Appendix C

Legal Aspects of EnhancedOil Recovery

Page

INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......................199

U N I T I Z A T I O N : VOLUNTARY AND Compulsory . . . . . . . . . . . . . . . . . . . . . . . . . . .199Basic principles of Oil and Gas Law. . . . . . . . . . . . . . . . . . . .................199

The Rule of Capture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............201Conservation Regulation: Well Spacing and Prorationing. . . . ... ... ....202

pooling and Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..............202Pooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........202Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 203

Voluntary Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............203Time of Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..............203Who May Unitize . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ....203Negotiation of Unit Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ...204

Compulsory Unitization . . . . . . .. .. .. . . $ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 211Procedure for Fieldwide Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212

Application . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212Notice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 213Hearing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................213Proof of Findings Required . . . . . . . . . . . . . . . . . . . . . . . ................213Entry of the Order for Unitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 214Amendment and Enlargement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ....215Effect of Unitization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 215Allowables and Well Spacing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...216Administrative and Judicial Encouragement to Unitization . . . . . . . .. ....216

APPROVAL OF ENHANCED RECOVERY PROJECTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 217Permit Requirements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................217

Application . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .217Notice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..................218Hearing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 218Order . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........................219

Injection Regulations Under the Safe Drinking Water Act. . ................219

OPERATIONAL ASPECTS OF ENHANCED OIL RECOVERY . . . . . . . . . . . . . . . . . . . . . . 221Potential Liability to Conjoining Interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221Environmental Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 223

Environmental Impact Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...223

197

Page

Air Pollution, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 224Water Pollution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 224Other Environmental Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225

Water Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225Lessor-Lessee Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225Riparian and Appropriation Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 226State Regulation of Water Use. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 227

LIST OF TABLES

TableNumber Page

c-1 Unitization Statutes: Voluntary and Compulsory . . . . . . . . . . . . . . . . . . . . . . . 228c-2 Comparative Chart of Aspects of State Unitization Statutes. . . . . . . . . . . . . . 229

198

Appendix C . 199

Introduction

The purpose of this appendix is to providedetails of legal issues associated with enhancedoil recovery (EOR). The term “enhanced oilrecovery” refers to any method of oil production

in which gases and/or liquids are injected intothe reservoir to maintain or increase the energy ofthe reservoir or react chemically with the oil toimprove recovery. Thus, enhanced recovery en-compasses the techniques referred to as pressuremaintenance, secondary recovery, and tertiaryrecovery. The reason for the broader use of theterm in this section is the fact that the legalproblems are much the same for any technique ofoil recovery beyond primary methods. There hasbeen relatively little commercial application oftertiary recovery techniques, so no body of caselaw specifically regarding it has developed; thelaw in this area must draw upon experience inpressure maintenance and established methodsof secondary recovery. Secondly, the regulatoryschemes of most States do not distinguish amongthe different types of recovery beyond primarymethods. Distinctions among the various tech-

niques of enhancing recovery will be made onlywhen necessary.

To assess fully how the law encourages, hin-ders, limits, or prevents employment of EORtechniques, it would be necessary to examine indetail each reservoir in which such techniques areor might be used. Such was beyond the scope ofthis assessment. The approach used here iden-tifies existing or possible constraints without at-tempting to suggest how much more or less oilcould be produced with or without particularconstraints. Statutes, regulations, and rules of lawaffecting EOR are described in a general waywithout discussing their applicability to particularfields, not only because the complex interplayamong various factors makes specific judgmentsabout individual fields very difficult, but alsobecause the law on some important points is un-decided or very uncertain in most jurisdictions.The views of producers and State regulatory per-sonnel are discussed when appropriate, as are theobservations and comments of legal authoritieson particular subjects.

Unitization: Voluntary and Compulsory

Basic Principles of Oil and Gas Law

The most efficient means of utilizing EOR tech-niques is generally to treat the entire oil reservoiras though it were a single producing mechanismor entity. There is no problem with this when theoperator of the field owns the leasehold ormineral interest throughout the entire reservoir;in this case obtaining the consent of any otherowner of an interest in the minerals in order toundertake enhanced recovery operations is un-necessary. However, where there are otherowners of interests in the same field, obtainingconsent may be necessary before fieldwideoperations may be commenced. In order to bet-ter understand the problems that may be in-volved in securing this consent or cooperation, itwould be useful to describe briefly the basic legalframework in which oil and gas operations takeplace.

The right to develop subsurface minerals in theUnited States belongs originally with the owner-ship of the surface. The different States whichhave fugacious minerals within their jurisdictionare divided as to whether such minerals areowned in place or whether the surface o w n e rowns only a right to produce the minerals thatmay lie beneath his land. For present purposesthe distinction has little significance. It is suffi-cient to point out that the ownership of the sur-face carries with it, as a normal incident ofownership, the right to develop the mineralsbeneath the surface.

The owner of the land may, however, sever theownership of the surface from ownership of theminerals. He may convey away all or a part of hisinterest in the development of the minerals andin so doing may create a variety of estates, Thus,for example, the owner of a 640-acre tract of land

200 . Appendix C

(one section) may convey to another person (orcompany) all of the mineral under the land ab-solutely. Or he may convey to that person a one-half interest, or some other percentage of in-terest, in all of the minerals beneath the section.Or again, he may convey to another all or a partof the minerals beneath a specific 40-acre tractcarved out of the section. Each of these interestswould be described as a mineral interest. Unlessotherwise restricted by the instrument creating it,the ownership of a mineral interest carries with itthe right to explore for, develop, and produce theminerals beneath the land.

Another type of interest that may be createdby a landowner or mineral interest owner is aleasehold interest. The owner of the minerals isnormally unable to undertake the developmentof the minerals himself because of the great ex-pense and risk of drilling. in order to obtaindevelopment without entirely giving up his in-terest in the minerals he will lease the right to ex-plore for and produce the minerals to another. Inreturn the lessee will pay a sum of money as abonus for the granting of the lease and will prom-ise to pay the lessor a royalty, generally one-eighth, on all oil and gas produced. Typically, thelessee will be granted the lease for a period of 1to 5 years (the primary term), subject to anobligation to pay delay rentals if a well is notdrilled in the first year, and so long thereafter asoil and gas or either of them is produced from theleased land (the secondary term). In addition to aroyalty interest of one-eighth, the lessor will re-tain a possibility of reverter; that is, if the delayrentals are not paid on time or production is notobtained within the primary term, or if produc-tion ceases on anything other than a temporarybasis in the secondary term, the interest leasedreverts automatically back to the lessor.1 Whenthe interest reverts, the lessor may then enter intoa new lease with another party or may undertakeor continue development himself.

The power to grant leases is often described asthe executive right, and a mineral interest may becreated with the executive power being grantedto another person. To illustrate, A as father of a

NOTE: All references to footnotes in this appendix appearon page 230.

family and owner of a tract of land may give bywill to child B a one-quarter undivided interest inthe minerals in the land, to child C a one-quarterundivided interest in the minerals, and to child Dan undivided one-half interest in the mineralstogether with the executive right to lease all theminerals. This would mean that only D could ex-ecute leases for the development of the minerals.D would be under a duty to exercise the rightwith the utmost good faith and fair dealing. Eachchild would receive a share of the proceeds fromthe development of the land (i.e., a share of thebonus, rental, and royalties), but it would beupon the terms established by D in his dealingswith the lessee in granting the lease. Under well-established principles of law, D must exercise thisright in such a manner that it does not unfairly ad-vantage him nor unfairly disadvantage theowners of the nonexecutive interests, children Band C. The duties owed by lessees to lessors androyalty owners, and the duties owed by execu-tive right owners to nonexecutive right owners,can impact upon the unitization of mineral landsfor enhanced recovery purposes. This is becausethe lessee or executive right owner must considernot only his own interest but the interests ofthose to whom he owes a duty in entering intoagreements for unitized operations.

In addition to duties, the lessee has certainrights arising from a lease that have significancefor EOR, These rights may be express or they maybe implied. They are express if the parties to thelease or deed have specifically recognized orgranted them in the conveyance. For example,the parties may explicitly provide that the lesseeshall have the right to conduct certain activitiessuch as laying pipelines on the surface of the landwithout being liable in damages. The rights areimplied if the parties have not expressly providedfor them, but the law recognizes that they existby virtue of the nature of the transaction be-tween or among the parties. Thus, the lessor andlessee may fail to provide expressly that thelessee has the right to come upon the leased landor to build a road for carrying equipment to a drillsite. The law will imply that the lessee has theright to do this when it would not be reasonablypossible to develop the minerals without under-taking such activity.

Appendix C . 201

Briefly stated, the law recognizes that evenwithout express grant, the lessee has the right touse such methods and so much of the surface asmay be reasonably necessary to effectuate thepurposes of the lease, having due regard for therights of the owner of the surface estate. It is wellestablished that the lessee does have suchrights. 2 However, the question may arise whethersuch rights are limited to those activities, eithersurface or subsurface, that could be contem-plated at the time of the execution of the lease ordeed. The same answer should be given for themore exotic methods of enhanced recovery thatthe courts have given for traditional waterfloodoperations when these were not provided for inthe lease. In allowing a waterflood project to goforward, the Appellate Court of Illinois stated in a1950 case:3

The mere fact that this method of production ismodern is no, reason to prevent its use by a ruleof law. It is true the contract of the parties doesnot specifically provide for this process, butneither does it specify any other process. Thecontract being silent as to methods of produc-tion, it must be presumed to permit any methodreasonably designed to accomplish the purposeof the lease: the recovery of the oil and the pay-ment of royalty. The court would violate funda-mental principles of conservation to insert by im-plication a provision that lessee is limited to pro-duction of such oil as can be obtained by oldfashioned means, or by so-called “primary opera-tions.”

The same rationale would apply to moremodern methods of enhanced recovery, eventhough these methods might involve somewhatgreater use of the surface and different types ofinjection substances.

A closely related question is the extent towhich the lessee or mineral grantee may usewater located on the property for purposes ofenhanced recovery. This has been an area ofsome controversy and will be taken up in a latersection because it involves matters going beyondlease and deed relationships.

F ina l l y , i t shou ld be noted that someauthorities have contended that there is not onlya right for the lessee to unitize or to undertakeenhanced recovery activities but also a duty todo so. The implied covenant of reasonable

development is well recognized in oil and gaslaw.5 It is to the effect that the lessee has theduty, where the existence of oil in paying quan-tities is made apparent, to continue the develop-ment of the property and put down as manywells as may be reasonably necessary to securethe oil for the common advantage of both thelessor and lessee. The lessee is expected to act asa prudent operator would in the same circum-stances. With increas ing exper ience withenhanced recovery, it can be argued that a pru-dent operator would, when it appears profitable,undertake enhanced recovery operations. Thus,where the lessee is reluctant to do so, the lessormight be able to require the lessee to engage insuch operations or give up the lease. Probablybecause of the difficulty or proof of profitabilityand feasibility for a particular reservoir there hasbeen little litigation on the point. However, onecourt has noted that there is “respectableauthority to the effect that there is an impliedcovenant in oil and gas leases that a lesseeshould resort to a secondary recovery methodshown to be practical and presumably profitableas a means of getting additional return from theIease .” 6 In another case the court similarlydeclared that “the Lessee not only had a right,but had a duty to waterflood the premises for therecovery of oil for the benefit of the mineralowners should it be determined by a prudentoperator to be profitable. ”7 Lessors then couldencourage enhanced recovery by making de-mands on their lessees.

The Rule of Capture

One of the most important and fundamentalprinciples of oil and gas law is the rule of capture.It stems from the fact that oil and gas arefugacious minerals; that is, they have the proper-ty of being able to move about within the reser-voir in which they are found. Followed by everyjurisdiction within the United States, the rule ofcapture is to the effect that a landowner may pro-duce oil or gas from a well located on his landeven if the oil or gas was originally in place underthe surface of another landowner, so long as theproducer does not physically trespass on theother’s land. The other landowner’s recourseagainst drainage of the petroleum under his prop-erty is the rule of capture itself: he may himselfdrill a well and produce the hydrocarbons and

202 . Appendix C

thereby prevent their migration to the property ofanother.

The problem with the rule of capture has beenthat it encouraged too rapid development of oiland gas. A landowner or his lessee must drill torecover the oil and gas beneath his property orthey will be recovered by a neighbor and lostforever to the landowner. The problem becameespecially acute when there were many smallparcels of land over a single reservoir. Overdrill-ing resulted from the rush to recover the oil andgas before it is produced by another, and theoverdrilling caused the natural pressure of thereservoir to be depleted too rapidly, therebyleaving oil in the ground that could have beenrecovered with sounder engineering practices.

Conservation Regulation: Well Spacing andProrationing

Recognizing that the rule of capture was result-ing in great loss of resources and excessive pro-duction of oil, the producing States began enact-ing legislation to modify it in the mid-1930’s. Toprevent excessive drilling the States authorizedregulatory commissions to promulgate well spac-ing rules, limiting the number of wells that can bedrilled in a given area.8 For example, the TexasRailroad Commission in Rule 37 allows, as ageneral rule, only one well every 40 acres. Ingeneral, in each major producing State specialspacing rules may be established for eachdifferent field and exceptions may be grantedupon showing of good cause.9

Well spacing alone would not be enough toovercome the problem of excessive production,for a producer might continue to produce at anexcessive rate in such a manner as to deplete pre-maturely the natural drive of the reservoir or inquantities that the market could not absorb. Toovercome this, the States established wellallowable; that is, they set a limit to the amountof oil or gas that could be produced in any 1month from a field or well. This is also known asprorationing of production. Well allowable havebeen set in two different ways. The first is knownas MER regulation: allowable are established forproduction at the maximum (or most) efficient

rate of recovery.10 The maximum efficient rate fora reservoir is established before a regulatory com-mission by expert testimony as to what would in-jure the reservoir and produce waste. This rate isnot constant, but changes with the age of thefield, and is not generally capable of exact com-putation. The second basic type of regulation ofwell allowable is known as market demandregulation: MER remains as the maximum rate ofproduction, but the rate actually allowed may belowered to a level which the commissionbelieves is the maximum amount of productionthat the market will bear for that month. This isgenerally established by the commission after ithas heard from producers as to the amount thatthey would like to produce. The commission maywish to give special incentives to certain types ofactivity and will establish allowable with morebeing allowed for one type of production thananother. To encourage drilling the commissionmay allow new wells to produce at the reservoir’smaximum efficient rate of recovery, while olderfields must produce at a lower rate, so that totalproduction from the State does not exceed theanticipated reasonable market demand. Withthe exception of Texas in recent months, themarket-demand type States have set allowablefor wells at the maximum efficient rate for every

month since 1973.

Pooling and Unitization

Pooling

State regulation of well spacing and produc-tion can cause significant problems that must beovercome by the producers themselves or by ad-ditional regulations. If there can be only one wellwithin a given area and there are several parcelsof land with different owners, some determina-tion must be made as to who will be able to drilla well and who will be entitled to receive pro-ceeds from the production from the well. The in-tegration of the various interests within the areafor the purpose of creating a drilling unit fordevelopment of a well and sharing of the pro-ceeds is known as pooling.11 It may be voluntaryif the interest owners come together and agreeby contract upon the drilling and sharing of the

production from the unit well. It may be com-pulsory if the State forces interest owners to par-ticipate on a basis established by the Stateregulatory commission when there is an applicantwho wishes to drill and some of the interestowners are unwilling or unable to reach an agree-ment upon sharing of development cost and/orproduction. Pooling then refers to the bringingtogether of the different interests in a given areaso as to integrate the acreage necessary forestablishing a drilling unit, and it may be volun-tary or compulsory. Virtually all States with pro-duction of oil or gas have compulsory poolingstatutes which can apply when the parties areunable to reach an agreement for voluntary pool-ing.

Unitization

Pooling does not result in the reservoir beingtreated as a single entity; it does reduce the num-ber of competitive properties within a reservoir,but there will still be competitive operationsamong the enlarged units to the extent permittedby law.

The mo efficient and productive method ofproducing oil may be achieved only if the entirereservoir can be treated as a single producingmechanism, i.e., when the reservoir may be oper-ated without regard to property l ines. Thisbecomes possible when one owner or lesseeowns or leases the rights to the entire reservoir orwhen all the interest holders in the reservoir unitefor a cooperative plan of development. Whenowners of interest do come together for such apurpose for development of most or all of a reser-voir this is referred to as unitization.12 It is muchthe same in principle as pooling, for it is an in-tegration of interests, and as with pooling it maybe voluntary or compulsory; but it is much morecomplex than pooling in attempting to reachagreement on cost and production sharing, andthe statutory schemes for compulsory unitizationare more difficult to comply with than for com-pulsory pooling. Unitization of most or all of areservoir is usually very desirable or is required inorder for there to be application of enhancedrecovery techniques to a reservoir.

Voluntary

Time of Unitization

Appendix C ● 203

Unitization

Ideally, unitization should take place at thefirst discovery of a reservoir capable of producinghydrocarbons in commercial quantities, or evenduring the exploration phase. However, this isnot feasible for it is only through drilling a num-ber of wells—with production from the first welland subsequent welIs going on—that theparameters of the reservoir can be established.Only when the characteristics and the limits ofthe field are generally known will the parties withan interest in the field be willing to unitize. Priorto that time they would possibly agree to shareproduction of petroleum from under their landswith parties who had no petroleum under theirs.It is only after extensive drilling that it is possibleto make an intelligent assessment of the basisupon which participation in the production fromthe reservoir should be established. Because ofthis, unitization has generally come about afterthe primary drive of the reservoir has begun todecline measurably, and it has appeared to in-terest owners that it may be desirable to unitizein order to undertakerecovery beyond themethods of recovery.

Who May Unitize

operations to enhancefield’s l ife by primary

Once it is clear to some of the parties with in-terest in the reservoir that unitization is desirable,there is the problem of determining who may un-dertake the uni t i zat ion. W i thout exp res sauthorization, either in the lease or by separate

agreement, the lessee is not able to unitize the

interest of the royalty owners to whom it mustpay royalty. The lessee may unitize its own in-terest—that is, agree to share with another theseven-eighths of production that it normallyowns-but without the consent of the royaltyowner(s) it may not agree with others to treat thepotential production attributable to the royaltyinterest from the leased acreage on any basisother than the one-eighth (or other fraction)going to the royalty owners. Some leases will

— .— — —

204 . Appendix C

contain authority to the lessee to enter into field-wide unitization agreements on behalf of thelessor, but the noted authority on unitization,Raymond M. Myers, has stated that “[d]ue to thecomplexity of the modern unitization agreement,a clause authorizing the unitization of the entirefield, or a substantial portion thereof, has notgenerally appeared in oil and gas leases. Lessorshave not generally been willing to grant suchbroad powers to lessees as such authorizationwould entail. ”13 Even with authorization the pru-dent lessee will gain the express consent of thelessor. Whether the executive right owner mayunitize, or authorize the lessee to unitize, the in-terests of the nonexecutive interests are open toquestion in most jurisdictions because there hasbeen little litigation on the point.14 The rule inTexas is that the executive does not have thispower; the rule in Louisiana is that he does. Ingeneral, it may be stated that it is desirable ornecessary to get the express consent of eachroyalty owner in order to effectuate voluntaryunitization.

Reaching agreement on unitization is a com-plex and drawn out undertaking often involvingdozens or hundreds of parties. To understand thisand to place in perspective the State’s role inunitization of property for purposes of enhancedrecovery, it would be useful to examine in somedetail the manner in which unitization is agreedupon.

Negotiation of Unit Agreement

The integrat ion of separate and oftendivergent ownership interests necessarily re-quires careful negotiation which may extend overseveral years. The best way to describe effec-tively the nature of and the problems inherent inthe voluntary unitization process is to relate theactual experiences of companies. The discussionof the process which follows draws in part fromthe case history of the McComb Field Unit in PikeCounty, Miss., 15 and from the Seeligson Field Unitin Jim Wells and Kleberg Counties, Tex.16

In the evolution of a voluntary unit, eachnegotiation has its own unique problems and cir-cumstances which affect the ability of principalsto achieve fieldwide unitization in a reasonableperiod of time. Even though no two unit opera-

tions are alike in every respect, there appear tobe four general stages in the negotiation process:

. Initiation of joint organization,

● planning period,

. Determination of participation formula, and

. Drafting and approval of agreements.

The remainder of this appendix is concerned withthe discussion of these four stages and their in-tegration during the formation of a voluntary unitoperation.

Initiation of Joint Organization.—The first stagein the unitization process involves the initiationof a joint organization of operating interests whorecognize the necessity for a fieldwide unit inorder to increase the ultimate recovery of oil andgas. A major operator or Ieaseowner will usuallyinitiate the process by informing other ownershipinterests that a unit operation may be desirablefor undertaking a particular fieldwide project forenhanced recovery.

For example, shortly after primary productionwas undertaken in the McComb Field, thecoowner of the discovery well and majorleaseowner (Sun Oil Co.) began accumulating ad-ditional technical information and data withrespect to the parameters of the reservoir. Thedata revealed an alarming condition in the reser-voir-a rapid decline in reservoir pressure whichcould bring premature abandonment with a tre-mendous loss in recoverable oil reserves. It wasapparent that a fieldwide gas- or water-pressuremaintenance project was needed to arrest thedeterioration of the reservoir and increase ulti-mate recovery. This pressure maintenance proj-ect required fieldwide unitization which, in turn,required full-field participation. A meeting washeld in February 1960, at the urging of the SunOil Co., and the preliminary evidence was pre-sented to 70 operating interests.

The initial stage of the Seeligson Field Unitnegotiation involved a different set of circum-stances. Numerous tracts in the field containedgas, oil, or both. A gas-unit operation had existedsince 1948, and the current problem was to unit-ize both oil and gas under one set of agreements.In particular, the proposed new unit operation

was primarily concerned with the increased oilproduction that would result both from thetransfer of allowable and from a pressure main-tenance program. Thus, operators having hadprevious negotiation experience could facilitatematters with the negotiation of a new unit agree-ment. A meeting was called in February 1952, todiscuss just such a possibility.

In specific terms, the initiation of a jointorganization entails three primary steps. First,after a discussion of the preliminary technical in-formation and data, operators reach a generalagreement on the “problem” giving rise to thenecessity for a unit operation. Once the problemis identified and clearly defined, then possiblesolutions for consideration can be enumerated.

During this initial step and the steps thatfollow, obstacles or delays may be encounteredwhen the joint organization involves a large num-ber of participants. If an inordinate number ofoperators have had little or no first-hand unitiza-tion experience or technical knowledge of theproposed solution projects, or where misunder-standings or suspicions develop, then unneces-sary delays may occur in the formation of a jointorganization.

The next step encompasses the acceptance ofthe articles of organization which establish theorganizational framework and procedural rulesfor the initial operating committee (UnitizationCommittee) and ancillary subcommittees. TheUnitization Committee is a temporary bodycharged with supervising the collection of exten-sive information and data germane to the forma-tion of the unit as well as presiding over thegeneral negotiations prior to the approval of theunitization agreements. The composition of theUnitization Committee and the various subcom-mittees requires an acceptable representation ofmajor and independent leaseowners. This willprovide a major step in spreading the respon-sibilities for unit formation among all parties in-terested in the fieldwide operation and also tominimize the potential misconceptions andmistrust which may develop among operating in-terests.

The final step in the initiation of the jointorganization involves financing of the temporary

organizational structure. Rather than the major

Appendix C ● 205

leaseowner bearing the full costs, financialresponsibility is generally shared according tosome acceptable method of cost allocation. Inthe McComb Field, expenses were shared jointlyon a well basis.

Generally, the initial stage in the negotiationprocess does not require more than a few meet-ings to finalize the temporary procedures for thejoint organization. Given sufficient preliminaryevidence, most operators recognize the necessityfor careful planning and thorough investigation inthe development of a fieldwide unitizationoperation.

Planning Period.—The second stage in thenegotiation process centers around the planningperiod, which culminates in the unitization agree-ments. This stage involves the activities ofvarious subcommittees who are responsible forcollecting extensive data and information and fordeveloping the details for the unit operation. Ingeneral, there are four main areas of concern:technical, legal, land, and accounting.

Technical. The gathering of technical data andinformation is the jo int responsibi l i tyof a Geologic Subcommittee and anEngineering Subcommittee.

The Geologic Subcommittee prepares thevarious geological maps and accumulatesfield data necessary for study by the jointorganization. In particular, their dutiescenter around ascertaining the extent of thereservoir in terms of its size, shape, andgeological limits. Aside from the extent ofthe reservoir, this subcommittee is con-cerned with mapping the thickness, struc-tural position, and extent of the “pro-ductive” pay of the reservoir. informationgathered by the Geologic Subcommittee ismade available to the Engineering Subcom-mittee for the evaluation of the various proj-ects under consideration and to operatorsfor determining oil recovery factors undervarious operating conditions. This is an im-portant phase in the negotiation process,due primarily to the fact that the technicalfeasibility and economic profitability ofvarious projects are evaluated and recomm-endations submitted to the UnitizationCommittee for consideration by the jointorganization.

206 . Appendix C

The task of this subcommittee is bestillustrated by the Engineering Subcommit-tee of the McComb Field Unit. As the reser-voir data were assembled, oil recovery fac-tors were derived under five operating con-ditions:

1.

2.

3.

4.

5.

Primary recovery (18 percent recoveryfactor);

Injection of produced gas (increaseultimate recovery to 23 percent);

Gas pressure maintenance (increaseultimate recovery to 30 percent);

Water pressure maintenance (increaseultimate recovery to 39 percent); and

High-pressure miscible gas injection(increase ultimate recovery to 54 per-cent).

Based on these oil recovery factors thewater pressure maintenance and high--pressure miscible gas injection projectswere selected for further feasibility analysis,where the advantages and disadvantages ofeach project were then evaluated.

While the miscible gas injection projectoffered the highest oil recovery factor, itsdisadvantages were extremely critical: thesupply of extraneous gas was available butat prohibit ive costs ; the process wasrelatively unproven in terms of general in-dustry-wide use; there existed possible cor-rosion problems as well as contamination ofreservoir gas; the project would require along period of time to implement andwould require expensive plant expansion;and, finally, there was a greater risk offailure. Furthermore, the rate of return forthe capital investment was calculated to be31 percent per year.

The advantages of the waterflood projectwere numerous: ample supply of salt waterin the reservoir; relatively lower initial in-vestment expenditure; proven method ofrecovery with a low risk of failure; minimumtime required to implement the project; andundertaking the waterflood project did notpreclude the adoption of miscible injection

at a later date. In addition, the capital in-vestment was calculated to earn a 72-per-cent annual rate of return. Finally, the pri-mary disadvantage of waterflooding was therelatively lower oil recovery factor.

After careful cons iderat ion of theeconomic feasibility and advantages anddisadvantages of each project, the technicalsubcommittees recommended the selectionof the water pressure maintenance projectfor the McComb Field Unit Operation.Aside from the higher rate of return oncapital investment, the major factors whichled to the waterflood selection involved theminimum risk of failure and the short imple-mentation time associated with the project.These factors were extremely crucial, giventhe rapidly declining pressure in the reser-voir.

Once the extensive geologic data andengineering information are accumulatedand project recommendations set forth, thefinal task of the technical subcommittees in-volves a preliminary determination of theparticipation formula whereby lessors andlessees share in unit production. The rele-vant aspects of the participation formulawill be considered later in this appendix,but it should be noted that the time framefor the work of the technical subcommitteescan vary considerably. For the SeeligsonField Unit, the Unitization Committee ap-pointed working interest representatives tothe technical subcommittees in February1952, and the Engineering Subcommitteeoffered recommendations (with respect tothe most feasible project and the tentativeparticipation formula) to a meeting ofoperators in January 1955. Hence, nearly 3years had elapsed during which time themajor technical groundwork for the unitoperation was completed. For the McCombField Unit, the work of the technical sub-committees was initiated in February 1960and recommendations and findings werepresented approximately 9 months later,

Therefore, the time required for collectingand evaluating detailed technical informa-tion and the subsequent recommendations

Appendix C . 207

which follow can consume from severalmonths to a few years during the unitizationprocess, In general, a number of factors suchas the geological complexity of the reser-voir, the number of development wellsnecessary for assessing the characteristics ofthe reservoir, the nature of the unitizationprojects under consideration, and whetherthe field is in the development phase or pro-duction phase may all contribute to thelength of time required for the planningperiod.

Legal. During the planning of a fieldwide unit,

the Legal Subcommittee handles the legalaspects assoc iated wi th the un i t i zat ion

process and the subsequent negotiation and

d r a f t i n g o f a g r e e m e n t s . T h i s c h a r g enecessarily requires an understanding of thedesired goal of the unit operation and themanner in which this goal impacts on landtitles, overriding royalties, operating leases,and other factors. In particular, the Legal

Subcommit tee determines whether thereare any legal restrictions or problems related

to property rights and the achievement of

the desired goal of the unit. It is incumbent

upon the Legal Subcommit tee to adv i se

lessees that they continue their lease obliga-

tions to lessors. The Legal Subcommitteemust ensure that the implied as well as ex-pressed obligations of lessees are satisfiedduring the negotiation and execution of aunitization agreement.

The Legai Subcommittee is also responsi-ble for submitting to the appropriate Stateregulatory agency all requisite documentsand instruments which pertain to the unitoperation. Such procedures will be dis-cussed in a subsequent section.

Land. The Land Subcommittee is generallycomprised of land agents whose function iti s t o i d e n t i f y r o y a l t y o w n e r s a n dleaseholders for the purpose of com-municating information to the various in-terest owners and facilitating the accept-ance of the unitization agreements. Whileoperating interests may be readily identifia-ble, a widespread distribution of royalty in-terests can make the task of the Land Sub-committee difficult and time consuming.

Frequently, overriding royalties, varioustypes of working-interest arrangements, androyalty interests involving estates or trustsmay add both time and expense to the com-plexity of forming a unit.

Once the majority, if not all, of the in-terested parties are identified, the landagents are responsible for conveying to theownership interests, information withregard to the nature of the unit operation(in terms of the project to be instituted aswell as each owner’s share in unit produc-tion). The work of the Land Subcommitteebegins in the planning stage of the unitiza-tion process and ends with the obtainingof signatures for the unit agreements.

Accounting. The initial concern of the Ac-counting Subcommittee involves the ac-counting for expenses incurred prior to theunit agreement. The work performed by thetechnical subcommittees and, to a lesser ex-tent, the other subcommittees operatingduring the planning period generatesexpenditures which must be underwrittenby the operating interests. Accounts aremaintained by the Accounting Subcommit-tee and subsequent billings to operators ona predetermined share basis are made forpurchases of supplies and field equipmentas well as the overhead costs of the tempo-rary joint organization.

The primary charge of the AccountingSubcommittee, however, is to prepare thejoint operation accounting procedureswhich establish the method of accountingand the allocational rules to be used in theunit operation. The accounting proceduresappear as an exhibit to the proposed unitagreement and specify the items to becharged to the joint account, the dispositionof lease equipment and material, the treat-ment of inventories, and the method ofallocating joint costs and revenues amongunit participants.

An important role of the Accounting Sub-committee entails the explanation and, insome cases, the determination of specifictax considerations which impact on owner-ship interests as well as the general field-wide operation. For example, tax legislation

. . .

208 . Appendix C

and tax court interpretations with respect toEOR projects are ever-changing, and the ap-plication of future tax law to EOR projectsis in a state of uncertainty. Therefore, thetax treatment applied to EOR projects mightaffect the incentive among participants of aproposed unit operation to engage in a par-ticular EOR project or it could affect the in-centive of an individual ownership interestto commit its property rights to the unitoperation.

An example where a possible disincentiveexists for joining a unit operation can beseen in the Income Tax Reduction Act of1975, which eliminated the percentage oil-depletion allowance for major companies.However, an exemption to this is providedfor independent producers and royaltyowners where an independent producer isdefined as one whose total retail sales is lessthan 5 percent of its total sales. When thisexemption is applied, the independent pro-ducer can apply the. 22-percent oil-deple-tion allowance to the market value of amaximum 1,800 barrels per day (for 1976,and declines to 1,000 barrels per day by1980). 17 When confronted with a choice ofjoining a unit operation which wouldenhance the producer’s recovery of oilabove the limit of 1,800 barrels per day andthus lose the exemption, the independentproducer would necessarily be concernedwith its participation factor in the unitiza-tion agreement. If the independent’s shareof unit production did not compensate forthe exemption loss or ensure at least a com-parable return for joining the unit, then thenegotiations of the unit operation couldface an obstacle to the attainment of fullfield participation. This situation mightcreate costly delays in the unitization proc-ess.

Another example can be seen in the ques-tions arising with respect to the tax treat-ment of costs associated with EOR projects,where costs relevant to the discussion in-clude intangible drilling and developmentcosts (lDC), cost of physical facilities re-quired in the EOR project, and the cost ofinjected material .18 According to the inter-

nal Revenue Code enacted in 1954, an IDCrefers to costs (i.e., labor, fuel, transporta-tion, supplies, and other items having nosalvage value) associated with installingequipment “incident to and necessary forthe drilling of wells and the preparation ofwells for production of oil and gas.” 1 9

Hence, the cost of installing injection wells,production wells, water source wells (in thecase of waterflooding), and converting pro-duction wells to input wells are treated asIDC and subject to the tax option of eitherexpensing these cost items or capitalizingthem. The generally accepted accountingpractice is to expense IDC, which allowsthem to be written off in the year that theyoccur.

The cost of physical facilities (i.e., storagetanks, pipelines and valves, waste-watertreatment equipment, etc.) must, by law, becapitalized and depreciated over the ex-pected useful l i fe of the equipment.However, the method of depreciation mayimpact on the incentive to undertake a par-ticular EOR project. A straight-line methodof depreciation (20 percent per year for 5years) would provide a “quick” writeoff andenable the full cost of the investment ex-penditure to be recovered in the first 5 yearsof the equipment’s useful life. With thesum-of-year’s digits method (over an 11-year period), only 68 percent of the full costof the equipment would be recovered dur-ing the first 5 years. The allowable deprecia-tion is greater for the straight-line method,and use of this method could improve theeconomic incentive of the EOR program. 20Furthermore, the tax treatment advice of theAccounting Subcommittee would be ex-tremely valuable at this point in evaluatingthe feasibility of projects under considera-tion by the joint organization.

The cost of the injected material may alsobe a relevant tax consideration. When high-cost materials are injected into a reservoirand a portion of the injected material can-not be recovered from the reservoir, thenthe total cost of the unrecoverable materialcan be expensed during the year in which itwas injected, or it can be capitalized and

depreciated (using the straight-line method)over the life of the reservoir. In addition, “ifit can be demonstrated, in any year, that aparticular injection project is a failure (i.e.,the injection of this material did not benefitproduction), a loss may be claimed for theundepreciated cos t o f the i n jec tedmaterial. ”21 At the margin, these tax optionsmay be an important consideration whenchoosing among EOR projects which requirethe use of high-cost injected material.

Determination of Participation Forrnula.-The“participation formula” (share of unit production

accruing to the separate ownership interests) is

the heart of the unitization agreement. As such, itrepresents the principal point of contentionamong the parties negotiating the voluntary for-mation of a unit operation. According to thenoted authority Raymond Myers, “The ideal isthat each operator’s share of production from theunit shall be in exact proportion to the contribu-tion which he makes to the unit. ”22 However, thedetermination of the “exact proportion” con-tributed by each operator to unit production isdifficult to determine and has led to long andlabored negotiations.

In the early days of unitization, participationwas based solely on surface area. The criteria wasfound to be wanting since, as Myers observes, itassumed “un i fo rm qua! i t y and th icknes sthroughout the [reservoir] with each tract havingbeneath it the same amount of reserves per acre.This rarely, if ever, happened.”23 More recently,shares are often determined in direct proportionto the amount of productive acre-feet of payzone which lies beneath the surface of each tract.However, this determination may be derivedonly after a series of development wells haveascertained the parameters of the reservoir. Theeffective procedure which is frequently utilized isto initially establish participation factors on thebasis of surface area and preliminary acre-feet ofpay zone criteria, then after the commencementof unit production (usually 6 months), the par-ticipation factors are adjusted in accordance withmore reliable or updated pay zone values.

Based on geologic studies of the McCombField, it was determined that the average payzone thickness was approximately 15 feet per

Appendix C . 209

acre for each 40-acre tract. This value providedthe basis for allocating unit production amongthe various ownership interests during the initialproduction phase in which approximately 18 per-cent oil recovery would occur. In the secondphase of the formula, secondary oil reserves wereallocated among the unitized interests on thebasis of 75-percent credit for net acre-feet of oilzone plus 25-percent credit for the participationfactor used in the first phase. This second phaseadjustment of participation factors was designedto take into consideration more technical aspects(actual pay zone) and thereby give some tractsadditional credit for their relatively larger con-tribution to unit production.

There are a number of obstacles, delays, or dis-incentives which tend to affect the acceptance ofthe participation formula as well as the subse-quent negotiations in drafting and approving theunitization agreements. A few of these have beenpreviously discussed and others are worth a briefmention.

Some of the ownership interests may be of theopinion that they should have a “fair advantage”with respect to their participation factor. In par-ticular, some parties may contribute more surfaceacreage to the fieldwide operation or a portion ofthe unit’s plant and equipment (such as injectionwells, storage facilities, and the like) may be lo-cated on their property. Hence, by virtue of thelarge surface acreage contribution or operationstaking place on their property, these ownershipinterests may argue for preferential treatment andthe adjustment of their proposed participationfactor to reflect this “fair advantage. ” The debateover this issue may create delays in the deter-mination of an acceptable participation formulaand, if left unresolved, could have a detrimentaleffect on the ability of all parties to form a volun-tary unit operation.

Pride of property ownership and/or controlover individual operations may affect the willing-ness of an individual ownership interest (royaltyas well as operating) to join a unit and committheir property and operational control to jointdecisions. When such strong feelings are held(and they may surface with participation factordissatisfaction), acceptance of the participationformula or general approval of the unitizationagreements may be difficult to achieve.

210 . Appendix C

A final consideration, which might well impacton the incentive for accepting the participationformula and entering a unit operation, involvesthe effect of FEA regulations. The domestic priceof crude oil is controlled at specific levels by FEA.However, the anticipation of future pricederegulation might prompt some producers toleave oil in place until the price of oil increases.This could be particularly critical when the pro-ducer feels that its return (based on the participa-tion factor) from the joint operation is marginal,at best.

In general, the acceptance of the participationformula by operators and royalty owners reflectstheir satisfaction with the unit operation and itsabil ity to ultimately increase profits whilesafeguarding property rights. Fieldwide unitiza-tion is initiated in order to increase the ultimaterecovery of oil and gas while reducing the riski-ness and costs associated with individual opera-tions. Through a joint effort, higher rates of returncan thus be realized with the retention of owner-ship interests in the recovery of oil and gas.

Drafting and Approval of Agreements.—Thefourth stage in the voluntary unitization processinvolves the drafting and approval of agreementsby participants engaged in a fieldwide operation.This stage represents the culmination of theefforts and responsibilities undertaken by thevarious subcommittees with the supervision ofthe Unitization Committee.

The Legal Subcommittee assumes the task ofdrafting the unitization agreements for the ap-proval of the ownership interests. The unitizationagreements are the legal instruments for the unitoperation, and there are generally two types ofdocuments: the Operating Agreement for theoperators or working-interest owners, and theRoyalty Owners Agreement for the royalty in-terests. It is customary to distinguish between thetwo ownership interests in order to facilitate theapproval of the unit operation. While operatinginterests share in the proceeds and costs of theunit operation, royalty owners share only in theproceeds from unit production and do not sharein the obligations incurred by the operators.Therefore, separate documents are desirablesince the Royalty Owners Agreement containsmaterial only of interest to the royalty owner.

The Operating Agreement contains a legalstatement of matters containing the participationformula and adjustments thereof, provisions forenlarging the unit operation, cost allocation,operational procedures, and matters pertaining totitles, easements, and term. Furthermore, theselection of the Unit Operation is specified inthis document where the Unit Operator is usuallythe largest leaseholder in the unit and is responsi-ble for the general supervision of the unit opera-tion. The execution of the Operating Agreementoccurs when the signature of the operators havebeen obtained. This generally requires approx-imately 6 to 8 months, as in the cases of both theMcComb and Seeligson Field Units.

As previously stated, the Royalty OwnersAgreement consists of material germane only toroyalty interests; as such, this instrument is con-siderably shorter and less difficult than theOperating Agreement. The Royalty OwnersAgreement must be presented to all the ownersof mineral interests in the unit area includingunleased lands, royalties, overriding royalties, gaspayments, and oil payments. The agreementmust be acceptable to the various royalty ownersbefore the unit operation becomes effective.Naturally, the primary concern among royaltyowners involves their share of the proceeds fromunit production and, to a lesser extent, their par-ticipation in plant products (gas, condensates,and others) and questions dealing with ease-ments. Therefore, in order to allay any apprehen-sions or misconceptions, great care has to be ex-ercised by operators in drafting the RoyaltyOwners Agreement and conveying to royalty in-terests the nature of the unit operation and howroyalty owners would benefit from unitizationwhile retaining their ownership rights. Myers ob-serves that “the interests of the lessee and lessorare for the most part identical, and this fact is ofcourse considered by the royalty owner in ac-cepting the decisions of his lessee. ”24

In order to achieve the maximum objectives ofvoluntary unitization, it is necessary that all par-ties having an interest in the unit area becomesubject to the unit agreements. However, in theabsence of compulsory unitization, this may beimpossible to obtain when some lessors orlessees refuse to participate in the unit. Evenwhen non joining parties cannot complain about

financial losses incident to the unit operation, theland of a non joining lessor or lessee may not beused to achieve the maximum effectiveness ofthe unitization program.

As a final note, the first four stages in thenegotiation and execution of a voluntary unitoperation demand much effort and planning onthe part of interested parties. The time that isnecessary to effect the fieldwide operation variesin accordance with the complexity and frequencyof the problems involved. Smaller units which in-volve fewer ownership interests will generallyestablish unitization in a relatively shorter timethan larger units with numerous and diverseownership interests. The larger the number of in-terested parties, the more difficult it is to coordi-nate and reconcile individual interests with theobjectives of the joint organization.

Based on the case histories of the McComband Seeligson Field Units, the time necessary forvoluntary unitization can be quite variable. Whenthe McComb Field agreement was submitted forregulatory approval, signatures of ownership in-terests had been secured for approximately 68percent of the royalty owners and nearly 84 per-cent of the operators. The time required for thecompletion of the first four stages involved lessthan 1 l/z years-a relatively short period for aunit operation encompassing over 300 tracts andthousands of ownership interests. On the otherhand, the Seeligson Field Unit initiated negotia-tions in February 1952; by November 1955, sig-natures of working-interest owners were ob-tained for the Operating Agreement. In the springof 1956, the Royalty Owners Agreement becameeffective and, after nearly 4 years of negotiation,the unit operation for the Seeligson Field becamea reality.

Compulsory Unitization

Compulsory unitization begins with voluntaryunitization of a majority of the interests withinthe field. It differs from voluntary unitization inthat all States with petroleum allow unitizationwhen most or all of the interested parties agreeto it, but not all States will force unwilling partiesto have their interests included in the unit opera-tions. Most States, however, do authorize the

Appendix C . 211

State commission to enter an order compelling allinterests in a field to participate in the unit oncethere has been voluntary agreement among aspecified percentage of interests in the field.25

This required percentage varies from 60 percentin New York and 63 percent in Oklahoma to ahigh of 85 percent in Mississippi. Texas is themost significant State without a compulsoryunitization statute, but it should also be pointedout that the effect of the statutes in California isso limited in application that they are rather in-effective: the California Subsidence statute pro-vides for compulsory unitization only in areas inwhich subsidence is injuring or imperiling com-merce or safety, while the California Townsitestatute applies only to fields over 75 percent ofwhich lie within incorporated areas and whichhave been producing for more than 20 years.

Without unitization of all interests, unit opera-tors may be liable to nonunitized interests fornon-negligent operations, and will have to ac-count to nonunitized interests as though therewere no unit. If a lessee in a unit has a royalty in-terest to which it must account for production,and that royalty interest is not joined in the unit,the lessee will have to account to the royaltyowner on the basis of the production from theleased land, not on the basis of the productionattributable to the leased land under the unitoperations plan. The lessee may have to engagein additional drilling in order to maintain thevalidity of the lease against non joining reversion-ary interest owners; such drilling may be com-pletely unnecessary for maximum recovery fromthe reservoir and, indeed, may be harmful to thatmaximum recovery. Lack of compulsory unitiza-tion or the requirement of a high percentage ofvoluntary participation could be a significantrestraint on unit operations, which in turn couldhave a significant impact on enhanced recovery.

In response to questionnaires sent to regula-tors and producers, several State commissionsand a significant number of producers identifiedthe inability of getting joinder of the necessaryparties in a field for unitization as inhibiting orpreventing the initiation of enhanced recoveryprojects. It was indicated that there probably areseveral hundred projects in the State of Texasthat cannot be undertaken because of the in-ability to join the necessary interests in the unit.

212 . Appendix C

Four small producers and four larger ones stated

that lack of joinder of parties was inhibiting proj-

ects in Texas. Producers in 10 States indicated

that enhanced recovery projects would be en-couraged by compulsory unitization or a loweredvoluntary percentage required to invoke com-pulsory unitization. For example, a Louisiana in-dependent declared “1 think 75-percent royaltyowner approval in Louisiana too high. A goodproject that benefits operator must necessari ly

benefit royalty owner.”

There appears to be little or no difficulty in re-quiring unitization and enhanced recovery ac-tivities on Federal lands. The major pieces ofFederal legislation for mineral development onFederal land provide ample authority to theSecretary of the Interior to make such require-ments. The Outer Continental Shelf Lands Act,for example, provides that for Federal leases the“Secretary may at any time prescribe and amendsuch rules and regulations as he determines to benecessary and proper in order to provide for theprevention of waste and conservation of thenatural resources of the Outer Continental Shelf(OCS). . . .Without limiting the generality of theforegoing provisions of this section, the rules andregulat ions prescr ibed by the S e c r e t a r ythereunder may provide for. . .unitization. . . .“26

Pursuant to this authority, the U.S. GeologicalSurvey in establishing operating orders for theOCS, Gulf of Mexico area, has provided that“Development and production operations in acompetitive reservoir [having more than onelessee] may be required to be conducted undereither pooling and drilling agreements or unitiza-tion agreements when the Conservation Managerdetermines. . that such agreements are practica-ble and necessary or advisable and in the interestof conservation. ”27 The same OCS order requiresthat operators “timely initiate enhanced oil andgas recovery operations for all competitive andnoncompetitive reservoirs where such operationswould result in an increased ultimate recovery ofoil or gas under sound engineering and economicprinciples.” 28 While Interior’s authority does notappear to be quite so ‘extensive under the MineralLeasing Act of 1920, the difficulties for unitiza-tion and enhanced recovery on Federal landonshore nevertheless appear minimal when com-pared with development on private lands.

Procedure for Fieldwide Unitization

The procedure for obtaining commission ap-proval for unitization or for compelling joinder ofparties in the unit is similar in most States,although by no means identical. Common ele-ments found in almost all States include the needfor application or petition by an interested party(normally the prospective operator), notice toother parties, a hearing, proof of matters requiredby the pertinent State statute, and entry of anorder by the commission defining the unit, andthe terms of the unitization. The entire procedureusually takes only a matter of weeks, althoughthere may be a delay or denial of the permitbecause of inequities in the participation for-mula. The description of the general procedureinvolved is intended to be suggestive only, withdetailed explanation of the procedure in severalof the more important States with enhancedrecovery activities. For other treatments, andspecific requirements for each State, referenceshould be made to the work cited29 and to tablec-1 .

Application

The application form and the information re-quired to be contained in it vary from State toState, but five common requirements are presentin whole or in part in most statutes. These arethat the following should appear:

1)

2)

3)

4)

5)

description of the area to be included,

description of the operations contemplated,

a statement of the unit control and com-position,

the expense and production allocation for-mula, and

the duration of the unit.

Some States require prior notice to be given tothe affected parties and several require that theapplicant furnish the regulatory commission witha list of the names and addresses of affected par-ties.

Who may initiate the regulatory process alsovaries from State to State. In many States any in-terested party may submit a petition for unitiza-tion, while in others only a working interest

owner may start the process. In a number ofStates the commission may initiate the procedureon its own motion, but this generally is not usedexcept with application by a party. Usually, it isthe unit operator who has been selected by theparticipants in the unit who initiates the process.

As described earlier, the expense and produc-tion allocation formula is tediously and carefullynegotiated by the parties to the unitizationagreement. Agreement with this information willnormally be submitted to the commission withthe petition or application. When compulsoryjoinder of other parties is sought, there will be astatement that such parties have been offered theopportunity to join the unit on the same basis asall others. The application will generally alsocover the matters which are required by thestatute to be found before the commission mayenter an order, as discussed under “Proof of Find-ings Required. ”

Notice

Both voluntary and compulsory unitizationstatutes generally require that notice and an op-portunity for a hearing be given prior to the entryof an order establishing or approving the unit.Louisiana, for example, provides that wheneverany application shall be made to the commis-sioner of conservation for the creation, revision,or modification of any unit: the applicant shall berequired to file two copies of a map of the unitwith the application; the applicant shall be re-quired to give at least 30 days notice of the hear-ing to be held on the unit in the mannerprescribed by the commissioner; and a copy ofthe plat shall remain on file in the office of thecommissioner in Baton Rouge and in the office ofthe district manager of the conservation districtin which the property is located, and be open forpublic inspection at least 30 days prior to suchhearing. JO Other States typically require a shortertime period for notice, but also require that it begiven by personal notice and/or by publication inthe State register or in a newspaper. Failure tocomply with a statutory notice provision mayresult in the order being declared invalid as toparties who were not given notice.31

Appendix C . 213

Hearing

Opportunity for hearing is required in all Statesprior to the entry of an order for unitization, butin some States, such as Alaska, no formal hearingneed be held if no party objects to the unitizationproposal after the notice is given.32 Hearings aregenerally conducted without rigid formality andare usually governed by the rules of civil pro-cedure of the State and/or such rules as may bepromulgated by the State commission pursuantto its delegated authority. Decisions are based onthe record evidence and a general right to rehear-ing and/or appeal is accorded.33

Proof of Findings Required

Prior to approval of any unit plan or entry of anorder requiring unitization in most States, theState commission must make certain findings.These generally are that unit operations arenecessary to increase ultimate recovery from thereservoir or prevent waste, that correlative rightsof interest owners are protected, and that the ad-ditional cost involved does not exceed the addi-tional recovery anticipated. The Texas statute, forexample, provides that unit agreements shall notbecome lawful or effective until the TexasRailroad Commission finds that:34

1)

2)

such agreement is necessary to accomplish[secondary recovery operations] or [con-servation and utilization of gas] or both;that it is in the interest of the public welfareas being reasonably necessary to preventwaste, and to promote the conservation ofoil or gas or both; and that the rights of theowners of all the interests in the field,whether signers of the unit agreement ornot, would be protected under its opera-tion;

the estimated additional cost, if any, of con-ducting such operations will not exceed thevalue of additional oil and gas so recoveredby or on behalf of the several personsaffected, including royalty owners, ownersof overriding royalties, oil and gas pay-ments, carried interests, lien claimants, and

others as well as lessees;

214 . Appendix C

3)

4)

other available or existing methods orfacilities for secondary recovery operationsand/or for the conservation and utilizationof gas in the particular area or field con-cerned are inadequate for such purposes;and

the area covered by the unit agreement con-tains only such part of the - field as hasreasonably been defined by development,and that the owners of interests in the oiland gas under each tract of land within thearea reasonably defined by developmentare given an opportunity to enter into suchunit upon the same yardstick basis as theowner of interests in the oil and gas underthe other tracts in the unit.

The Louisiana statute, to cite a compulsoryunitization statute, provides that an order for unitoperation shall be issued only after notice andhearing and shall be based on findings that:35

1)

2)

3)

4)

the order is reasonably necessary for theprevention of waste and the drilling of un-necessary wells, and will appreciably in-crease the ultimate recovery of oil or gasfrom the affected pool or combination oftwo pools;

the proposed unit operation is economicallyfeasible;

the order will provide for the allocation toeach separate tract within the unit of a pro-portionate share of the unit productionwhich shall insure the recovery by theowners of that tract of their just and equita-ble share of the recoverable oil or gas in theunitized pool or combination of two pools;and

at least three-fourths of the owners andthree-fourths of the royalty owners,. . shallhave approved the plan and terms of unitoperation, such approval to be evidencedby a written contract or contracts coveringthe terms and operation of said unitization

signed and executed by said three-fourths ininterest of said owners and three-fourths ininterest of the said royalty owners and filedwith the commissioner on or before the dayset for said hearing.

As indicated previously, different States withcompulsory unitization provisions have varyingrequirements as to the percentage of partiesvoluntarily entering into the unitization prior toinvoking the compulsory features.

Entry of the Order for Unitization

After application, notice, hearing, and pres-entation of evidence and findings by the commis-sion, the commission, if approving the unitiza-tion, will enter a formal order for the unitizationwhich will become a matter of public record. InOklahoma, for instance, the order of unitizationissued by the Oklahoma Corporation Commis-sion will provide for:36 1 ) the management orcontrol of the unit area by an operator who isdesignated by vote of the lessees; 2) the alloca-tion of production; 3) the apportionment ofoperational costs; 4) the manner of taking overthe wells and equipment of the several lesseeswithin the unit area and the method of compen-sation therefore; 5) creation of an operating com-mittee; 6) time of the plan’s effectiveness; and 7)time and conditions of unit dissolution. OtherStates are similar. Unit members dissatisfied bythe unitization order may appeal directly to theOklahoma Supreme Court.37

Interests joined in the unit through compulsionmay be allowed to choose prior to commence-ment of unit operations whether to participate ascotenants sharing in expenses and profits or totake a fair and reasonable bonus and royaltywhich is expense free. Several States including,among others, Alaska, Colorado, New Mexico,Utah, and Wyoming provide for or require financ-ing programs for nonconsenting parties withlimited cash outlay capabilities to defer unit ex-penses until production is obtained with reasona-ble risk assessments added.

The problem of determining a fair and equita-ble basis for allocation of production among theunit members can be an extremely difficult one,as was brought out in the discussion of theproblems of negotiating voluntary agreements forunitization. Claims may be made that productionshould be allocated on the basis of surfaceacreage, productive acre feet, productive porespace, prior production history, and other

grounds. The State commission may use a com-bination of these. For example, the OklahomaCorporation Commission for the West CacheCreek Unit in Cotton County, Okla., used a splitformula based first upon the estimated remainingnet economically recoverable primary productionof the unit, and secondly on the floodable acrefeet of the unit. The Oklahoma Supreme Courtupheld this approach against a chalIenge by a dis-satisfied party who claimed that the formulashould, in its second phase, take into account thecurrent production from the claimant’s well; thecommission’s order was, the court ruled, sup-ported by substantial evidence and so the courtwould not overrule the commission.38

State commissions have set formulae on avariety of base: and have generally been upheldby the courts regardless of the formula used.39

Statues do occasionally provide some stand-ards, but as one authority has stated, “Viewingpresent statutory standards, shed of all frills, theparties must look for real protection to the in-tegrity of the regulatory agency and of the partiespresenting evidence, as well as to careful scrutinyof the information by those who expressly con-sent to the allocation.”4° Both the sparsity oflitigation on the subject and statements concern-ing the regulatory commissions in response toOTA’s questionnaires indicate that the Statecommissions are effectively protecting the in-terests of the parties to unitization proceedings.

Amendment and Enlargement

Under most statutes for unitization, it is possi-ble to enlarge the unit and/or amend the unitagreement(s) following the same procedures thatwere used in creating the unit in the first in-stance. This may occur if additional parties wishto participate in the agreement or if it is learnedthat the reservoir has different parameters thanoriginally believed.

Effect of Unitization

Each State authorizes the establishment ofvoluntary fieldwide units, although formal Stateapproval may not be required for the creation ofsuch a unit. There are distinct advantages to get-ting such approval even when it is not a require-ment. First, the State will generally, by statute,immunize the participants from application of the

Appendix C . 215

State antitrust laws to the unit operation.41 Sec-ond, it may serve to protect the participants fromapplication of the Federal antitrust laws to theunit operations. The argument can be made thatunitization reduces competition and can serve asa means of limiting production and controllingprice. However, the general weight of authority isthat, so long as there is no collusion in refiningand marketing, the mere joint production of oildoes not create antitrust problems.42 W h e r eunitization is necessary to increase total produc-tion it would appear that unitization would ac-tually promote competition by increasing theamount of oil available to all the parties. The roleof State approval in Federal antitrust considera-tions (if they should be raised) is that it can beargued that the approval and order of the Statecommission gives rise to the well-recognizedParker v. Brown43 exemption from the operationof the Federal antitrust laws. That is, in the caseof Parker v. Brown, the U.S. Supreme Court heldthat State approval of a raisin marketing programprovided the cooperative activities of the raisingrowers with immunity from the Federal antitrustlaws. The same rationale would apply to unitoperations approved by a State commission. 44

Only one Federal case45 has attempted to applythe Federal antitrust statutes to unit operations,and was terminated through a carefully negoti-ated consent degree.

Another reason for getting State approval for avoluntary unit even if not required is that it mayprovide protection from l iabi l i ty for non-negligent operations to other parties in the reser-voir who have not joined in the unit. This is animportant subject in itself, and is taken up in alater section. Suffice it to say at this point the ele-ment of State approval of the enhanced recoveryprogram has been enough for some courts toestablish immunity from such Iiability for opera-tors. And, of course, where the requisite percent-age approval is achieved in a State with a com-pulsory unitization statute, the entry of acommission order for a unit will result in unitizingthe field and all interests in the field may betreated as members of the unit; no separate ac-counting or operations on a nonunit basis will benecessary.

One more point should be brought out, andthat is that under the terms of an oil and gas lease

216 . Appendix C

in some instances and by statute in others theestablishment of the unit will sever the unitizedportion of the leasehold from the rest of theIease. 46 Depending on the wording of the leaseclause (known generally as a “Pugh clause”because of the person purportedly creating itoriginally) or of the applicable statute, such as inMississippi, Louisiana, and Wyoming, additionalactivity on the severed part of the leasehold maybe necessary to keep the lease in force as to theportion of the lease not included in the unit. Suchlease and statutory provisions can serve as a dis-incentive to lessees to participation in unit opera-tions.

Allowable and Well Spacing

In order for an enhanced recovery project tobe successful, it is necessary to be able to pro-duce the oil. The fixing of allowable in market-demand type States could discourage enhancedrecovery if the production rates were set at alevel below the optimum rate for the reservoir.The regulat ions of the State commiss ionsgenerally do make provision for the setting ofallowable for enhanced recovery operations. Forexample, Oklahoma provides that “An” approvedand qualified waterflood project shall be entitledto produce an allowable of forty-five (45) barrelsof oil per well per day including producing andinjection wells on a project basis upon theacreage developed for waterflooding. The com-mission may increase the allowable for awaterflood project for good cause shown afternotice and hearing. ”47 In other States, similar pro-vision is made and/or allowable may be trans-ferred among interest owners for the encourage-ment of enhanced recovery.48 Because of special

t reatment and encouragement of enhancedrecovery projects, it does not appear that the set-

ting of allowable wou ld impede enhancedrecovery operations. No producer responding toOTA’s questionnaires indicated that there was aproblem of establishing adequate allowable forenhanced recovery. The same is true of wellspacing.

Administrative and Judicial Encouragementto Unitization

A number of State commissions and courtshave recognized the benefits that result from un-

dertaking unit operations to enhance recoveryand accordingly have attempted to encourageunitization. They have done this in several ways.

One has been to deny to non joining partiesthe benefits they might have expected to obtainby their refusal to join. Production allowablehave been set at a higher rate on occasion for unitmembers than for those who decline to enter theunit.49 To cite another example, an agency haslimited the royalty payable to a non joiningroyalty owner to the royalty that would havebeen paid had the allowable not been increasedfor the enhanced recovery operations.50 Such ac-tions have been upheld by the courts. 51

Another method of encouraging unitizationhas been for agencies to use their authority overwell spacing or the prevention of waste to makeunitization more attractive to interest owners.Thus in one well known case,52 the Colorado Oiland Gas Conservation Commission prohibitedthe production of gas from a large reservoirunless the gas was returned to the reservoir, usedin lease or plant operations, or used for domesticor municipal needs in or near the field. The oilcould not be produced without production of thegas, and the gas could not be reinfected withoutunitization of the field. Although sympathizingwith the commission’s goal, the ColoradoSupreme Court struck down the order on theground that it was beyond the authority of thecommission. Subsequently, Colorado enacted acompulsory unitization statute. A recent effort bythe Oklahoma Corporation Commission to re-quire separate owners of interests to developtheir land as a unit was struck down as beingbeyond the statutory authority of the commis-s ion.53

Finally, the courts have encouraged unitizationby denying damages to a non joining interestowner who has asserted that his production hassuffered by virtue of the unit operation of theparty against whom the claim is brought. Suchcases are taken up in a later section.

It should be observed that while agencies andcourts have expressed support for enhancedrecovery, they are l imited to the statutoryauthority they possess. There is only limited op-portunity for them to use their discretion for en-couragement of enhanced recovery.

Appendix C ● 217

Approval of Enhanced Recovery Projects

Permit Requirements

prior to commencement of any underground

injection for EOR purposes, (all enhanced recov-ery projects require underground injections), theparty responsible must obtain approval from theproper State commission. Often this may be doneat the same time that approval of unitization issought; much the same information is requiredand a similar procedure is employed. The twoshould be treated separately, however, becausethey are separate legal requirements involvingdifferent considerations and because an operatormust get a permit for enhanced recovery opera-t ions even when a unit ization procedure is notnecessary, as when the operator owns the entire

area covered by the reservoir.

As with the unit ization statutes, the require-

ments for enhanced recovery operations permitsvary from State to State.54 What is attempted hereis to highlight the general features of the regula-tory procedures that are similar in most Stateswith detailed references to the regulations of thelarger producing States. The procedure typicallyrequires the filing of an application or petition bythe party responsible for the project whichdescribes the activity proposed. Depending onthe jurisdiction, notice of the proposed actionmay have to be given to interested parties beforeapplication or it may be given subsequent to theapplication, either by the regulatory commissionor by the operator. A hearing upon the applicationwill be held if timely objection is made by an in-terested party or on the commission’s own initia-tive.

Application

Applications for enhanced recovery permitstypically require four elements of information tobe included, and these may be specified either bystatute or by rule of the regulatory agency: 1 )geographic description of the area covered by theoperation; 2) identification of parties affected orwho may be affected by implementation of theproposed project; 3) data concerning the forma-

tions underlying the area of operation; and 4) ex-planation of the recovery program.

Geographic descriptions required generally in-clude a plat of all leases in the affected area withlocations given for all present, abandoned, andproposed wells. New Mexico, for example, re-quires a plat showing the locations of all wellswithin a 2-mile radius of existing and proposedinjection wells and the formation from which thewells are producing or have produced. 55

To facilitate the giving of notice to affected par-ties, and to enable the States to prepare conserva-tion plans, the States generally require the ap-plication to include one or more of the following:the names and addresses of operators within thearea, the names of all operators within the unit,

the names of al l owners of property interests

within one-half mile of injection wells, and the

names of all lessees within 2 miles of injectionwells.

Data concerning subsurface formations that aregenerally required under the statutes or regula-tions include full descriptions of the formations inthe area and specific delineation of the reservoirto be flooded. Other such information may be re-quired. Kansas, for example, requires not only thename, description, and depth of the formations tobe flooded, but also the open-hole depths ofeach such formation, the elevations of the top ofthe oil- or gas-bearing formation in the injectionwell, the wells producing from the same forma-tion within one-half mile radius of the injectionwell, and the log of the injection well (if a com-plete log does not exist, such information regard-ing the well as is available). 56

The data concerning development plans thatare generally required include specific descriptionof injection methods, identification of the sub-stance(s) to be injected, the source of the sub-stance, and the daily amounts of the injection. in-formation pertaining to casing and casing testsmust similarly be submitted along with such loginformation as is available to the operator. SomeStates require additional data on oil to gas ratios

218 . Appendix C

and oil to water ratios on production obtained tothe date of the application. Separate applicationrequirements exist in some states for waterfloodmethods, repressurization, disposal wells and theuse of hydrogen sulfides’

Because it is typical of the requirements ofState commissions for enhanced recovery applica-tions, section 3-30I (b) of the General Rules andRegulations of the Oil and Gas Conservation Divi-sion of the Oklahoma Corporation Commission isset forth:

The application for an order authorizing apressure maintenance or secondary recoveryproject shall contain the following:

(1) The names and addresses of the operatoror operators of the project.

(2) A plat showing the lease, groups of leasesor unit included within the proposed project; thelocation of the proposed injection well or wellsand the location of all oil and gas wells, includingabandoned and drilling wells and dry holes; andthe names of all operators offsetting the area en-compassed within the project.

(3) The common source of supply in which allwells are currently completed;

(4) The name, description, and depth of eachcommon source of supply to be affected;

(5) A log of a representative well completed inthe common source of supply;

(6) A description of the existing or proposedcasing program for injection wells, and the pro-posed method of testing casing;

(7) A description of the injection medium tobe used, its source and the estimated amounts tobe injected daily;

(8) For a project within an allocated pool, atabulation showing recent gas-oil ratio and oiland water production tests for each of the pro-ducing oil and gas wells; and

(9) The proposed plan of development of thearea included within the project.

Notice

Because enhanced recovery operations mayaffect in one way or another virtually all parties inthe vicinity of the operation, the notice require-ment and opportunity given for a hearing reflect aliberal attitude toward notification of nearby tractowners and operators. Service of notice must bepersonal, by mail, or by publication in a readilyavailable or official publication. Generally, noticemust be given by the applicant himself to the

other parties, and it will have to be given some 10to 15 days before the application or just after fil-ing of the application. Notice commonly must beextended to owners and operators of the reservoirand all those with interests in property withinone-half mile of the injection well(s). Protestagainst the application must be lodged within 15days of service of notice or of the application, de-pending on the jurisdiction, In many jurisdic-tions no hearing need be held if no party objectsto the application or if the commission does notorder one on its own motion.

An example of the notice requirements can begiven by reference to Alaska’s rules58 which re-quire a copy of the application to be mailed ordelivered by the applicant to each affected opera-tor on or before the date the application is filedwith the Oil and Gas Division of the Departmentof Natural Resources. Statements must be at-tached to the application showing the parties towhom copies have been mailed or delivered. Inthe absence of any objection within 15 days fromthe date of mailing, the division’s committee mayapprove the application. If objection is made, thecommittee shall set the matter for hearing aftergiving additional notice to the affected parties.Other States are similar in their provisions.

Hearing

Once a protest is made to an application or thecommission on its own initiative requires one, ahearing will be held on the application. The func-tion of the hearing will be to determine whetherthe injection program is reasonably necessary forthe prevention of waste and to obtain greaterrecovery from the common source, whether therecovery costs will be less than the proceeds fromrecoverable oil and gas, and whether the rights ofother interested parties are adequately protected.Hearings are governed by the State’s rules of civilprocedure and/or rules promulgated by the com-mission pursuant to authority delegated to it. Evi-dence introduced at the hearings will normally bescientific information and data brought outthrough the testimony of geologists and engineersunder questioning by the operator’s attorney orthe opponent’s attorney. A right to rehearingand/or a court review of a commission decision isgenerally provided upon timely application.

Appendix C . 219

Order

In general, an application for any type of injec-tion program may be denied by the State commis-sion for good cause; the commission will haveconsiderable discretion allowed by State statute.If the application is approved, an order will beissued by the commission giving the operatorauthority to proceed. The order will be a matter ofpublic record and can be rescinded for any goodcause. The injection program will be subject toadditional requirements while it is being imple-merited. 59 The operator will normally be requiredto complete reports before or at the time of com-mencement of injection, to issue periodic reportsregarding the program, and will be subject to in-spection of operations by the State regulatoryagency. Additional notice to other State agenciesmay be required after issuance of the order. Theappropriate State agency will also have to benotified of the termination of the injectionprogram.

Injection Regulations Under the SafeDrinking Water Act

Acting under the authority of the Safe DrinkingWater Act, 60 the Envi ronmental Protect ionAgency (EPA) has issued proposed regulations61

that would be applicable to underground injec-tions for EOR purposes. While these regulationswere not final at the preparation of this report, it is

useful to examine them in the context of the SafeDrinking Water Act and current State controlprograms. Some type of regulation wil l beforthcoming from EPA, even if not in the preciseform of the present proposals.

The Safe Drinking Water Act was passed intolaw as an amendment to the Public Health ServiceAct in 1974. Its purpose is to establish nationaldrinking water standards and ensure minimumprotection against contamination of drinkingwater supplies by well-injection practices. It at-tempts to accomplish this by having EPA issueregulations specifying minimum requirements forState programs to control underground injectionof fluids that may threaten the quality of water inaquifers that are or may be used for public supply.Section 1421 (b) (1)62 of the Act itself sets out theminimum requirements for State programs to con-

trol underground injection. They are, 1 ) onlyState-authorized injections may be continuedafter 3 years from the date of enactment; 2) the in-jector must satisfy the State that his operationdoes not endanger the drinking water; 3) the Stateprogram must have procedures for inspection,monitoring, recordkeeping, and reporting for in-jection operations; and 4) the regulations mustapply to all persons including Federal agencies.

With specific respect to oil and natural gas pro-duction, the Safe Drinking Water Act providesfurther in section 1421 (b)(2) 63 that:

Regulations of the [EPA] Administrator under thissection for State underground injection controlprograms may not prescribe requirements whichinterfere with or impede—(A) the underground injection of brine or otherfluids which are brought to the surface in connec-tion with oil or natural gas production, or(B) any underground injection for the secondaryor tertiary recovery of oil or natural gas, unlesssuch requirements are essential to assure that un-derground sources of drinking water will not beendangered by such injection.

In promulgating regulations setting requirementsfor State programs, it is the interpretation of theAct by EPA that the “Administrator need notdemonstrate that a particular requirement is es-sential unless it can be first shown that the re-quirement interferes with or impedes oil or gasproduction.” 64 Thus, the burden is upon the Stateor the enhanced recovery operator to prove thatthe requirement in question does interfere with orimpede production, and EPA further places theburden on the operator to show that the require-ment is not essential, That is, EPA has stated thatan alternative method of protection of drinkingwater may be approved by the State commission“if the operator clearly demonstrates that (i) therequirement would stop or substantially delay oilor natural gas production at his site; and (ii) therequirement is not necessary to assure the protec-tion of an existing or potential source of under-ground drinking water.”65

it should be observed that EPA does take noteof the fact that oil-producing States have regu-lated injections for years, and does set the re-quirements applicable to injection wells relatedto oil and gas production in a subpart separatefrom requirements for other types of injections.

220 . Appendix C

While EPA-required procedures are similar to ex-isting State procedures for injection permit regula-tion, the proposed regulations would imposemuch more detailed requirements than do currentState procedures. For example, the application re-quirements for new underground injection underthe proposed regulations66 set forth immediatelybelow should be compared with the Oklahomaregulations concerning application quoted onpage 218 of this appendix.

(a) The application form for any new under-ground injection shall include the following:

(1) Ownership and Location Data. The ap-plication shall identify the owner and operator ofthe proposed underground injection facility, andthe location of the facility.

(2) Engineering Data.(i) A detailed casing and cementing

program, or a schematic showing: diameter ofhole, total depth of well and ground surfaceelevation; surface, conductor, and long string cas-ing size and weight, setting depth, top of cement,method used to determine top; tubing size, andsetting depth, and method of completion (openhole or perforated);

(ii) A map showing name and locationof all producing wells, injection wells, abandonedwells, dry holes, and water wells of record withina one-half-mile radius of the proposed injectionwell; and

(iii) A tabulation of all wells requestedunder (ii) penetrating the proposed injectionzone, showing: operator; lease; well number;surface casing size and weight, depth and ce-menting data; intermediate casing size andweight, depth and cementing data; long stringsize and weight, depth and cementing data; andplugging data.

(3) Operating Data.(i) Depth to top and bottom of injection

zone;

(ii) Anticipated daily injection volume,minimum and maximum, in barrels;

(iii) Approximate injection pressure; and(iv) Type, source, and characteristics of

injected fluids.(4) Geologic Data—Injection Zone. Ap-

propriate geologic data on the injection zone andconfining beds including such data as geologicnames, thickness, and areal extent of the zone.

(5) Underground Sources of DrinkingWater Which May be Affected by the Injection.Geologic name and depth (below land surface) ofaquifers above and below the injection zone con-

taining water of 3,000 mg/I total dissolved solidsor less and aquifers containing water of 10,000mg/I total dissolved solids or less.

(6) An electric log on all new wells and onexisting wells where available.

The regulations could broaden the number of per-sons or agencies who could challenge the ap-plication and insist upon a public hearing. Newrequirements would be made for record keepingat several different levels (by governmental agen-cies and operators); there would be a 5-yearlimitation on permits; new standards could be re-quired to be met after an injection program hascommenced under a properly issued permit; andthe specific well requirements go beyond thoseof many States.

A number of parties have objected strenuouslyto these proposed regulations or similar prior pro-posals, and to the general approach taken by EPAunder the Safe Drinking Water Act on the groundsthat this will significantly hinder EOR operationswithout corresponding benefits in the protectionof drinking water. A resolution of the InterstateOil Compact Commission of June 30, 1976, forexample, declared: “The State regulatory agenciesestimate that if the recent draft regulations wentinto effect it would cause a loss of production ofover 500,000 barrels of oil per day and in excessof 2.5 billion cubic feet of gas per day. All of thisis from existing wells that have been producingfor a number of years with virtually no adverse im-pact on the environment.67 While this resolutionreferred specifically to the immediate predecessorof the currently proposed regulation, personnelwith the Interstate Oil Compact Commission indi-cated in personal contact that the current regula-tions could still substantially interfere with or im-pede enhanced recovery of oil.

The Council on Wage and Price Stability re-cently criticized EPA’s proposed regulations onthe grounds that EPA may have both underesti-mated the costs of conducting the State regula-tory programs and misjudged the health benefitsto be gained by the regulations.68 Specifically, theCouncil stated that “EPA’s data regarding benefitsand costs offered in support of the regulations aretoo fragmentary, subjective, and inconclusive toenable an informed decision to be made on thisissue, ” and urged that further evaluations be madebefore putting regulations into effect.69

Finally, both producers and State commissionsidentified the contemplated EPA regulations asbeing likely to hinder or discourage enhancedrecovery operations. Of the responses from pro-ducers, four independent and six large producersstated specifically that the proposed EPA regula-tions would have an adverse effect on operations.An example of such responses was the followingcomment of one independent producer from theState of New York: “EPA-proposed rules andregulations regarding existing underground injec-

tion wells--could have a very negative effect on

enhanced recovery. ” One of the large companiesresponding similar ly stated: “The recently pro-

posed EPA rules concerning secondary recoveryoperations could essent ial ly prohibit newenhanced projects. ” One State agency which hasauthority over several hundred enhanced recov-

Appendix C . 221

ery projects with many more potential projects inthe State said that no permit had been denied forsuch projects but that “Many may be denied nextyear if the Federal UIC [underground injectioncontrol] Regulation is administered as written. ”The American Petroleum Institute has also con-ducted a survey of major and independent pro-ducers and has concluded that “Without doubtthe proposed regulations will interfere with andimpede underground injections and substantiallydecrease the ultimate production and recovery ofhydrocarbons.” 70

In light of the number of such comments, it isclear that EPA-proposed regulations are perceivedas having, or as likely to have, an adverse impacton enhanced recovery operations.

Operational Aspects of Enhanced Oil Recovery

Potential Liability to Nonjoining InterestsRelatively few reported cases have arisen in

which non joining interests have made claims fordamages against unit operators for enhancedrecovery activit ies, a n d fewer sti l l in whichdamages have been awarded. However, the issueis an important one as is suggested by the number

of articles that have been written on the subject.71

As one writer has commented, the small number

of cases is “like the top of an iceberg, it does notreveal the trouble underneath—the number of

secondary [ i .e., enhanced] recovery projects

delayed or hamstrung by threats of litigation, and

the heavy price sometimes exacted by the owners

of minority interests in exchange for coopera-tion. 72 For this reason, it is important to examinebriefly the legal theories upon which claims orliability might be based, the treatment of these bythe courts in the past, and possible approaches tothe problem in the future.

The legal theory upon which a claim fordamages may be based will depend in part uponthe relationship between the claimant who hasnot joined the unit and the operator responsiblefor the enhanced recovery project. If the claimantis a lessor or cotenant of the operator, the claim inmost circumstances will be that the operator hasbreached a duty owed to the claimant or that the

operator has caused waste of property jointlyowned by both the operator and the cotenant. Ifthe claimant is a neighbor owning an interest inthe reservoir, the claim may be based on a theoryof trespass, strict liability (ultrahazardous activity),nuisance, or fault. In general, the courts haveshown a disinclination to award damages on anyof these grounds except the very last—fault.

As discussed in an earlier section, the lease it-self governs most relations between lessor andlessee. Most leases are silent with respect toenhanced recovery, however, and it is necessaryto examine implied rights and obligations thatarise out of the basic relationship. These can beput under many headings, but the general princi-ple that is most important is that the lessee mustact in good faith and do nothing to injure thevalue of the leasehold. While the same relation-ship is not present in a cotenancy situation, it isnevertheless well recognized that one cotenantshould do nothing to reduce the value of the jointproperty without the consent of the other. Ineither circumstance, the most likely claim to beraised by a non joining lessor or cotenant is thatthe lessee/operator is causing or permitting oil

and/or gas to be drained away from the property.Cases have been adjudicated in several jurisdic-tions on this basis and will be described briefly.

222 . Appendix C

In the case of Tide Water Associated Oil Co. v.Stott, 73 a pressure maintenance program was un-dertaken with the approval of the Texas RailroadCommission by the lessee of the claimants. Thelessors (claimants) refused to join in the unit. Thelessee was also the lessee on other nearby tractsand maintained its lease on the lessors’ lands bycontinuing to conduct primary operations there.The lessors sued the lessee on the theory that itwas causing drainage of “wet” gas from undertheir tracts to the other tracts operated by thelessees. The Fifth Circuit Court of Appeals held infavor of the lessee, saying that there was noliability to the nonconsenting lessors becausethey had been given an opportunity to join in theunit operations on a fair basis.

In the case of Carter Oil Co. v. Dees,74 a lesseesought a declaratory judgment allowing it to con-vert an oil production well to a gas injection wellfor enhanced recovery operations. The lessor op-posed this, claiming it would cause drainage of oilfrom underneath his property. Despite a contraryruling on an identical case the previous year bythe Seventh Circuit Court of Appeals,75 the Ap-pellate Court of Illinois held for the lessee on theground that the additional oil gained by the proj-ect through drainage from other land would morethan compensate for the loss from the lessor’sland.

After the Dees case, the Illinois legislaturepassed an act that expressly stated that enhancedrecovery was in the public interest. When a groupof nonconsenting lessors and cotenants at-tempted to block a waterflood operation in thecase of Reed v. Texas Company, 76 the IllinoisSupreme Court relied upon the legislation to holdfor the operator. The court held that the claimantshad been offered an opportunity to participate inthe program on a fair basis, that the State miningboard had approved the project, and the projectwas in the public interest; it stated:

If a minority of one or more persons affected bythe operation could prevent it by refusing to joinin the agreement, they could then force theothers to choose between leaving a large part ofthe oil underground, or consent to granting thedissidents an unreasonably large percentage ofthe oil. in other words, the power to block arepressure program by refusing to sign theunitization agreement, would be the power to in-

sist upon unjust enrichment. Surely a court ofequity would not support such a rule.

In somewhat similar cases, the North Dakota77 andMississippi 78 Supreme Courts followed the sameline of reasoning in holding for the operators ofother enhanced recovery projects.

It should be observed that despite the denial ofdamages to lessors, the lessee-operators in casessuch as the Stott case must still satisfy other re-quirements of their leases to keep them valid.Thus in Stott the operator had to maintain sepa-rate production activities on the leases and had toaccount to the claimants separately from the unitoperation. However, the courts have shown awillingness to support enhanced recovery despitecompeting claims of property rights in minerals.An express statement by the legislature in favor ofenhanced recovery can be of considerable sup-port for this predisposition in litigation of thisnature.

When it is a neighboring interest owner who isclaiming damages the theories asserted in supportof liability are different. By and large, however,the courts have tended to support enhancedrecovery and, with certain exceptions which willbe noted, have denied liability.

In injection programs, the fluid injected sweepsfrom the injection well towards the productionwell (s). The migration of the fluid can cross prop-erty lines, and this fact has led to claims oftrespass by neighboring interest owners who havenot joined in the unit or enhanced recoveryprogram when they have felt the production fromtheir land was reduced by the fluid sweep. Themost important case dealing with this claim oftrespass is a Texas case, Railroad Commission v.Manziel. 79 In rejecting the neighbor’s claim oftrespass, the Texas Supreme Court adopted thetheory advanced by Professor Howard Williamsand Dean Charles Meyers of a negative rule ofcapture. 80 Just as one may produce oil or gas eventhough it migrates from the property of another,so too may one inject a substance into the groundfor production purposes even though it migratesand causes loss of production for a neighbor. Thecourt also supported its denial of liability by not-ing that enhanced recovery is in the public in-terest. No case involving enhanced recovery hasbeen found which has granted damages on a

Appendix C . 223

theory of subsur face t respass by in ject ion of

fluids.

For some types of ultrahazardous activitiesthere is strict liability (liability without a showingof negligent operations) for damages flowing fromthe activity. This legal theory overlaps with theprinciple of nuisance, and the two may be treatedtogether even though one does not usually thinkof enhanced recovery as being ultrahazardous. 81

In an important recent case arising in Oklahoma,the Tenth Circuit Court of Appeals upheld a deci-sion in favor of a claimant for damages for a non-negligent waterflood project. The court, inGreyhound Leasing and Financial Corporation v.

Joiner City Unit,82 relied upon a nuisance provi-sion in the Oklahoma Constitution which statesthat no private property shall be taken ordamaged for private use unless by consent of theowner. Although the unit operator had had theproject approved by the Corporation Commissionand had offered the claimant an opportunity toparticipate in the unit, the court found liability. Itis possible that the court in another jurisdictionmight hold in this manner even without such aState constitutional provision. Because the moreexotic methods of enhanced recovery arerelatively new and untried, there is a greaterpossibility that a court might find them ultrahazard-ous than with normal waterflood operations. Thepossibility of liability on this ground could be adisincentive to operations even though a numberof authorities have expressed disfavor with such aresult. Producers in five States indicated that theyhave enhanced recovery projects being inhibitedby fear of such liability.

The final basis for liability for enhanced recov-ery operations is fault, which includes negligentactions, wanton disregard of the rights of others,and intentional harm. Liability arising from suchactions is well recognized whether primary orenhanced recovery operations are involved. In vir-tually all instances the actions of the operator willbe beyond those included in the order of theState commission. Few would contend thatoperators should have their negligent or inten-tionally harmful acts excused simply because theyare engaged in enhanced recovery operations,although questions might be raised about thestandard of care that should be applied to opera-tors in such projects.

In general, the courts have looked with disfavorupon claimants who have been offered an oppor-tunity to join in an enhanced recovery operationon a fair and equitable basis and have refused tojoin. The commission approval of the projects andpublic interest in enhanced recovery of oil tend tonegate the possibility of liability for non-negligentoperations and lend support to the other legaltheories —such as the negative rule of capture—upon which a court might decide a claim fordamages from a nonconsenting interest owner. AState statute expressing encouragement forenhanced recovery will also tend to negateliability. However, the uncertainty of the law inmany jurisdictions makes the undertaking ofenhanced recovery without joinder of all the in-terests in the unit either voluntarily or throughcompulsory unitization a risky business. Not onlymay operations result in liability, but the merepossibility that a court might so hold could dis-courage unitization by recalcitrant minority in-terests and could provide them strong leverage inbargaining over the participation formula.

Environmental Requirements

Both State and Federal environmental require-ments might affect enhanced recovery in severalways. First, they may cause delay in the approvaland initiation of projects. Second, they may makeenhanced recovery projects a greater economicrisk because they could increase costs, couldcause liability for violations of the requirements,or could force the shutting down of projects. Suchpossibilities could discourage efforts to undertakeEOR projects. It should be noted that present en-vironmental requirements seem to be restrictingonly with respect to enhanced recovery inCalifornia, and EPA’s proposed underground in-jection regulations discussed in a previous sec-tion. The areas of environmental regulations thatmay be of significance for present or future opera-tions relate to requirements for environmental im-pact statements, air quality standards, and limita-tions on water pollution.

Environmental Impact Statements

Environmental impact statements are now re-quired for certain State activities in several States

224 . Appendix C

and for all Federal actions and, proposals signifi-cantly affecting the quality of the human environ-ment. In 1970, the California Legislature enactedthe Environmental Quality Act,83 which requiresvarious State and local governmental entities tosubmit environmental impact reports before un-dertaking certain activities. The affected State andlocal agencies are compelled to consider thepossible adverse environmental consequences ofthe proposed activity and to record such impactsin writing. At least one producer has reported thatthis California requirement has caused “delay inwaterflood projects due to delay in permitsbecause of environmental assessment studies.”These and other requirements had, said the pro-ducer, resulted in “presently over 1-year delay inobtaining permits. ”

The National Environmental Policy Act of 1969in section 102 (2) (c)84 requires an environmentalimpact statement to be completed for everyrecommendation or report on proposals forlegislation and other major Federal actions signifi-cantly affecting the quality of the human environ-ment. Since the Federal Government is now in-volved with enhanced recovery only in limitedareas on Federal lands, this Act does not havemuch effect on enhanced recovery. However,should the Federal Government become involvedin regulation of enhanced recovery, an environ-mental impact statement would probably have tobe filed to meet the requirements of section102(2) (c).

Air Pollution

Air quality requirements are primarily of sig-nificance for thermal recovery projects. Thelegislation of greatest importance in this area isthe Federal Clean Air Act of 1970,85 and the Stateimplementation plans enacted pursuant to it,

Under the Clean Air Act, EPA has establishedprimary and secondary ambient air quality stand-ards. The primary standards are designed to pro-tect the public health and the secondary stand-ards are to protect the public welfare. It is theresponsibility of the States to promulgate plansto attain these standards for each of the pollut-ants for which the EPA has set standards. Limita-tions for air pollution from new sources of pollu-tion are established by EPA itself. In addition, the

Clean Air Act has been interpreted by the courtsas requiring agencies to prevent any significantdeterioration in air quality in areas already meet-ing the standards. Both State and Federal govern-ments can enforce the Clean Air Act, and stiffpenalties may be assessed for violation of regula-tions.

The precise applicability of the Federal andState requirements under the Clean Air Act de-pends upon the size and type of equipment usedin steam generation, the quality of the fuel usedfor providing a heat source, and the quality of theair in the State and region where the operationstake place. Since most ongoing thermal projectsare located in California, it is the State in whichthere is an indication as to the impact of such airrequirements. One producer there indicated thatan application for a number of enhanced recov-ery projects was being delayed while EPA soughtadditional data on the air quality impact of theequipment to be used. The same producer sug-gested that some 25 projects were being delayeddue to present and pending air-quality and land-use regulations. “Thermal recovery projects,” itstated, “have been delayed due to EPA andCounty Air Pollution Control District regulationsand permit requirements. ” At least three otherlarge and small producers stated that they hadmultiple projects being delayed by California air-quality requirements. Hydrogen sulfide regula-tions in Texas have been made more stringent inrecent years, but no producer indicated that thishas had an adverse impact on enhanced recov-ery.

Water Pollution

The most important aspect of water pollution,namely pollution of ground water throughseepage from flooding operations, is governedunder State and Federal law by the Safe DrinkingWater Act as previously discussed. Additionally,the Federal Water Pollution Control Act Amend-ments of 197286 (FWPCA) regulate water quality.Under the FWPCA the discharge of pollutantsinto navigable waters without a permit isprohibited. The term “navigable waters” is verybroadly defined. Severe penalties are providedfor violation of the requirements of the Act.

Appendix C ● 225

Other Environmental Regulation

There are other local, State, and Federal regula-tions that can affect enhanced recovery. Land-useplanning restrictions and zoning, toxic substanceregulation, noise level limits, occupational healthand safety requirements, and other measures mayimpact upon enhanced recovery operations inone way or another. However, the degree of im-pact is highly speculative at this point.

Water Rights

All types of enhanced recovery, as previouslynoted, require water either for flooding purposesor for steam generation. Water of low quality hasseemed adequate in the past, but for some of themore sophisticated techniques of enhancedrecovery, fresh water will be more desirable.Questions of water rights for enhanced recoveryhave generated problems and litigation in thepast, and it can be expected that such issuescould become more important in the future. Abrief treatment of the principles that have guidedthe courts with respect to water rights suggeststhe problems that may be faced in acquiringwater for enhanced recovery.

Before discussing the law applicable to water,it is necessary to mention some of the classifica-tions of water that are made, for the rights mayturn on the classification. Water, of course, maybe found on the surface of the earth or under-

ground. Sur face waters may be c lass i f ied as

diffused (having no defined channel or cour sesuch as a marsh), water courses, lakes, springs, orwaste water. Underground waters may beclassified as underground streams or as percolat-ing waters (having no flow or water course) .87

The right to own or use water can presentquestions in three basic areas. First, there may becontroversy arising between lessor and lessee, orbetween surface owner and mineral interestowner, as to water found on or adjacent to theland where the oil is located. Second, questionscan arise between those who wish to use waterfor enhanced recovery and others who assertrights to the water but have no relationship withthe enhanced recovery project or land on whichit is located. Third, and perhaps overlapping the

other two, will be matters of regulation of wateruse by the States.

Lessor-Lessee Rights

The litigation that has arisen in the past withrespect to water rights for enhanced recovery hasdealt primarily with the respective rights of lessorand lessee, or surface owners and owners ofmineral interests beneath the surface. Forsimplification, reference will be made simply tolessor and lessee. In such litigation, it has beenpresumed that the original owner of the surfaceowned the right to the water and could disposeof it for enhanced recovery purposes; the ques-tion litigated has been whether there was such adisposition, either expressed or implied.

The first type of issue that has arisen iswhether a grant of “oil, gas, and other minerals”(or a similar phrase) has included water as amineral. Courts have held that freshwater is not amineral within the meaning of this clause in an oiland gas lease or deed.88 instead, the courts treatfresh water as belonging to the surface estatewhether the water occurs at the surface or mustbe brought from the underground. Therefore, thelease or deed from the surface owner must ex-pressly grant rights to use of this water, or therights to the water must arise as part of an im-plied right to use of the surface for the develop-ment of the mineral estate. One Texas courtmade a distinction between fresh water and saltwater, holding that salt water is part of themineral estate,89 but the Texas Supreme Courthas since said that salt water and fresh water alikeshould be treated as belonging to the surfaceestate.90

Many oil and gas leases do contain an expressgrant of right to the lessee to use water from thelease premises. They often contain a provisionsuch as the following:91

The lessee shall have the right to use, free ofcost, water, gas and oil found or located on saidland for its operations thereon, except waterfrom the wells of the lessor.

Does this provision, which does not mentionenhanced recovery, authorize the use of waterfrom the land for enhanced recovery purposeswhen such techniques were not known in the

96-594 0 - 7fj . 1 ~

226 . Appendix C

area or to the industry when the lease wasgranted? It is generally treated as authorizing theuse of water on the leased premises for enhancedrecovery, but a notable Texas case, Sun Oil Co. v.Whitaker, 92 to be discussed shortly, declined torule on this question when given the opportunity.A problem with a clause such as the one quotedis that the water for enhanced recovery may haveto be used on other lands and this is not permit-ted by the provision. However, the royaltyowners agreement will include a provision forthis when there is unitization. if a nonroyalty in-terest owner is the owner of the surface, otheragreement will have to be made to authorize theuse of the water off the leased property.

Finally, even if there is no express provision foruse of water for enhanced recovery, there willgenerally be an implied right to use of the water.As stated in a previous section, the lessee has theright to use so much of the surface as may bereasonably necessary to effectuate the purposesof the lease having due regard for the rights of theowner of the surface. This will include water, andseveral courts have expressly applied this impliedright doctrine to water (both fresh and salt) foruse in enhanced recovery operations. 93

The most recent and important of these deci-sions is Sun 0il Co. v. Whitaker.94 In this Texascase, one Gann gave a lease to Sun Oil in 1946and then conveyed away the surface rights toWhitaker in 1948. The lease had an express pro-v i s ion fo r the use o f wate r subs tan t ia l l y l i ke the

one quoted above . A f te r year s o f p roduct ion by

primary methods, Sun decided to waterflood theformation. It received authority from the TexasRailroad Commission to use fresh water for thispurpose, and began producing water from a non-replenishable water formation for the program.The owner of the surface, Whitaker, was usingfresh water from the same formation for irrigationof farmland. Sun sought to prevent Whitakerfrom interfering with i t s product ion, andWhitaker in the same suit sought to prevent Sunfrom using the water for enhanced recovery. Thecourt held, without ruling on the extent of the ex-press provision, that the oil and gas lessee’sestate was the dominant estate, that the lesseehad an implied grant of free use of such part andso much of the premises as was reasonablynecessary to effectuate the purpose of the lease,

that the implied grant extended to and includedthe right to use water in such amounts as wouldbe reasonably necessary to carry out its opera-tions under the lease, and that the waterfloodoperation was reasonably necessary to carry outthe purposes of the lease. It should be noted thatthe court found that no other source of usablewater on the leased tract was available, and thatthe decision was by a narrow majority of five tofour. With only a slight change of facts this courtand any other could easily hold to the contrary,so that an enhanced recovery project operator iscertain of his rights to water only if they havebeen expressly granted for enhanced recoverypurposes .95

Riparian and Appropriation Rights

When the rights to water of parties other thanthe lessor and lessee are considered, several rulesof ownership of rights must be taken up. Theseare the doctrines of riparian rights and rights ofprior appropriation, and some States follow acombination of these two.96 Which rule appliesto a particular State has largely been determinedby the climate and geographical region in whichthe State is located. Generally speaking, thesedoctrines apply to watercourses with under-ground waters being governed by a theory of ab-solute ownership or a reasonable use limitationonly. However, in some States, the rightsdoctrines will apply to underground water as wellas surface water.

Riparian Rights. —The doctrine of riparianrights is found to apply in some 31 States (tableC-2) located primarily in the eastern half of theUnited States, where there is more water. Underthis principle, the owner of land adjacent to awatercourse (the riparian owner) is entitled toreasonable use of such amount of water as he canput to a beneficial purpose. A reasonable use issuch that it will not unduly disturb a lowerriparian’s right to some minimum flow of waterand which is suitable to the character and size ofthe particular watercourse. A limitation on theright is that the water must be used on theriparian owner’s premises, or at least within thewatershed. In States following this principle, per-colating waters are generally treated as beingsubject to absolute ownership by the surfaceowner or a principle like the rule of capture is ap-

plied, so that the underground waters may besold and transported away from the watershed.

The significance for enhanced recovery underthe riparian rights approach is that production ofoil is a beneficial use as is required under thedoctrine, and water generally will be availablefrom one source or another. However, whether

the water is from a watercourse or from under-ground it may be necessary for the operator tocontract for the water. Use of the water forwaterflooding can be enjoined by lower riparianowners only if they can show that there has beenan excessive or unreasonable taking of the water,leaving them with less than their fair share.

Rights of Prior Appropriation.—The doctrine ofprior appropriation developed in the more aridregions of the United States and presently appliesin nine States, commonly designated as theRocky Mountain States. Prior appropriation is thetaking of a portion of a natural supply of water, inaccordance with law, with the intent to apply itto some beneficial use within a reasonable time.As before, enhanced recovery operations do con-stitute a beneficial use of the water.97 The right tothe water is fixed by time, not by location on the

watercourse . Thus , an upst ream appropr iator

who is later in time (junior appropriator) in his ap-propriate ion i s subord inate in r igh t to adownstream prior (senior) appropriator’s right tothe water. Appropriation is a vested right then totake or divert and consume the same quantity ofwater forever.

Ownership of land is generally a prerequisiteto appropriation. However, as has been stated byone authority that “[i] n the absence of statute, ithas always been the rule in States following theappropriation doctrine that an appropriator maychange the use and place of use so long as thechange does not injure other appropriators. 98 Thismeans that, subject to State regulation, a partymay acquire or dispose of his appropriationrights. The importance of this is that operators arefaced with the problem that with prior appropria-tion the right is perpetual with no provisions forshort term appropriation of water. The ability tobuy and sell rights is significant, for the use ofwater for enhanced recovery is of limited amountand duration; the operator must buy on a short-term basis, if possible, or appropriate the water

/

Appendix C . 227

and sell the rights after completion of operations.Where the operator is a junior appropriator, he issubject to having his water diminish or cease en-tirely in times of shortage.

Dual System. —Some 10 States apply a com-bination of the two principles described aboveknown as the California doctrine. That is, theyfollow a rule that a riparian owner may take waterfrom a source but only as much as he can put to areasonable beneficial use. Surplus water is sub-ject to appropriation by nonriparian owners or toexport by riparian owners to nonriparian lands;but this appropriation or export is junior to theprior rights of the riparian appropriators. Beyondthis, generalization is very difficult, for the Stateshave gone in different directions through courtdecisions and legislation.

As stated previously, EOR is regarded as abeneficial use of water. While a nonriparianoperator may acquire rights for water in the dual-system States, his rights will be subject to priorappropriation by those senior in rights to him.Ground water is likely to be the subject of speciallegislation in such States.

State Regulation of Water Use

The trend in the current development of waterlaw has been, as noted by the leading authorityon the subject, “toward more public regulationsthrough permit systems, accompanied by newlegislative efforts in some States to recognize theinterrelationship between many surface andground water sources and to combine the con-trols and management under one statute.99

Regulation is more comprehensive generally inthe more arid Western States than in the morehumid Eastern States, although the Eastern Statesdo regulate pollution of waters. A number ofWestern States following the prior appropriationdoctrine have agencies which regulate the ac-quisition, transfer, or change of appropriationrights. Because regulation of ground water is ofrelatively recent date in most States, its treatmentin statutes tends to be more comprehensive thanfor surface waters, and the permit systems aremore extensive.

Whether surface waters or ground waters areto be used in enhanced recovery, it is likely, par-ticularly in the western half of the United States,

—

228 . Appendix C

that an operator will have to be issued a permitacknowledging his right to the water prior tousing the water he has acquired for the EOR proj-ect. This will probably be done through the officeof a State engineer, a commission, or a waterresources board in a proceeding separate fromthe one for a permit to inject the water. The pro-cedure is similar to that for getting approval forthe EOR project. There have been few cases aris-

ing from administrative problems involvingenhanced recovery projects, and little or no in-dication from the literature or the questionnairesthat State regulation of water rights has causedany problems for enhanced recovery. The poten-tial for problems exists, however, because theagencies might likely become focal points forcompeting claims over the uses to which freshwater should be put.

Table C-1Unitization Statues: Voluntary and Compulsory

[Adapted from Eckman, 6 Nat. Res. Lawyer 382 (1973)]

Statute Citation

Alabama. . . . . . . . . . . . . . . . . . . . . . Code of Ala., Tit. 26, ~fj 179 (70) to 179(79)Alaska. . . . . . . . . . . . . . . . . . . . . . . . Alas. Stat. $31.05.110Arizona. . . . . . . . . . . . . . . . . . . . . . . Ariz. Rev. Stat. $$27-531 to 27-539Arkansas. . . . . . . . . . . . . . . . . . . . . . Ark, Stat. Ann. 1947, $53-115, C-1 to C-8California Subsidence. . . . . . . . . . . Calif. Pub. Res. Code $$3321 to 3342California Townsite . . . . . . . . . . . . Calif. Pub. Res. Code Q$ 3630 to 3690Colorado . . . . . . . . . . . . . . . . . . . . . Colo. Rev. Stat. 1963, 100-6-16Florida. . . . . . . . . . . . . . . . . . . . . . . . Fla. Stat. Ann. ~ 377.28 (1) and (2)Georgia. . . . . . . . . . . . . . . . . . . . . . . Ga. Code Ann. $43-717 (b) and (c)Idaho . . . . . . . . . . . . . . . . . . . . . . . . Idaho Code ~ 47-323Illinois, . . . . . . . . . . . . . . . . . . . . . . . Smith-Hurd, Ill. Rev. Stat. Ch. 104$84 b, cIndiana . . . . . . . . . . . . . . . . . . . . . . . Burns Ind. Stat. ~ 46-1714 (b) and (c)Kansas. . . . . . . . . . . . . . . . . . . . . . . .Louisiana Subsection B. . . . . . . . . .Louisiana Subsection C . . . . . . . . .Maine . . . . . . . . . . . . . . . . . . . . . . . .Michigan . . . . . . . . . . . . . . . . . . . . .Mississippi . . . . . . . . . . . . . . . . . . . .Missouri . . . . . . . . . . . . . . . . . . . . .Montana. . . . . . . . . . . . . . . . . . . . .Nebraska . . . . . . . . . . . . . . . . . . . . .Nevada. ... , . . . . . . . . . . . . . . . . . .New Mexico . . . . . . . . . . . . . . . . . .New York. ... , . . . . . . . . . . . . . . . .North Dakota. . . . . . . . . . . . . . . . . .Ohio. . . . . . . . . . . . . . . . . . . . . . . . .Oklahoma . . . . . . . . . . . . . . . . . . . .Oregon. . . . . . . . . . . . . . . . . . . . . . .South Dakota. . . . . . . . . . . . . . . . . .Tennessee . . . . . . . . . . . . . . . . . . . .Texas . . . . . . . . . . . . . . . . . . . . . . . .Utah . . . . . . . . . . . . . . . . . . . . . . . . .Washington . . . . . . . . . . . . . . . . . . . .West Virginia. . . . . . . . . . . . . . . . . .Wyoming . . . . . . . . . . . . . . . . . . . . .

Kans. Stat. Ann. $$55-1301 to 15-1315La. Rev. Stat. 1950, Tit. 30, # 5BLa. Rev. Stat. 1950, Tit. 30, $ 5CMe, Rev. Stat. ~ 2159Mich. Comp. Laws Ann. 3$319.351 et seq.Miss. Code 1972 ~$ 53-3-101 to 53-3-110Rev. Stat. Mo. 1969, $259,120Rev. Code of Mont. 1947, $$ 60.131.1 to 60.131.9Re. Rev. Stat. Neb. 1943, $57-910Nev. Rev. Stat. 522.070N.M. Stat. Ann $$ 65-14-1 to 65-14-21N.Y, Environ. Conserv. Law $23-090, subdivs. 1, 3-12No. Dak. Cent. Code $$ 38-08-09.1 to 38-08-09.17Ohio Rev. Code $1509.2852 Okla. Stat. Ann. $~ 287.1 to 287.15Ore. Rev. Stat. 520.270 to 520.330So. Dak. Comp. Laws 45-9-37 to 45-9-51Term. Code Ann. 60-104 (d) (13)Vernon’s Civ. Stat. Tex. Ann., Article 6008bUtah Code Ann. 40-6-17Rev. Code Wash. ~~ 78.52.340 to 78.52.460W. Va. Code 1931 $4 22-4 A-8 to 22-4 A-9Wyo. Stat, ~ 30-222

Appendix C . 229

Table C-2Comparative Chart of Aspects of Unitization Statutes

State

Alabama . . . . . . ., . . .Alaska ., . . . . . . . . . . .Arizona . . . . . . . . . . . .Arkansas . . . . . . . . .California Subsidence*California Townsite* . .Colorado. . . . . . . . . . . .Florida . . . . . . ., . .Georgia .., . . . . . . . . . .Idaho, . . . . . . . . . . . . .IIllnols ., . . . . . . . . . . .,Indiana . . . . . . . . . . . . . .Kansas . . . . . . . . . . . . . .Kentucky. . . . . . . . . . . .Louisiana Subsection B.Louisiana Subsection CMaine . . . . . . . . . . . .

Michigan” ’””’”” ““”’”Mississippi . . . . . . . . . . .Missouri . . . . . . . . .Montana. . . . . . . . . . . .Nebraska. ., . . . . . . . . .Nevada . . . . . . . . . . . . .New Mexico, . . . . . . .New York . . . . . . . . . . . .North Dakota . . . . . . . .Ohio . . . . . . . . . . . . . . .Oklahoma . . . . . . . . . . .Oregon . . . . . . . . . . . . . .South Dakota.. . . . .Tennessee. ., . . . . . . . .Texas. ., . . . . . . . . . .Utah. .,... . . . . . . . .Washington . . . . . . . . . .West Virginia . . . . . . . . .Wyoming . . . . . . . . . . . .

Percent working orroyalty int. req’d

vol. = voluntary only:

7562.5637565758075Nonevol.75

None7575None75

85-W -65-R758575807562.57560806563757550vol.80None7580

Inc. ult.recovery

YesYesYesYesNoYesYesYes——

YesYes

YesYes

YesYesYesYesYesYesYesYesYesYesYesYesYesYesYes

——

YesYesYes

Proof or findings required

Preventwaste

YesYesYesYesNo——

Yes—

YesYes

YesYesYesYesYes—

YesYesYes—

YesYesYes—

Yes—

YesYesYes

YesYesYesYesYes

Protect corr.

rights

YesYesYesYesYesYesYesYes—

orYesYes

YesYes

Yes—

YesYesYesYesYesYesYesYesYesYesYesYesYes

YesYesYesYesYes

Add.costnot over

add. recov

YesYesYesYesYesYesYesYes——YesYesYesYes

YesYesYesYesYesYesYesYesYesYesYesYesYesYesYes

YesYesYesYesYes

Unit areaPart or All ofSingle orMultip.pools

PAMPASPASPASPAM

ASPAMPAMPASPAMPAMPASPASPAMPASAM

PAMPAMPAMPASPAMPAMPASPASPASPAMPASPASPAMPAM

PAMPASA MAS

PAM

Water rights

doctrineR-riparianPA-prior

appropriationD-dualsystem

RPAPARDD

PARR

PARRDRRRRRDR

PAD

PAPARDRDDDRD

PADR

PA

● See text, page 211.Adapted in part from Eckman,6Nat Res. Lawyer 384(1973).

—

230 . Appendix C

APPENDIX CFOOTNOTES

I The description here is of what 15 known as the “unless”type lease, the type In use in most States. A slightly differenttype lease, an “or” lea5e, is In use In Cal ifornla, T h ed i f f e r e n c e b e t w e e n t h e t w o r e l a t e s pr{marily to theautomatic termination of the lease in the primary term forthe “unless” lease. H. Willlams and C. Meyers, 0// and GasLam, $601.5 (1975).

‘Gray, “A New Appraisal of the Rights of Lessees Under011 and Gas Leases to Use and Occupy the Surf ace,” 20Ro( ky ,tlt. klIn. L, Inst. 227 (1 975).

‘CarI(Ir 011 V. O(>(’S, 92 N. E.2d, 519 (1 950).

~Merrl I I, ‘‘ Impl led Covenants and Secondary Recovery,4 OLla, 1. K(IV 177 (1 951); Walker, “Problems Incident tothe Acqulsltlon, Use and Disposal of Repressuring Sub-stances Used In Secondary Rec f)very Opera tions, ” 6 RockyAl[. $lin L lns[ 273 ( 1 9 6 1 ) ; see also, H. Wllllams .lnd C .

M e y e r s , 0/1 and Cm Law $ 935 (1 975), and cases andauthorities cited therein.

‘) Martin, “A Modern Look at Implied Covenants to Ex-plore, Develop, and Market Under Mineral Leases, ” 27th Oil& Gas In)t 177 (Matthew Bender 1976).

‘Iln re Shaller’s Estate, 266 P.2d 613, 616-617 (Okla.1 954).

- Tlcf~’w.~(tlr 0// Cc), v. Il>nix, 223 F. Supp. 215, 217 (E.D.Okla. 1963).

See generally, Interstate Oil Compact Comm isslon, AStudy ol Con\erva(ion of 011 and Gas in (he Unltcd S(a(es,13-14 (1964).

‘)The rules and regulations (No. 105) of the Arizona Oiland (jas Conservation Commission, to cite another exam-ple, provide that an 80-acre spacing will apply for oil wellsin the absence of an order by the Comrnlsslon providing forthe spac Ing of wells and establishing dralhage or drillingunits for a reservoir.

10A recent treatment O( the subject is Bruce, ‘‘Maximum

Efficient Rate—Its Use and Misuse In Production Regula-ti~~n,tf 9 Nat, R~~~ Ldwyc’r 441 (1 976)

‘z Ibid,

1‘R, Myers, The Law o) Poo/Ing and Unltlzatlon ~ 3.02(2)(,2d (’d. 1967).

14H. Wllllams and C. Meyers, Oil and Gas Law $ 339.3,1975.

1‘For cj i Sc Ussion of th IS unit, OTA has drawn upon prutz -

man et al , “Chronicle ot Creating a Fieldwlde Unit, ” .5th Na-oonal lrr~(. for P(’troleum Landn-ten 77 (1 964).

I ~JDesc rlptlon of the establ i shment of th is uni t is Con-

tained in R. Myers, The Law of Pooling and Unitization Ch. IV(2d ed. 1967) and the discussion of unit formation whichfollows is largely drawn from this work.

ITlbid, ~ 10.08 (1 976 SUpp. ).

‘aIbid. ~ 10.07.

lgEnhanced Oil Recovery, National Petroleum COUnCi!,

(December 1976), 87.

Wbid. 88,

‘l Ibid. 89,

-“R. Myer~, The LJI$ of Poollng and Unitization $4.02 (2ded. 1967).

231bid.

Wbid. ~ 4.06,

“)Appendix C gives the citation to each State’s compul-sory unitization statute and the basic requirements of eachState’s act(s) (tables C-1 and C-2).

-’(’43 U.S.C. $1 334(a) (l).

1’OCS Order 11 (16) (Cult of Mexico Area).

~80CS Order 11 (15) (Gulf of Mexico Area).

1’Eckman, “Statutory Fieldwide Oil and Gas Units: AReview for Future Agreements, ” 6 Nat, R(JJ, Lawyer 339(1 973); Lawson, “Recent Developments in Pooling andUnitization, ” 23rd Oil & Gas ln~[, 145 (1 972); R. Myers, TheLaw of Poollng and Uni(iza[ion, Ch. IX (2d ed. 1967); W .Summers, The Law O( Oil and Cm, Chs. 29, 31 (1 966); H.Wllllams and C. Meyers, Oil arrd Gas Laws $913 (1 975).

~llLoulsiana Revised Statutes, Title 30, Ch. 1, $ 6(B).

‘lE.g., Moore 0//, /nc. v. Snakard, 150 F. Supp. 250 (W.D.Okla. 1957), remanded on joint motion of parties, 249 F.2d.318 ~lOth Cir. 1957).

~11 1 Alaska Administrative Code $ 22.540.

I ~Colcjrado, for example, provides that any party to the

commission’s rehearing who is dissatisfied with the disposi-tion of the application for rehearing, “may appeal therefromthe district court of the county wherein IS located any prop-erty of such party affected by the decision, by filing a peti-tion for the review of the action of the commission withintwenty 120] days after the entry of the order followingrehearing or after the refusal for rehearing as the case maybe, ” Colorado Revised Statutes, Title 65, Article 3$ 22(b).

~~Vernon’5 TeX. Ann. Civ. Stat,, Article 6008b $ 1

1’Louisiana Revised Statutes, Title 30, Ch. 1, $ 5C.

1“Oklahoma Statutes, Title 52, $287.4.

lzlbid. 5287.6.

$8pr(jdLj( (Jrj lj(~velopm(~nt (-0, v. ,Lfa~na 011 C orp , 371

P.2d 702 ((lkla. 1962 ) .

‘“H. Wlillams dnd C , M e y e r s , 0// and Gaj LJJV $ 9 7 0(1 975), and c ases disc ussed therein.

‘“EC kman “Statutorv Fleldwlde O i l a n d Gas U n i t s : ARev Iew for Future Agrtwments, ” 6 hat. R(I$ la~$i [’r 339, 360(1 973).

‘l E.g., Wyomlrrg Statutes Annotated, $30-222.

‘JH. Wtlllam$ a n d C. M e y e r s , 0// anc] Ga$ Lati $ 9 1 1(l 977); R Myt~rs, The L~Iv ol Pool ing a n d UmfIza(Ion, Ch.X11, (2d ed. 19671

~! J1 7 u s. 341 (1 943).

-lJR M y e r s , Th(I / ail oi P(x)//n,g a n d Un~/~/al/on $12.() j (1 J , I Jd cd 19671.

‘; Unl((Id 5[al(’~ v. ( [~lfon Vallc! operators C o m m i t t e e ,75 F. $upp. 1, 77 F. Supp 409 ~W D. La, 1948), afi’d 339 U.S.940 (1 950).

~“H, Wll!lam\ and C. Meyer>, 01/ Jnd Ca$ / a~%f ~ 953( 1 975).

“-Oklahorn.~ C<~rporatl[m Comml>sion, General Rules andRegu I at lon~ of (1 I I and G a s C o n s crvdt Ion DI v i s ion , $2-261 (d]

‘fiE.g , Texa~ Railroad Commrssltm, 011 ~nd Gas Divtsrcm;Rule 48, New M[)XICO OIi Conservat ion Commlsslon, Rule7 0 1 [, 3

“I IJ{J(I \l’a/(lr Alsjo( Mt(Id 0// C(), v Stott, 159 F, 2 d 1 7 4

[5th Clr. 1946), cert. denied 331 U.S. 817 (1 947).

‘Iof)ob$on” v, Arkdr?sa\ 0// drr~ Gaj (-cm~mJ$$Ion, 2 3 5S E1’.2d 33 (Ark 1 9 5 0 ) .

‘ l O t h e r example~ inc Iude R(Ipubl/( Natural (hs C O v,B~L(Ir, 197 F 2d 647 (1 Oth Clr. 1952); Cor/(Iy v. M)sslsslppiS/att C)II an(l Gaf B(xard, 105 $ 2d 633 (M I S S. 1958); f3arrr -

I%J(III, In( v. )[ In ()// Co , 162 S 2 d 6 3 5 ( M i s s . 1 9 6 4 ) S e eg[>nerdlly, Ii W IIllams and C. Meyers, 01~ and G~\ la~v $933(1 975)

-’ ( )m( )n R,] f/roc?d Co v. 011 dnd Ca\ Conserkd(lon Com-

rn /$$ /e r r , 284 P.2d 242 (COIO, 1955),

‘‘t k~/m(’r/( b & Payne, /nc, v, Colporallon C’ommfsslon,532 P.2d 419 (Okla. 1975).

IiA State by State brief treatment rs Interstate 011 Com-

pact Commission, Summdr) 0/ .%~cond<]r) Recoh(’ry a~)d

Pro$sur(] ~la~n(erranco Ru/(Is ,]nd Regulallfm$ In t i r e Um(~JcfS/a~(’\ (S~~ptember 1969).

> INCW M e x i c o (JII C o n s e r v a t i o n Commissl(~n, R u l e701 B 1,

“ {) Kansas Corporatl[~n Commlssitm, (;enf~r,ll Rule\ andRegulat ions, $ 82-2-502, A well log IS the writ ten recordd(~s[ rl blng the strata, water, oil or Has encountered I n drll I -

Append;x C . 231

ln~ a well with such addit ional information as to gasvolumes, pressures rate of fill-up, water depths, cavingstrata, and casing record as is usually recorded in the normalprocedure of drilling. /b/d., $82-2-101,

“E.g. Texas Railroad Commission, 011 and Gas Division,Rule 36(c) (1 O) pertaining to hydrogen sulfide Injections,

W 1 Alaska Administrative Code $ 22.400(c).

>(lMlch igan, for example, gives the supervisor ~Jt’ wel iS the

authority, as part of his power to prevent waste, “To requirethe locating, drilling, deepening, redrilling or reopening, c ds-ing, sealing, operating and plugging of wells drflled for 01 Iand gas or for secondary recovery projects, or wells for thedisposal of salt water, brine or other oil field wastes to bedone in such manner or by such means as to prevent theescape of oil or gas out of one stratum into another, or ofwater or brines into oil or gas strata; to prevent pollutlondamage to or destruction of fresh water supplles Includinginland lakes and streams and the Great Lakes and connect-ing waters, and valuable brines by oil, gas or other waters, toprevent the escape of oil, gas or water into workable coal orother mineral deposits; to require the disposa I of 5.11 t w,, ter

and brines and oily wastes produced Inc Idcntal to oIl andgas operations, in such manner and by such methods andmeans that no unnecessary damage or danger to or destruc-tion of surface or underground resour( es, to neighboringproperties or rights, or to life, shalAnn $ 319.6(c).

(1042 USC, $$ 300 f-300j-9.

~~140 CFR Part 146, 41 Fed. Reg.

‘):42 U, S.C.$ 300h (b)(1).

bJ[bid. $! 300h (b) (2).

~IA41 Fed, Reg. 36731.

bjlbid.

result. ” M Ich. Comp Lavv

36730 (August 31, 1976)

~blbid. 36744. 40 CFR $ 146.47.

““35 0 1 / & Gas Comp<l( / Bu//ef/n, ]unt~ I 976 p 1 3 ,

‘nCouncil on Wage and Price Stabi lit y Release CM’ PS-204IO(t. 27, 1976).

w Ibid. at 23-24.

‘~JLetter of Roy F. Ca I son, Production D I ret tor, Amc) rl c a n

Petroleum lnstitut[~, Dall~s, Tex., to Office ot Water Supplv,Environmental Protection Agency, W~shlngton, D C,, underdate of Jan, 12, 1977.

~ I A I ist of these is contal ned I n H. W I [ I lams and CMeyers, (JII and Ga\ Law, $ 204.5 (1 975 I,

‘JLynch, “Liability for Secondary Rec oierv (){wr,~tlons,”22nd 0// & Ca\ /ns[, 37, 79( I 97 I ),

-‘1 59 F, 2d 174 (5th C ir. 1946), cert. deni[d, 3 I I u $ 817

( 1 947),

“J92 N E 2d 519 III I app, 1 9 5 0 ) .

232 . Appendix C

“;Ramsey v. Carter Oil Co., 74 F. Supp. 481 (E. D. Ill.1947), affm’d 172 F.2d 622 (7th Cir.), cert. denied 337 U.S.958 (1949), reh. denied, 338 U.S. 842 (1949).

‘[,1 59 N . E . 2d 641 (1 I I 1959) .

“7Svverson v. North Dakota State Industrial Commission,111 N.W.2d 128 (N.D. 1961).

‘HCallfornia Co. v. Britt, 154 So.2d 144 (Miss. 1963 ) .

“361 S,W.2d 560 (Tex. 1962).

HOH, Will lams and C. Meyers, 0// and Gas 1.Jw, $ 2 0 4 . 5

(1 975).

. ~lLynch, “Liablllty for Secondary Recovery Operations, ”2 2 n d 0// & Gas /nst 39, 65 (1971).

w444 F.2d 439 (1 Oth Clr. 1971 ).

~ ICa] ifornld Publ IC Resources Code $$ 21000-21151.

M42 LJ. S.C. S 4 3 3 2

“;42 IJ. S.C $$ 1857 e( seq

l i 033 u ,s ,C $$ 1151 (’~ $W

‘“These c Iassitications by Hutchins have been critic Izedbut they remain useful and have been important in thedevelopment of water law. See R. Clark, VIatcrs and WaterR@ I/s $ 3.1 (1 967).

88Vogei V. Cobb, 141 P.2d 276 (Okla. 1943) ; Mack oilCo v. Laurence, 389 P.2d 955 (Olka. 1964); H. Willlams andC. Meyers, 0// and GI$ Law $219.6 (l 975).

~~An]~)<]h~ador C)II c o , v, Robertjon, 3 8 4 S.W 2 d 7 5 2

(Tex. Civ. App. 1964).

Y~JRob/nson V. Robbin \ Pe(roleum Corp , 501 S. W. 2d

865 (Tex. 1973).

‘[l Walker, “Problems Incident to the Acquisition, Use andDisposal of Repressuring Substances Used in SecondaryRec every Operations, ” 6 t h R o c k y Mt. M/n. L. /nsr 2 7 3(1 961).

“:483 S.W.2d 808 (Tex. 1972).

‘~E.g., HoI( V . SoLIthIve$/ ArrtIoc h S a n d UrrIt, FifthEnlarged, 292 P,2d 998 (Okla. 1955).

w483 S,W.2d 808 (Tex. 1972).

9:A subsequent Texas case held the implied right to usewater from the surface of the leasehold did not extend touse of the water for operations otf the leased premisesRobinson v. RobbIns P((rolcum Corp., 501 S.W,2d 865 (Tex.1 973).

“fiThe discu~sion which follows IS drawn primarily fromthe following sources: R. Clark \f’ater and \Va(er RiglI(spaSSIrTI (1 967); Losee, “Le~al Problems of a Water Supply forthe Oil and Gas Industry, ” 20 th Oil & Gas Inst. 55 (1969);Trelease, “The Use of Fresh Water for Secondary Re[ everyof O i I in the ROC ky Mountain States, ” 16th R(K ky $4(. Min. L./nst, 605 (1 971); Walker, “Problems Incident to the Acqulsl-tlon, Use and D!sposal of Repressuring Substances Used inSecondary Re( every operations. ” 6th R(x k v M(. M/n. L./rr\f, 273 (1 961).

‘-hlafhc’rs v. Texm o, 421 P.2d. 771 (N. M. 1966)

‘l}’ Losee, “Legal Problems of a Water Supply for the 011and Gas Industry,: 20th 0// & Gas Inst. 55, 81 (1 969).