CHAPTER 12 EVALUATING THE PURCHASE AND SALE AGREEMENT IN LIGHT OF POTENTIAL ROYALTY AND TAX CLAIMS
| Jurisdiction | United States |
(Dec 2008)
EVALUATING THE PURCHASE AND SALE AGREEMENT IN LIGHT OF POTENTIAL ROYALTY AND TAX CLAIMS
Sam G. Niebrugge
Davis, Graham & Stubbs LLP
Denver, Colorado
Gregory R. Danielson received his undergraduate degree from the University of Colorado in 1979 and obtained his J.D. in 1983 from the University of Denver. Since graduation, Greg has represented oil and gas companies in a variety of matters including business transactions, title examinations and bankruptcy law. Greg is currently a partner in the law firm of Davis Graham & Stubbs LLP. Greg is an active participant with the Rocky Mountain Mineral Law Foundation. He has been a member of the Board of Trustees and has served as Co-Chair of the Oil and Gas Program for the Annual Institute Proceedings. Greg also co-chaired the 2002 Special Institute on the Regulation and Development of Coalbed Methane and the 2004 Special Institute on the Development of Unconventional Gas. Greg has been a lecturer and author for various industry groups. His published papers include: "Title Examination of State and Federal Lands," Mineral Title Examination III, Paper No. 4 (Rocky Mt. Min. L. Fdn., 1992); "Liability Associated with Federal Record Title Leasehold Rights," 32 Public Land Resources L. Dig. 283 (1995); "Due Diligence for the Purchase of Pipeline Systems," Institute on Rights of Way, Paper No. 14 (Rocky Mt. Min. L. Fdn., 1998); and "Lease Maintenance and the Development of Coalbed Methane," 46 Rocky Mt. Min. L. Inst. 5-1 (2000); "The Perfect Oil and Gas Lease: Why Bother!" 50 Rocky Mt. Min. L. Inst. 19-1 (2004) and "An Industry Perspective on Coalbed Natural Gas (Methane) Units," Federal Onshore Pooling & Unitization, Paper No. 20A (Rocky Mt. Min. L. Fdn., 2006). Greg is a member of the Colorado Bar Association (Chair, Natural Resources and Energy Law Section, 2003-2004), American Bar Association, American Association of Professional Landmen and the Denver Association of Petroleum Landmen.
Sam G. Niebrugge joined the law firm of Davis Graham & Stubbs LLP as an Associate in the Natural Resources Department in 2008. He received a Bachelor of Science in Engineering with a major in Mechanical Engineering from the University of Michigan in 2003. He received his Juris Doctor from the University of Denver Sturm College of Law in 2007 where he was a member of the Order of St. Ives. Sam is admitted to practice in both Colorado and North Dakota.
I. INTRODUCTION
Royalty and tax obligations present difficult problems for the buyer and seller to evaluate in the purchase and sale of oil and gas properties. As this conference evidences, royalty and tax liabilities are an active area of litigation with potentially large exposure based upon class action litigation for underpayment of royalties or taxes and associated claims for punitive damages and statutory penalties. As a result, these issues tend to receive a lot of attention in the negotiation of the purchase and sale agreement. Many published papers have dealt with these issues in a more general context of the allocation of risks and the assumption of liabilities associated with the acquisition of oil and gas properties.1 The discussions usually focus on management of the liabilities associated with the royalty and tax claims through a variety of means, using pre-closing due diligence, representations and warranties, indemnities and assumption of liabilities.
In this paper we will consider the royalty and tax liability issues and how they are handled under traditional purchase and sale agreement provisions. We will also suggest that from the buyer's perspective the focus on liabilities may not be sufficient. Through the terms of the purchase and sale agreement the buyer seeks to preserve the value perceived by the buyer at the time of making its proposal.2 In a royalty and tax context, the standard terms of a purchase and sale agreement do not always provide an adequate remedy or assurance for the buyer. In part because the royalty and tax valuation issues directly affect the value received by the buyer and not just potential liabilities. If the seller is not properly valuing the production for royalty or tax purposes, then costs that are currently attributable to the royalty burdens would be shifted to the working interest owners, thereby lowering the value associated with the seller's net revenue interest. As we will discuss in this paper, this effective net revenue interest can be quantified by making certain assumptions, and one can make a purchase price adjustment based on the reduction in net revenue interest. An adjustment to the purchase price will allow the buyer to preserve the perceived value of the property.
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II. ROYALTY AND TAX CLAIMS
A. Changing Markets
Over the last 20 years the valuation of production for royalty and tax purposes has grown increasingly more difficult. These complications arise not only from the greater variety of creative marketing arrangements that thrive in an unregulated market but also the evolution of the state law view of the implied covenant to market. Prior to federal restructuring of the gas industry, most sales occurred at the wellhead to an interstate pipeline. There was not much variety in the manner in which the production would be valued. After the federal restructuring, culminating in FERC Order 636, which prevents interstate pipelines from purchasing gas at the wellhead, the simplistic marketing arrangements disappeared. Producers now build their gathering and transportation systems and market their gas. The customary industry contracts of the regulated era are not well suited to this new market. Statutes and court decisions from the pre-restructuring era don't fit with the current gas marketing environment. The accounting systems used to calculate royalties and taxes fit the pre-restructuring era but may now require significant modification to be able to do the accounting required in today's environment.3
B. Range of State Views: Texas to Colorado
In addition to the complicated royalty accounting issues that arise in the unregulated gas market, more uncertainty arises from the range of state law views related to the valuation of production for royalty and tax purposes and the treatment of post-production costs. Many of the early cases examining this issue arose in the state of Texas. Many of the land practices in other producing states, without any case law for guidance with respect to royalty valuation issues, looked to the state of Texas. Texas case law influenced the development of contract forms such as standard form oil and gas leases and the practices for setting up accounting systems. As the case law has developed in some of these jurisdictions, some of the state courts have declined to follow the Texas line of cases.
Texas defines a royalty as the landowner share of production, free of the expenses of development and production, although the royalty may be subject to costs incurred subsequent to production.4 Texas courts look to the express language of the royalty clause to determine if the parties have agreed to alter the general understanding regarding the sharing of costs between the non-working interest owners and royalty owner. In Heritage Resources Inc. v. NationsBank5 the Texas Supreme Court considered royalty provisions providing for market value at the wellhead for gas produced. Each royalty provision also prohibited deductions for costs of processing, dehydration, compression and transportation. The court upheld the producer's calculation of royalty with a deduction for the cost of transportation away from the well to the point of sale.
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The court held that the term "market value at the wellhead" has a commonly accepted meaning in the oil and gas industry which rendered the written prohibition on production and post-production costs as "surplusage as a matter of law."
On the other end of the spectrum from Texas point of view, we have Colorado case law and Wyoming statutes. In Rogers v. Westerman6 the Colorado Supreme Court considered various forms of royalty clauses using the "at the wellhead" language. The Colorado Court found that the ambiguity in these clauses meant that the phrase was silent with respect to the allocation of post-production costs and had no meaning. The Court looked solely to the implied covenant to market to determine the allocation of post-production costs. In defining whether gas was marketable the Court considered two factors: condition and location. The gas is in a marketable condition, if it is in a physical condition that is acceptable to be bought and sold in the commercial marketplace. The gas must also be delivered to a location that is the commercial marketplace, being a place where the gas is commercially saleable in the oil and gas marketplace.7 The second part of the two-pronged test distinguishes Colorado from most other states that have considered the implied covenant to market in a royalty context.
Wyoming has enacted legislation that creates by statute an implied covenant to market. Under the Wyoming Royalty Payment Act, enacted in 1989, the Wyoming legislature defined those costs that may be deducted from the royalty share when there is no explicit provision in the agreement between the parties.8 The Wyoming Royalty Payment Act also adds a new level of concern for potential buyers of oil and gas properties based on the penalties that may be assessed if the producer fails to provide the information owed to the royalty owner under the Act.9 Section 303(c) of the Act states that any person who fails to provide royalty information as provided in the Act is liable for payment of a penalty to the affected royalty, overriding royalty or other nonworking interest of $100 per month. A producer may logically conclude that this is a one-time penalty per report of $100 per...
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