rules for Gas-Electric Coordination FERC Docket No. RM14-2 On March 20, FERC issued a Notice of Proposed Rulemaking to revise regulations to better coordinate the scheduling of natural gas and electricity markets, in light of increased reliance of natural gas for electric power generation. The focus of the rulemaking is on revisions to the natural gas scheduling system. Specifically, the proposed rules would: 1) move the start of the gas day earlier, from 9:00 am to 4:00 am (Central), to help ensure gas supplies during morning electric ramp-up; 2) delay the first day-ahead gas nomination opportunity from 11:30 am to 1:00 pm, allowing generators to finalize power schedules before purchasing gas; and 3) increase from two to four the number of intraday nomination cycles, to allow generators to better meet changing demands. In addition, the proposed rules contain a provision requiring the offering of multi-party service agreements, allowing shippers more flexibility in using capacity. Comments will be due in eight months, following a six month window for the gas and electric industries to reach consensus on standards. Tennessee Gas Pipeline Files with FERC on Niagara Expansion Project On March 7, FERC issued a notice of Tennessee Gas Pipeline s February 21 application for approval of its proposed Niagara expansion project, designed to increase deliveries to the U.S. northeast and eastern Canada by up to 158 MMcfd. The proposed expansion includes three miles of 30-inch pipe, as well as equipment modifications, along TGP s 200 Line in southwestern New York. TGP plans to complete construction by November Equitrans Files with FERC on Expansion of Marcellus Takeaway Capacity On March 4, FERC issued a notice of Equitrans LP s February 24 application for approval of its proposed H-164 pipeline project, designed to increase access to Marcellus Shale gas by connecting its gathering system to an interconnect with the Texas Eastern Transmission system. The project would increase transportation capacity for Marcellus production by 475 MMcfd. The proposed project includes about three miles of 12-inch pipeline, planned for completion by October Gulf FERC Issues Presidential Permit for Houston Pipe Line Cross-Border Facilities On March 20, FERC issued an order granting a presidential permit to the Houston Pipe Line Company for the construction and operation of border-crossing facilities between the U.S. and Mexico in Hidalgo County, Texas. The export/import facilities would have a design capacity of about 140 MMcfd, similar to the 23-mile, 24- inch diameter pipeline extension the company is building from its existing Edinburg Lateral. FERC Staff Release Favorable Draft EIS for the Freeport LNG Project On March 14, FERC staff released a draft Environmental Impact Statement for the facilities proposed by Freeport LNG, finding that the project s adverse environmental impacts (except for construction-phase noise and traffic impacts) could be reduced to less-than-significant levels with mitigation. The project would include modification of previously authorized facilities at Freeport LNG s existing Quintana Island terminal, as well as development 8

9 of additional facilities capable of liquefying 1.8 Bcfd of natural gas. Comments on the draft EIS are due May 5. Southeast and NEB applications with market studies. The next export application on DOE s Order of Precedence is Oregon LNG, also supported by a Navigant market study. Elba Island LNG Project Applies for FERC Siting and Construction Authorization On March 10, Southern LNG Company applied to FERC for authorization to build natural gas liquefaction and export facilities at its Elba Island project near Savanah, Georgia. The project, a joint venture between Kinder Morgan and Royal Dutch Shell, seeks to build liquefaction capacity totaling about 350 MMcfd of natural gas. Southern LNG s August 2012 application to the DOE for export authorization is still pending. California/Northwest FERC Grants Waiver to CAISO Tariff Regarding Fuel Cost Allowances On March 21, FERC granted the second of two waivers requested by the California Independent System Operator to provide temporary protection to generators against potential adverse outcomes in CAISO s day-ahead electricity market caused by sudden increases in natural gas prices. Because certain formulaic bids or price caps were not able to reflect actual gas costs in the case of rapidly increasing gas prices, CAISO sought waivers first allowing for the use of updated gas price data for settlement purposes (waiver granted March 14), and second allowing updated gas price data for market execution purposes (granted March 21). The waivers will allow CAISO to use updated gas prices if it believes that the most up to date prices (published on a same-day basis by the Intercontinental Exchange, Inc., or ICE) will exceed a certain percentage of the day-ahead prices (initially set at 150%). The waivers will remain in effect until April 30, Jordan Cove LNG Project Receives Non-FTA Export Authorization from DOE On March 24, the Department of Energy announced its conditional authorization of exports to Non-Free Trade Agreement nations by Jordan Cove Energy Project, owned by Verasen Inc. The approval for Jordan Cove, to be located in Coos Bay, Oregon, is to export up to the equivalent of 0.8 Bcfd of natural gas for 20 years. Jordan Cove s DOE approval follows the approval in February by Canada s National Energy Board for Jordan Cove to export natural gas from Canada to be used as the project s feedstock. Navigant supported both Jordan Cove s DOE 9 British Columbia TransCanada Subsidiary Applies for Environmental Certificate for Coastal GasLink Project On March 12, a subsidiary of TransCanada Pipelines Ltd. submitted its application to the B.C. Environmental Assessment Office for an environmental certification for the Coastal GasLink Project. The 650-kilometer pipeline project is designed to deliver natural gas from the Groundbirch area near Dawson Creek to Shell Canada s proposed LNG Canada liquefaction facility near Kitimat. The filing will trigger a 45-day period for public comment, scheduled to run from March 21 to May 4. NEB Requires LNG Export Proponent to Refile Application with Necessary Export Impact and Market Analysis On March 5, Canada Stewart Energy Group Ltd. filed an application with the NEB for authorization to export liquefied natural gas from a proposed project on the northern B.C. coast. The application is for exports of LNG equivalent to about 1.5 Tcf per year of natural gas. Feedstock would be brought to the project via a proposed 800-kilometer pipeline. Because the application did not include sufficient market analysis, however, the NEB stated by letter dated March 18 that it will not treat the application as complete until Canada Stewart Energy refiles its application with the necessary export impact and market analysis. Maritimes Goldboro LNG Receives Environmental Approval On March 21, the Province of Nova Scotia announced its issuance of environmental assessment approval (with conditions) for Pieridae Energy s Goldboro LNG export project. The project s export application is currently before the NEB, seeking authority to export up to 10 million tonnes per annum (about 1.4 Bcfd of natural gas equivalent). Pieridae expects to make a final investment decision in 2015, with a targeted operational date in 2020.

10 Fuels Team Gordon Pickering, Director Iron Point Circle Suite 225 Folsom, CA Bob Gibb, Associate Director San Jacinto Suite 900 Austin, TX navigant.com About Navigant Navigant Consulting, Inc. (NYSE: NCI) is a specialized, global expert services firm dedicated to assisting clients in creating and protecting value in the face of critical business risks and opportunities. Through senior level engagement with clients, Navigant professionals combine technical expertise in Disputes and Investigations, Economics, Financial Advisory, and Management Consulting, with business pragmatism in the highly regulated Construction, Energy, Financial Services, and Healthcare industries to support clients in addressing their most critical business needs. Out of its Sacramento and Houston offices, Navigant s Fuels experts focus on the North American market offering fuels services to utilities and public entities, financial services companies, independent power producers, natural gas producers, pipelines, LNG developers, and large industrial end-users. Among other tasks performed for clients, the Fuels Practice has performed due diligence analyses and market analyses/price forecast studies, provided contract support (transportation, supply, and storage), developed fuel plans, and provided litigation and regulatory support Navigant Consulting, Inc. All rights reserved. # Navigant Consulting is not a certified public accounting firm and does not provide audit, attest, or public accounting services. See navigant.com/licensing for a complete listing of private investigator licenses. 10