CHAPTER 8 DRAFTING ISSUES WHICH IMPACT NON-FEDERAL ROYALTY: AN ANALYSIS OF SELECTIVE CURRENT MARKET FORCES

• Jurisdiction: United States

Oil and Gas Royalties on Non-Federal Lands
(Apr 1993)
CHAPTER 8
DRAFTING ISSUES WHICH IMPACT NON-FEDERAL ROYALTY: AN ANALYSIS OF SELECTIVE CURRENT MARKET FORCES
Christine L. Hinton
Oryx Energy Company
Dallas, Texas
and Patricia A. Patten
OXY USA Inc.
Tulsa, Oklahoma

Justice Holmes observed in one of his opinions that "A word is not a crystal, transparent and unchanged: it is the skin of a living thought and may vary greatly in color and content according to the circumstances and the time in which it is used."¹ Most certainly drafters of oil and gas contracts are constantly reacting to "circumstances and time" when reviewing case law, statutory enactments and rulemaking for potential drafting impact on documents typically used. But since one drafter's problem is another drafter's solution, there are unlimited choices as to drafting suggestions. In an attempt to narrow the focus of this paper and to compliment the other papers presented at this institute, the authors provide selective practical suggestions and comments on drafting issues emerging from current market forces — additionally limiting the commentary to issues which have a direct impact upon non-federal royalties.

INTRODUCTION

Corporate personnel who draft typical oil and gas agreements have a natural bias toward standardization of agreements. Consistency of terminology has been an important aspect of administering the thousands of contracts held by companies. Also, the ultimate marketability of the properties involved is affected by "known" operating parameters. The amount of variation from the standardized forms is clearly related to the amount of market power by the party requesting the changes and in this regard, as a general proposition, it seems lessors have not recently gained any increasing leverage. However, it is also generally observed that reputable corporate drafters have not been continually redrafting one-sided provisions in their standardized forms in the last few years.

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One of the last major efforts for drafting changes to typical oil and gas agreements was a reaction to the royalty clause litigation of the 1980's. For the most part, companies' revisions to their standard lease and division order forms have been completed and industry now has a better idea of the "color and content according to the circumstances and the time in which it is used."² Of course, industry still anticipates much litigation will ensue over issues of valuation and deductions under older lease forms. The goal in all instances, of course, is to draft agreements to eliminate royalty and/or co-working interest owner conflicts and to reflect the intent of all parties. Everyone wants to know the parameters under which they will receive benefits and under which they must fulfill obligations.

The more recent drafting changes from the corporate perspective are not so much an attempt to make clear what was unclear — as in the royalty clause changes, but rather changes which are reactive to new market forces. In that light, this paper will look at some of the issues and market forces of the last year, specifically — drafting implications of the new Oklahoma royalty legislation, FERC's new Order 636 series which further restructures marketing's sales and transportation business, the newly approved A.A.P.L. gas balancing agreement, gas contract settlements and a selective horizontal drilling lease issue.

OKLAHOMA SB-168 — DRAFTING ASPECTS OF THE NEW ROYALTY STATUTE

Oklahoma producers, seemingly accepting its constitutionality³ , are in the middle of implementing the

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provisions of the new "Production Revenue Standards Act"⁴ ("Act"), with the actual payment methodology due to commence with July 1993 production. The specific provisions of the Act were much debated and have been the topic of informational seminars and commentary⁵ . This paper is not intended to detail provisions, but generally the Act continues the weighted average approach for payments to all royalty owners on all production.

In order to adjust for shifting of royalty payment responsibility (lessees will be responsible to pay other lessees' royalty owners) the Act authorizes an entitlement to a somewhat larger or somewhat smaller production share for gas. A smaller share results when a lessee has burdens exceeding those of other lessees. A larger share of gas production results when burdens are less than other lessees. This new entitled share has been termed "proportionate production interest" and is being calculated on all gas wells regardless of the drilling date (but note fieldwide unit wells are excluded).

This new entitled share is the crucial difference from the prior statute and is Oklahoma's solution to what was a continuing problem of non-compliance with the prior statute. One of the reasons for non-compliance was the potential for economic hardship, or at the very least immediately reduced revenues, from an apparent obligation to proportionately pay other parties' excess royalty burdens. Let's examine the Act and consider: what are the drafting implications?

Protective Language for Calculating Producer's Entitled Share

First, implementation efforts to secure the proper ownership information to calculate the newly termed "proportionate production interest" has presented a quandary — what to do when an interest owner does not or cannot provide verification of their own royalty burden — not an uncommon situation when other companies or purchasers have been the payor and handled changes in ownership relating to a well. While there is a statutory loss of nomination

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rights⁶ which can be imposed on the non-reporting party, the proper, verified amount of total royalty burden is essential to calculating ALL of the remaining working interest owners' entitled share of production.

While the standard should be to act as a reasonably prudent operator and to proceed on the best ownership/royalty burden information, operators (or other designated payors) can draft language in their requests for ownership information or send follow-up letters once the situation occurs in order to expressly document their efforts to confirm ownership. This can also serve as notice to the non-complying owner as to the proposed calculations and actions which the operator will pursue. For instance, the following language could be used to cover the situation:

Should Operator (or designated alternate as allowed under the Act) not be provided the ownership information in the time and manner as required under 52 O.S. Section 570.8, Operator shall have the right to enforce all non-compliance rights provided by statute, and further shall deem the non-reporting working interest to be burdened by 1/8 royalty burden and shall calculate proportionate production interests under the Act accordingly. Non-reporting working interest owners shall be liable for any mispayments caused by their failure to provide ownership as required under the above cited Act.

A need for similar language to cover future wells under new operating agreements in Oklahoma has been identified by a sub-committee of the Mid-Continent Oil and Gas Association Legal Committee. Their proposed language may soon appear as a typically added "Other Provision":

Upon request by the operator and for the purpose of calculating each party's proportionate production interest, each party shall furnish the operator with such title information as it may have as required by the Act, and the operator shall have no duty to calculate proportionate production interest until that information has been furnished. As an alternative to reliance on the title information furnished by each party, the operator may conduct a title examination or update existing title opinions for the purpose of determining the parties' proportionate production interests, and the cost of any such title examination shall be charged to the joint account. When the operator has determined each party's proportionate production interest, the operator shall

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mail a schedule of those interests to all parties. Such schedule shall be accompanied by the operator's computations and such title information or title opinions as will support those computations. Each party shall have thirty (30) days after receipt of the operator's schedule to agree or disagree with the calculated proportionate production interests. Any party who does not mail written notice of non-agreement to operator within said period setting forth the basis for his objections to the operators' calculations shall be deemed to have agreed to the proportionate production interest calculated for him. Once the proportionate production interest calculations shall have become final as to all parties, the operator shall advise all parties of that fact and furnish all parties with the final schedule of proportionate production interests.

As an observation it is noted that parties may wish to alter the wording as to the right to charge the joint account when the operator elects to obtain a new title examination. The language above does not even require production or a "non-reporting owner" as a prerequisite to incurring costs associated with a new title search. These new calculations would essentially require a division order title opinion in order to determine all royalty burdens — usually far more costly than a drilling title opinion. Secondly, the above language suggests that the operator does not have to obtain updated title, and if not, shall have no duty to calculate interests until the information is furnished. This means NO parties entitled interest would be calculated if there is a non-reporting working interest owner. This inaction would undermine the general intent of the Act.

It is suggested that a provision similar to that in the first presented language would be the more practical solution. This would allow the operator to proceed on an assumed burden and then make the...