Bennion v. ANR Production Co.

819 P.2d 343, 172 Utah Adv. Rep. 3, 116 Oil & Gas Rep. 401, 1991 Utah LEXIS 142, 1991 WL 216573

• Court: Utah Supreme Court
• Decided: October 21, 1991
• Docket: 900473
• Status: Published

Opinion

DURHAM, Justice:

This is a case of first impression on the rights of a nonconsenting mineral owner under the forced pooling provisions of the Utah Oil and Gas Conservation Act. The case raises questions regarding the drilling of increased density wells in a drilling unit already subject to a forced pooling order. The operative facts span nearly two decades, from 1971 to 1990. During that period, the Oil and Gas Conservation Act underwent several amendments and a complete repeal and reenactment. We discuss the effect of those changes on the parties’ rights and liabilities, and we examine constitutional and statutory challenges to certain changes in the act.

In 1971 and 1972, in the exercise of its statutory powers, the Utah State Board of Oil, Gas and Mining (the Board) established oil and gas drilling units for large areas of the state. See Bennion v. Utah State Bd. of Oil, Gas & Mining, 675 P.2d 1135, 1137 (Utah 1983). The Board made each 640-acre geographical section a drilling unit and authorized the drilling of only one well on each unit. Id. Sam H. Bennion is the owner of an unleased mineral interest in certain property located in Section 1, Township 2 South, Range 5 West in Duchesne County. The property was included in one of the drilling units established in 1971. By issuing the 1971 order, the Board fixed the location of the unit well and precluded Bennion from drilling his own wells.

Under a communitization agreement dated June 12, 1973, all of the owners of working interests in the drilling unit except Bennion voluntarily pooled their interests pursuant to Utah Code Ann. § 40-6-6(5) (then codified at § 40-6-6(f)). The Tew 1-1B5 well (the first well) was designated as the unit well. It was completed as a producing well on July 7,1974. In 1975, Benn-ion filed a petition requesting that the Board order the interests in the unit pooled pursuant to its statutory power under section 40-6-6(5) (then codified at § 40-6-6(f)). 1 A statutory pooling order was entered by the Board on April 30, 1981, retroactively effective July 26, 1979. 2 The terms of the 1981 order were the result of negotiations between the Board, Bennion, and the unit operator. The order accounted for and applied only to the first well, providing that once the well reached payout, 3 Bennion was to receive a share of production upon payment of a share of the monthly operating costs. The order made no finding concerning the sharing of costs between consenting and nonconsenting owners.

In April 1985, the Board issued an increased density well order permitting an additional well on the subject drilling unit. 4 In 1986, ANR Production Company (ANR) became the operator of the first well. On February 6,1990, ANR commenced drilling the Miles 2-1B5 well (the second well) within the boundaries of the drilling unit. Bennion was given the opportunity to participate in the drilling of the second well, but he refused.

In a petition dated April 10, 1990, ANR requested that the Board either enter a new order or modify the 1981 order to lay out. the costs Bennion would be required to pay and the revenues he would be entitled to receive as a result of the second well. On September 20, 1990, the Board entered an order modifying the 1981 order. The modified order incorporates the second well, allowing Bennion to receive a royalty from the time of first production. Before he can receive a working interest share of production, however, the new order requires Bennion to pay his share of 100 percent of the costs of surface equipment beyond the wellhead, 100 percent of the operating costs, and 175 percent of the costs of drilling, completing, and equipping the well.

In this appeal, Bennion requests that this court review the Board’s 1990 action modi fying the 1981 order. He raises four issues: (1) whether the imposition of a statutory nonconsent penalty is inconsistent with the declaration of public interest contained in the Utah Oil and Gas Conservation Act; (2) whether the penalty is unconstitutional, either on its face or as applied, as a taking or a violation of due process; (3) whether the Board lacks statutory authority to modify a forced pooling order; and (4) whether the 1985 order requires the operator to make a showing of economic feasibility to the Board prior to the drilling of a second well. We treat these issues in order.

I. CONFLICT WITH THE DECLARATION OF PUBLIC INTEREST

Bennion argues that the imposition of a nonconsent penalty in this case is inconsistent with the statutory declaration of public interest contained in the Oil and Gas Conservation Act. 5 This is a question of law to be reviewed under a correction-of-error standard. See Utah Code Ann. § 63-46b-16(4)(d); Morton Int’l v. Utah State Tax Comm’n, 814 P.2d 581, 587 (Utah 1991); Savage Indus. v. Utah State Tax Comm’n, 811 P.2d 664, 669-70 (Utah 1991). In pertinent part, the declaration of public interest contained in the Oil and Gas Conservation Act provides:

It is declared to be in the public interest to foster, encourage, and promote the development, production, and utilization of natural resources of oil and gas in the state of Utah in such a manner as will prevent waste; to authorize and to provide for the operation and development of oil and gas properties in such a manner that a greater ultimate recovery of oil and gas may be obtained and that the correlative rights of all owners may be fully protected....

Utah Code Ann. § 40-6-1 (1988). Bennion argues that the modification of the 1981 order requiring him to pay nonconsent penalties for the second well does not protect his correlative rights pursuant to the statutory directive.

“Correlative rights” are defined under section 40-6-2 of the Utah Code as “the opportunity of each owner in a pool to produce his just and equitable share of the oil and gas in the pool without waste.” The statute requires the protection of all owners’ correlative rights, of course, not just Bennion's. A nonconsent penalty clearly protects the participating parties by compensating them for the risk they assume in drilling the well. 6 In addition, such an allocation of risk and benefits protects nonconsenting parties’ rights by allowing them to receive revenues (in addition to a royalty) from a well for whose drilling costs they are not liable. The imposition of a penalty on nonconsenting working interest owners is a reasonable way to allocate risks and balance the diverse interests involved in the pooling of oil and gas interests. See Application of Kohlman, 263 N.W.2d 674, 678-79 (S.D.1978). Taken as a whole, forced pooling in general “prevents waste,” provides for “a greater ultimate recovery of oil and gas,” and protects “the correlative rights of all owners” pursuant to the purposes of the Oil and Gas Conservation Act. Accord Palmer Oil Corp. v. Phillips Petroleum Co., 204 Okl. 543, 231 P.2d 997, 1005 (1951), appeal dismissed for lack of substantial federal question, 343 U.S. 390, 72 S.Ct. 842, 96 L.Ed. 1022 (1952). As part of the statutory scheme, the nonconsent penalty is entirely consistent with those objectives.

II. THE CONSTITUTIONALITY QUESTION

Bennion challenges the statutory nonconsent penalty as an unconstitutional taking and a violation of due process. Under the Utah Administrative Procedures Act, we may grant relief if we find that an agency’s order was based on a statute which is unconstitutional on its face or as applied. Utah Code Ann. § 63-46b-16(4)(a). When legislative enactments are attacked on constitutional grounds, we apply a presumption of validity “so long as there is a reasonable basis upon which both provisions of the statute and the mandate of the constitution may be reconciled.” Timpanogos Planning & Water Management Agency v. Central Utah Water Conservancy Dist., 690 P.2d 562, 564 (Utah 1984); see Mountain States Tel. v. Garfield County, 811 P.2d 184, 187 (Utah 1991); State v. Rio Vista Oil, Ltd., 786 P.2d 1343, 1349 (Utah 1990). The burden is on the petitioner to affirmatively demonstrate the unconstitutionality of the statute. See Mountain States Tel., 811 P.2d at 187; Rio Algom Corp. v. San Juan County, 681 P.2d 184, 191 (Utah 1984).

In 1955, the Utah legislature first enacted the legislation now known as the Utah Oil and Gas Conservation Act. 1955 Utah Laws ch. 65. The statute created the Oil and Gas Conservation Commission (now known as the Board of Oil, Gas and Mining), id. at § 3, and gave that agency the power to establish drilling units, id. at § 6(a), and to enter orders pooling “all interests in [a] drilling unit for the development and operation thereof,” id. at § 6(f). The original statute provided that pooling orders should allow for the reimbursement of nonconsenting working interest owners’ shares of costs out of production from the unit, id. at § 6(g) (codified at § 40-6-6 (Supp.1959)); it contained no nonconsent penalty for failure to participate in a well. In 1977, the Oil and Gas Conservation Act was amended to add such a penalty; the amount of the penalty was 120 percent for a well in a proven field and 150 percent for a well drilled “to a different common source of supply or in an area not proven for production.” 1977 Utah Laws ch. 161, § 1. In 1983, the Utah Code was amended to its current form, which provides for a statutory nonconsent penalty ranging between 150 percent and 200 percent. 7 1983 Utah Laws ch. 205, § 1 (codified at § 40-6- 6(6)(b)). In this case, the allocation of costs and revenues established by the Board in its 1990 order conforms to the 1983 version of the statute.

Bennion argues that the statute mandating a nonconsent penalty is unconstitutional on its face and as applied because it is a taking of a property right without just compensation. This argument is without merit. Bennion confuses the concept of a vested property right with an obligation to pay a share of drilling costs. The modification of the 1981 order and the imposition of a nonconsent penalty did not divest Benn-ion of any property right. He still owns a mineral interest and has a right to a royalty. See Bennion v. Utah State Bd. of Oil, Gas & Mining, 675 P.2d at 1142. Any right he has to a statutory share of production as a nonconsenting working interest owner is, however, subject to the payment of a share of costs and expenses, including a share of risk compensation which results from his election not to contribute to the drilling costs.

Bennion had the right to participate — or not participate — in the second well on condition that certain requirements were met. That he had the option of participating in the costs of drilling or being subject to a penalty was a grant to him (at the expense of the participating working interest owners) because of the statute’s recognition of correlative rights. 8 See Anderson v. Corporation Comm’n, 327 P.2d 699, 703 (Okla.1957), appeal dismissed for lack of substantial federal question, 358 U.S. 642, 79 S.Ct. 536, 3 L.Ed.2d 567 (1959). The parties were forced to cooperate for their mutual benefit and for the protection of the public generally. Id. A nonconsent penalty is “designed to ensure that nonpartie-ipating owners do not benefit from the successful outcome of risks they do not take.” In re SAM Oil, 817 P.2d at 302.

Clearly, a drilling unit order cannot constitutionally prohibit a mineral owner from drilling a well on his property unless it also gives the owner the opportunity to participate in production from the unit well. See Bennion v. Utah State Bd. of Oil, Gas & Mining, 675 P.2d at 1142; Ward v. Corporation Comm’n, 501 P.2d at 507. But where, as in this case, the nonconsenting party is not only given a royalty from production but is also given the opportunity to elect to participate in the drilling, the subsequent imposition of a nonconsent penalty constitutes a valid exercise of the police power. See 5 W. Summers, Oil and Gas ch. 29, § 977, at 136 (1966) (“[Ujnlike the judgments of courts dealing with claims fixed by past events which are res judicata, [orders of oil and gas regulatory agencies] are prospective, subject to change, and fundamentally designed to prevent waste and protect correlative rights, with effects upon private property when they occur only incidental to these two police power purposes.”). The penalty is not an unconstitutional taking of property.

Bennion also argues that under federal 9 due process principles, the Utah statutory nonconsent penalty is invalid on its face because it does not have a rational relation to a permissible state interest. We disagree.

According to the United States Supreme Court, “a state has constitutional power to regulate production of oil and gas so as to prevent waste and to secure equitable apportionment among landholders of the migratory gas and oil underlying their land, fairly distributing among them the costs of production and of the apportionment." Hunter Co. v. McHugh, 320 U.S. 222, 227, 64 S.Ct. 19, 21, 88 L.Ed. 5 (1943) (emphasis added). As discussed earlier, the purpose of a nonconsent penalty is to balance the costs, benefits, and risks of drilling a well among the diverse parties. The nonconsenting parties avoid any risk; the participating parties assume it. The statutory nonconsent penalty is an integral part of the compulsory pooling process which protects the correlative rights of all of the mineral owners. See supra section I. Further, the penalty provides an incentive for parties to participate in drilling, resulting in increased production consistent with the public policy of this state. There is, therefore, a rational relation between the Utah statutory nonconsent penalty and a permissible state interest.

Bennion also argues that his right to due process was violated because the Board arbitrarily and capriciously imposed the nonconsent penalty on him without taking into account the risks involved in his particular case. He argues that he is being assessed a very high penalty when in fact the risks of drilling a dry well in the area were “virtually zero.” This argument is likewise without merit.

Inherent in the drilling of any well is a risk of mechanical problems, price fluctuations, or insufficient production to cover costs. For this reason, the legislature has decided that a minimum nonconsent penalty of 150 percent is justified in all cases. Because not all wells carry the same risks, however, the legislature has provided for a higher risk penalty when warranted. It is left to the Board to decide in each case whether the risks of a particular well warrant the minimum statutory penalty of 150 percent, the maximum of 200 percent, or an amount in between.

Although in the case of the second well the risk of a dry hole was minimal, the drilling process itself was not risk-free. In this particular case, the Board found that there was enough risk to warrant the imposition of a 175 percent nonconsent penalty. Under the Utah Administrative Procedures Act, Bennion can obtain relief only if we find that the amount of the nonconsent penalty imposed on him “is based upon a determination of fact, made or implied by the agency, that is not supported by substantial evidence when viewed in light of the whole record before the court,” Utah Code Ann. § 63-46b-16(4)(g), or if the Board’s action was “otherwise arbitrary or capricious,” Utah Code Ann. § 63-46b-16(4)(h)(iv). With regard to the 175 percent penalty, in light of the record before us, we hold that the Board’s finding is supported by substantial evidence and was neither arbitrary nor capricious. By means of the 175 percent penalty, the consenting parties will recoup a fair and reasonable amount from Bennion’s share of production.

III. MODIFICATION OF THE 1981 ORDER

Bennion contends that the Board lacks statutory authority to modify the 1981 pooling order. Under the Utah Administrative Procedures Act, this court shall grant Bennion relief if an agency has acted beyond the jurisdiction conferred on it by any statute. Utah Code Ann. § 63-46b-16(4)(b). This is a question of law and, more particularly in this case, a question of statutory construction. The particular statutory terms do not expressly grant the Board discretion; therefore, this court is in as good a position as the Board to interpret the statutory language. See Savage Indus., 811 P.2d at 668. Thus, our review is governed by a correction-of-error standard, with no deference to the Board’s conclusion that it has the authority to modify a pooling order. 10

Bennion argues that the Utah Code gives the Board the authority to modify an order establishing a drilling unit but that the Board does not have a corresponding power to modify an order pooling the unit. We look first at the language of the statute.

When a drilling unit is initially established, the Oil and Gas Conservation Act contemplates that only one well will be drilled per unit. See Utah Code Ann. § 40- 6-6(l)(a) (1988) (formerly codified at § 40-6-6(b) (Supp.1977)) (an order establishing a drilling unit shall include “the acreage to be embraced within each drilling unit and the shape of each drilling unit as determined by the board but the unit shall not be smaller than the maximum area that can be efficiently and economically drained by one well”); Utah Code Ann. § 40-6-6(l)(b) (1988) (formerly codified at § 40-6-6(c) (Supp.1977)) (an order establishing a drilling unit shall direct “that no more than one well shall be drilled for production from the common source of supply on any drilling unit”). Yet, even in 1981, when the drilling unit at issue in this case was force-pooled by the Board, the statute contemplated that additional wells could be permitted under the right circumstances. The statute provided: “When found necessary for the prevention of waste ... or to protect correlative rights, an order establishing drilling units in a pool may be modified by the board ... to permit the drilling of additional wells on a reasonably uniform plan in the pool, or any zone thereof.” Utah Code Ann. § 40-6-6(d) (Supp.1977). Under the 1983 amendments to the Oil and Gas Conservation Act, the Board, without qualification, can “permit additional wells to be drilled within the established units.” 1983 Utah Laws ch. 205, § 1 (codified at § 40-6-6(4)). Based on the language of the statute, therefore, it is perfectly logical that the Board’s 1981 order force-pooling the subject drilling unit did not apply to or anticipate the drilling of additional wells in the unit or the consequences if a party elected not to participate in a future well. It is just as logical, however, that the legislature intended to permit the Board to amend its pooling orders to accommodate the drilling of additional wells.

This court has held that in addition to those powers expressly conferred upon an administrative agency, the agency has such implied powers as are reasonably necessary to effectuate its express powers or duties. Williams v. Public Serv. Comm’n, 754 P.2d 41, 50 (Utah 1988); Basin Flying Serv. v. Public Serv. Comm’n, 531 P.2d 1303, 1305 (Utah 1975); see also 1 Am. Jur.2d Administrative Law § 72 (1962); 38 Am.Jur.2d, Gas and Oil § 148 (1968). Consistent with that principle is a recognition of the authority of the administrative agency charged with the regulation of the oil and gas industry to change or modify its orders. Although we have never before ruled on this issue, several courts of other oil and gas producing states have recognized such an inherent power. See, e.g., Application of Bennett, 353 P.2d 114,118— 19 (Okla.1960) (“We are ... of the opinion that the Legislature intended and contemplated that orders ... could and should be modified when it is shown that modification is necessary in order to conserve oil or gas or bring about a fair and equitable production of the oil or gas.”); Railroad Comm’n v. Aluminum Co. of America, 380 S.W.2d 599, 602 (Tex.1964) (“[T]he Commission’s power to regulate oil and gas production in the interest of conservation and protection of correlative rights is a continuing one and its orders are subject to change or modification where conditions have changed materially, new and unforeseen problems arise or mistakes are discovered.”); see also Application of Kohlman, 263 N.W.2d at 678; 5 W. Summers, Oil and Gas ch. 29, § 977, at 138 (1966) (“with regard to those matters fairly within the areas of prevention of waste and protection of correlative rights there is broad continuing jurisdiction to alter, amend, and modify and interpret previous orders” within the oil and gas regulatory agencies). A pooling order, while based on facts existing at the time of its entry, addresses future conduct and relationships. In this case, the anticipated drilling of an additional well in the unit caused the 1981 order to become inadequate to define the relationships among the owners in the unit. Because the modification of the pooling order promoted the stated policies and goals of the Oil and Gas Conservation Act without compromising Bennion’s correlative rights, it follows that amendment of the order was proper.

Moreover, upon close examination, it is evident that the legislature intended that the statutory nonconsent penalty be determined on a well-by-well basis. The language of section 40-6-6(6)(b) stipulates that the Board is to determine an amount “not less than 150% nor to exceed 200% of that portion of the costs and expenses ... in the well.” The nonconsent penalty is therefore to be determined by the risks associated with each particular well. 11 That can only be done if the Board has the power to amend the original pooling order to accommodate the particular risks of an additional well. 12

In conclusion, although the Utah Oil and Gas Conservation Act does not explicitly authorize the Board to modify a pooling order to accommodate the drilling of additional wells in a drilling unit, such an authorization is implied in the statute’s grant of authority to the Board to modify drilling orders to that effect. When a modification of a drilling order results in the drilling of wells not specifically addressed in the previous pooling order, in the absence of a voluntary agreement as to the treatment of additional wells within the pool, the Board has the implied authority to modify the pooling order under terms consistent with the Oil and Gas Conservation Act. In this case, the conditions that existed at the time the original pooling order was entered have changed appreciably. It was necessary that the pooling order be modified to the extent necessary to fix the amount of drilling and operational costs for the second well. As has been demonstrated, the Board has done so in a manner consistent with the express language of and the policies behind the Oil and Gas Conservation Act.

IY. SHOWING OF ECONOMIC FEASIBILITY

As a final argument, Bennion asserts that the 1985 order allowing the drilling of additional wells in the unit requires an operator to make a showing to the Board of economic feasibility prior to drilling a second well. He further asserts that ANR made no such showing in the case of the second well. The 1985 order states, “Additional wells may be drilled at the option of the operator of the unit, based upon geologic and engineering data for that unit which will justify the drilling of an additional well in order to recover additional oil, provided the additional well appears to be economically feasible.” Benn-ion raised this issue in his response to petitioners’ request for agency action, but the Board made no express finding in this regard in its 1990 order. Although the Oil and Gas Conservation Act does not require the Board to give prior approval for the drilling of additional wells on existing units, the language of the 1985 order could be interpreted to require such approval. That language requires clarification from the Board.

Y. CONCLUSION

We uphold the Board’s 1990 action modifying the 1981 order. The imposition of a statutory nonconsent penalty is not inconsistent with the declaration of public interest contained in the Utah Oil and Gas Conservation Act. The statutory nonconsent penalty is not unconstitutional as a taking or a violation of due process. Under appropriate circumstances, the Board has statutory authority to modify a forced pooling order. Finally, we remand this case for the Board to make a finding on the question whether the 1985 order requires an operator to make a showing of economic feasibility to the Board prior to the drilling of a second well and, if so, whether such a showing was made in this case.

HALL, C.J., HOWE, Associate C.J., and STEWART and ZIMMERMAN, JJ., concur.

1 . This is termed “forced” or "compulsory" pooling, as opposed to voluntary pooling. “In order to reap maximum benefits from his position as the owner of a mineral interest in a producing well, Bennion had to enter a pooling arrangement and pay his share of the producing costs along with the owners of the other working interests.” Bennion v. Utah State Bd. of Oil, Gas & Mining, 675 P.2d at 1138. Because Bennion did not join the voluntary pooling agreement, the only way for him to achieve this end was to be “force pooled” with the other mineral owners by the Board under its statutory powers.

2 . A drilling unit order, such as the one entered in this case in 1971, “establishes spacing (drilling) units of a certain size over what appears to be a common source of supply and fixes the well location within the unit.” Ward v. Corporation Comm’n, 501 P.2d 503, 507 (Okla.1972). A forced pooling order is issued subsequent to a drilling unit order and determines the interest of each owner in a drilling unit and, in the absence of a voluntary agreement, the relative income, investment, and costs to be allocated to different parties in the drilling unit. See Bennion v. Utah State Bd. of Oil, Gas & Mining, 675 P.2d at 1140-41.

3 . At "payout,” the cumulative value of production from a well exceeds the initial costs of drilling, equipping, and completing the well.

4 . Increased density wells are drilled for simultaneous production when it is determined that . one well per drilling unit is not draining a pool. This type of well is to be distinguished from an alternative production well, which is drilled as a substitute for the original well. See Bennion v. Gulf Oil Corp., 716 P.2d 267, 268 (Utah 1985). Increased density wells were not permitted under the Utah statute until after the 1983 repeal and reenactment of the Oil and Gas Conservation Act. Prior to that date, only one producing well was allowed per unit. Id. at 269.

5 . In its 1990 order, the Board made no finding of fact or conclusion of law regarding this issue or Bennion’s constitutional challenges to the statutory nonconsent penalty (see next section). Bennion’s response to petitioners’ request for agency action does, however, raise these issues, and his attorney orally preserved the arguments at the administrative hearing. Neither ANR nor the amici addressed the issues in any of their pleadings at the administrative level, but they did so in briefs to this court. Although there were no findings by the Board on these issues, its imposition of a statutory nonconsent penalty on Bennion implicitly recognizes the constitutionality of the penalty and dismisses any potential conflict with the overall policy behind the Oil and Gas Conservation Act. Cumulatively, these factors support the conclusion that Benn-ion has preserved these issues, and we are not precluded from adjudicating them here. See Utah Associated Mun. Power Systems v. Public Serv. Comm’n, 789 P.2d 298, 300 (Utah 1990).

6 . Bennion does not dispute his liability for 100 percent of his share of the costs of preparing, drilling, completing, equipping, and operating the second well. What he objects to is the assessment of the additional 75 percent noncon-sent penalty for some of those costs. The Oil and Gas Conservation Act requires a 100 percent assessment of the costs of well operation and of the costs of equipment beyond the wellhead, Utah Code Ann. § 40-6-6(6)(a), and requires a 150 percent to 200 percent assessment “of the costs and expenses of staking the location, wellsite preparation, rights of way, rigging up, drilling, reworking, deepening or plugging back, testing and completing, and the cost of equipment in the well,” Utah Code Ann. § 40-6-6(6)(b). A 100 percent assessment on some costs allows the consenting parties to recover 100 percent of a nonconsenting party’s share of those costs out of that party’s share of production. A 175 percent assessment on other costs (often termed a 175 percent penalty) allows the consenting parties to recover 100 percent of the nonconsenting party’s share plus an additional 75 percent as a risk penalty. If a well never produces (i.e., it is a dry hole), the nonconsent-ing party is not liable for any of the drilling costs. If the well is not productive enough to allow the consenting parties to recover their costs and the amount of the penalty (i.e., it is an unprofitable well), the nonconsenting party will not have to pay any portion of the remaining costs or penalty. In this way, a nonconsenting working interest owner avoids the financial risks of a dry hole or an unprofitable well.

7 . The statutory nonconsent penalty established in the Oil and Gas Conservation Act applies only to forced pooling orders entered by the Board. The interest owners in any given drilling unit are at liberty to voluntarily pool their interests under their own terms. See Utah Code Ann. § 40-6-6(5). In that event, the voluntarily pooled owners can agree to be subject to any reasonable penalty for nonconsent to the drilling of a well. See In re SAM Oil, 817 P.2d 299, 302-303, 304 n. 6 (Utah 1991), This occurred in the instant case, where all of the owners except Bennion voluntarily pooled their interests in an agreement providing for a 300 percent noncon-sent penalty. In addition, nonconsenting parties under the voluntary agreement did not receive a royalty until payout, whereas under the 1990 order Bennion receives a royalty share from the time of first production.

8 . In this way, the nonconsent penalty avoids, among other things, “the serious constitutional problem which would arise if the state simply compelled participation in a speculative venture.” 5 W. Summers, Oil and Gas ch. 29, § 975, at 128 (1966).

9 . Although he mentions the state constitutional due process provision, Bennion’s argument is developed solely as a question of federal law. We therefore do not undertake an independent state analysis.

10 . Specifically, in the 1990 order, the Board concluded:

The Board has the necessary and inherent authority, pursuant to [the Oil and Gas Conservation Act] to amend, modify or supplement its previous pooling orders where there has been a substantial change in circumstances or an omission in a prior order and where failure to modify the order would result in the continued enforcement of terms which are not just and reasonable or which would fail to protect correlative rights.

11 . When additional wells are drilled, for example, there will be improved knowledge of the geologic and economic factors involved. That change and any others in connection with additional wells should be taken into account in allocating the costs and benefits among the parties.

Bennion cites Oklahoma case law for the proposition that pooling under a forced pooling statute is on the basis of the area of the drilling unit rather than only on an individual well-bore. See, e.g., Inexco Oil Co. v. Oklahoma Corp. Comm’n, 767 P.2d 404, 405 (Okla.1988), cert. denied, 490 U.S. 1040, 109 S.Ct. 1943, 104 L.Ed.2d 414 (1989); Amoco Prod. Co. v. Corporation Comm’n, 752 P.2d 835, 837 (Okla.Ct.App.1987); Amoco Prod. Co. v. Corporation Comm’n, 751 P.2d 203, 206 (Okla.Ct.App.1986) (adopted by the Oklahoma Supreme Court Dec. 16, 1987). Those Oklahoma cases are distinguishable. Pursuant to Oklahoma law, nonconsenting interest owners are often given the option of participating in unit-wide drilling or accepting a cash bonus and/or an overriding or excess royalty interest. Where these options are present, the election is exercisable only once, prior to the drilling of the initial well. Under those circumstances, the "initial risk capital investors” have a vested right in their interest in the unit rather than in any given well. See, e.g., id. at 207. Under the statutory scheme established by the Utah statute, however, a nonconsent penalty is determined on a well-by-well basis. An election to participate is made anew each time an additional well is drilled, and the policy considerations are therefore different.

12 . In his reply brief, Bennion argues that in electing not to participate in the second well, he assumed that his costs would be allocated according to the 1981 order. Yet the 1981 order is silent as to the rights of consenting and noncon-senting interest owners to reimbursement for costs out of production and share of production. In his original brief, Bennion admitted that he refused to participate in the second well despite the fact that ANR informed him that such failure would subject him to the nonconsent penalties mandated by statute. Moreover, the letter dated March 20, 1990, in which ANR offered Bennion the opportunity to participate in the second well clearly states that nonconsenting parties will be subject to the statutory penalty of 150 percent to 200 percent. For these reasons, we find Bennion’s reliance argument unpersuasive.