When the Virginia Gas and Oil Board orders compulsory pooling for a coalbed methane well, can it allow the operator to deduct post-wellhead processing, transportation, and marketing costs from the gas owner's one-eighth royalty?

Plain-English summary

When Virginia's Gas and Oil Board issues a compulsory pooling order for a coalbed methane well, it brings together all the gas owners (some leased to the operator, some not) within a defined drilling unit. The unleased owners get a "deemed leased" status with a statutory royalty of one-eighth of production. The Board's standard order language defines that one-eighth as a share of "net proceeds," meaning actual sales proceeds received by the operator minus post-production costs incurred downstream of the wellhead, including gathering, compression, treating, transportation, and marketing. The Chairman of the Board asked the Attorney General whether the Board had legal authority to use that net-of-costs formula.

Acting Attorney General William Mims concluded that the Board does have authority. The reasoning runs along several tracks. First, Virginia traditionally measured royalty "at the wellhead," meaning the raw gas at the wellhead, not the marketable processed gas at the point of ultimate sale. Defining the royalty as net of post-production costs is a way of arriving at the at-the-wellhead value by working backwards from the eventual sales price (the "net-back method"). Texas, Mississippi, Louisiana, and federal courts have used this method extensively. Second, the Board has used this language consistently since 1992, and the General Assembly defeated 2009 bills (SB 1204, HB 2518) that would have removed this authority. The legislature is presumed to know AG interpretations and Board practice; defeat of those bills signals legislative acquiescence in the Board's approach.

Third, the AG distinguished private-lease cases from the Board's compulsory-pooling context. Cases like Estate of Tawney (W.Va. 2006) and Rogers v. Westerman Farm (Colo. 2001) involved interpretation of private lease contracts, often using contract-interpretation principles (construe against drafter, implied duty to market) that do not apply to Board orders for unleased interests. The Board is regulating, not contracting.

Currency note

This opinion was issued in 2009. Subsequent statutory amendments, court decisions, or later AG opinions may have changed the analysis. Treat this page as historical context, not current legal advice. Verify current law before relying on any specific rule, deadline, or remedy mentioned here.

Background and statutory framework

Virginia's Gas and Oil Act, in Chapter 22.1 of Title 45.1 (§§ 45.1-361.1 to 45.1-361.44), was substantially overhauled in 1990 to allow compulsory pooling for coalbed methane and to consolidate regulatory authority in the Virginia Gas and Oil Board. The Board has statewide jurisdiction over drilling units, pooling, and related regulatory matters. Section 45.1-361.14(B) gives the Board "the power necessary to execute and carry out all of its duties." Section 45.1-361.15 lists specific authorities, including the power to enter spacing and pooling orders, establish drilling units, and take any actions reasonably necessary to carry out the Act.

Section 45.1-361.22(4), specific to coalbed methane gas pooling, requires the operator to deposit "one-eighth of all proceeds attributable to the conflicting interests" into an escrow account, plus all proceeds in excess of ongoing operational expenses attributable to a participating or nonparticipating operator. The statute reflects the traditional industry royalty of one-eighth of production. It does not specify whether the one-eighth is measured at the wellhead or at the point of ultimate sale.

The Board filled that interpretive gap by regulation. 4 VAC § 25-160-100(B) requires that proceeds for conflicting royalty claims "shall be deposit[ed] in accordance with § 45.1-361.22 of the Code of Virginia, to be determined at the wellhead." That is, the Board measures the one-eighth royalty at the wellhead, not at the downstream point of sale.

But raw wellhead gas does not have a freely observable market price in most cases. Modern coalbed methane production typically involves substantial post-wellhead processing (gathering, compression, treating, transportation, marketing) before the gas reaches a sale point. To translate the eventual sale price into a wellhead value, the Board uses the "net-back method" (also called net proceeds or work-back method): take the actual sales price received by the operator, subtract the costs of post-production processing and transportation, and what is left is the wellhead value. The royalty is one-eighth of that wellhead value.

Federal regulation 30 C.F.R. § 206.151 uses a similar net-back method for federal gas leases. Texas, Mississippi, Louisiana, and Oklahoma cases generally accept the same approach for measuring "at the well" royalty.

Some other states, including Colorado (Garman v. Conoco, Rogers v. Westerman Farm) and West Virginia (Estate of Tawney), have rejected post-production cost deductions on private leases by reasoning that the lessee has an implied duty to market or that ambiguous lease language is construed against the drafter. The AG was careful to distinguish those cases: they involved private contract interpretation, not regulatory orders for unleased interests.

What the AG concluded

The Board has broad statutory authority over pooling orders. Section 45.1-361.14(B) and § 45.1-361.15 confer expansive powers, supplemented by the Board's authority to promulgate regulations and issue orders necessary to carry out the Act.

The net-back method is a permissible way to measure at-the-wellhead royalty. Where wellhead market value cannot be directly observed, working backwards from the sales price minus post-production costs is a standard industry approach with extensive support in case law from other jurisdictions and in federal regulation.

Private-lease cases do not control. Cases like Tawney and Rogers turn on contract interpretation principles. The Board is regulating unleased interests, not interpreting private contracts. Different legal framework, different result.

Long-standing practice without legislative correction signals acquiescence. The Board has used this language since 1992. The General Assembly's defeat of 2009 bills to override the Board's approach demonstrates legislative acquiescence. Agency interpretation in matters within its specialized competence is entitled to deference.

Common questions

What is the "rule of capture" and why does it matter?
Under the common-law rule of capture, gas was treated like a wild animal: whoever pumped it from a well on their property owned it, even if it migrated from a neighbor's land. The neighbor had no remedy. The 1990 Act replaced that rule with compulsory pooling, which protects correlative rights but does so within the Board's regulatory framework.

What is the difference between "at the wellhead" and "at the sale point"?
At the wellhead, gas is raw, often wet (containing water and impurities), uncompressed, and not yet in a marketable form. At the sale point (typically a downstream pipeline interconnection), the gas has been processed, compressed, transported, and made marketable. The sale price reflects the post-production work; the wellhead value does not. Royalty at one-eighth of the sale price would give the royalty owner a free ride on the operator's processing investment.

Why did the General Assembly defeat the 2009 override bills?
The opinion does not say. As a legal matter, the AG used the defeat as evidence of legislative acquiescence in the Board's interpretation. The actual policy debate involved competing claims by gas owners (who want larger royalties) and operators (who want to recover their post-production investment).

Does this apply to oil too, or just gas?
The Act covers both. The opinion's reasoning applies equally, though most of the discussion centers on coalbed methane gas because that is the dominant production in the Virginia coalfield region.

What about owners who do participate as operating partners?
Participating gas owners share in the well's costs and revenues directly, rather than receiving a royalty. The opinion's framework is specific to the one-eighth royalty for nonparticipating or unleased owners.

Can a gas owner challenge a Board order they disagree with?
Yes, through the appeals procedure in § 45.1-361.19. The Board's orders are subject to judicial review under the Administrative Process Act.

Citations

• Va. Code Ann. §§ 45.1-361.1 to 45.1-361.44 (Virginia Gas and Oil Act)
• Va. Code Ann. § 45.1-361.22(4) (one-eighth royalty escrow)
• 4 VAC § 25-160-100(B) (wellhead measurement)
• 30 C.F.R. § 206.151 (federal net-back method)
• Piney Woods Country Life Sch. v. Shell Oil Co., 726 F.2d 225 (5th Cir. 1984)
• Hunter Co. v. McHugh, 320 U.S. 222 (1943)
• 2009 S.B. 1204; 2009 H.B. 2518 (defeated)

Source

• Landing page: https://www.oag.state.va.us/annual-reports-opinions/official-opinions
• Original PDF: https://www.oag.state.va.us/files/Opinions/2009/09-018-Lambert.pdf

Original opinion text

COMMONWEALTH of VIRGINIA
Office of the Attorney General
William C. Mims

900 East Main Street
Richmond, Virginia 23219
804-786-2071
FAX 804-786-1991
Virginia Relay Services
800-828-1120
7-1-1

Attorney General

June 10, 2009

Mr. Bradley C. Lambert
Chairman, Virginia Gas & Oil Board
Department of Mines, Minerals and Energy
P.O. Box 900
Big Stone Gap, Virginia 24219

Dear Mr. Lambert:

I am responding to your request for an official advisory opinion in accordance with § 2.2-505 of the Code of Virginia.

Issue Presented

You ask whether the Virginia Gas and Oil Board is authorized to issue compulsory pooling[1] orders that permit deduction of post-production costs downstream of the wellhead when computing the gas owners' one-eighth royalty interests.

Response

It is my opinion that the Virginia Gas and Oil Board may issue compulsory pooling orders that permit deduction of post-production costs downstream of the wellhead when computing gas owners' one-eighth royalty interests.

Background

You advise that beginning around 1992, the Virginia Gas and Oil Board (the "Board")[2] has issued compulsory pooling orders that contain the following provision:

9.2 Option 2 - To Receive A Cash Bonus Consideration: In lieu of participating in the Well Development and Operation in Subject Drilling Unit under Paragraph 9.1 above, any Gas Owner or Claimant named in Exhibit B-3 hereto who does not reach a voluntary agreement with the Unit Operator may elect to accept a cash bonus consideration of $____ per net mineral acre owned by such person, commencing upon entry of this Order and continuing annually until commencement of production from Subject Drilling Unit, and thereafter a royalty of 1/8th of 8/8ths [twelve and one-half percent (12.5%)] of the net proceeds received by the Unit Operator for the sale of the Coalbed Methane Gas produced from any Well Development and Operation covered by this Order multiplied by that person's Interest in Unit or proportional share of said production [for purposes of this Order, net proceeds shall be actual proceeds received less post-production costs incurred downstream of the wellhead, including, but not limited to, gathering, compression, treating, transportation and marketing costs, whether performed by Unit Operator or a third person] as fair, reasonable and equitable compensation to be paid to said Gas Owner or Claimant.

You further state that the Board's legal authority to issue orders providing such allowance for deduction of post-production costs has been challenged by citizens and at least two legislators. You provide a partial copy of the Board's March 17, 2009 meeting transcript where one such challenge was based on the Dillon Rule.

Historical Background

Historically, gas has been viewed as a transient mineral and has been analyzed by analogy to the common law concerning wild animals.[3] Under common law principles, when a wild animal leaves an owner's property and goes on to the property of another, the subsequent property owner has the legal right to capture the animal for his own use.[4]

Just as with wild animals, the "rule of capture" traditionally has been applied to migratory, fugacious minerals such as gas. The rule of capture has been referred to as the "cornerstone of the oil and gas industry and is fundamental both to property rights and to state regulation."[5] Under the common law, when someone drills a legal well on adjacent property and as a result of the natural migration of the gas the gas pool underlying both properties is drained by that single legal well, the original owner had no right to complain of trespass or to be compensated for the gas by the well operator.[6] With the "rule of capture," there was no taking and no protection of correlative rights of others in the pool.[7]

As noted by the Supreme Court of Virginia, the Commonwealth previously followed the common law rule of capture: "[t]he courts are practically unanimous in holding that a landowner, under whose land there is oil, gas, or water, cannot complain of a neighbor who in pumping on his own property drains the oil, gas, or water from his lands."[8]

The Supreme Court of the United States has affirmed the constitutional power of individual states "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."[9] To address any inequity under the "rule of capture" and protect correlative rights of others in the same pool, as well as to eliminate the race to drill unnecessary competing wells and to maximize the recovery of the Commonwealth's natural resources to meet growing energy needs, the 1990 Session of the General Assembly enacted the current Virginia Gas and Oil Act[10] ("the Act") that allows compulsory pooling and has established the Board with statewide jurisdiction.[11]

The Act significantly changed both the common law and prior statutory provisions concerning gas and oil in Virginia.[12] The Act extensively reorganized the predecessor act and consolidated the Virginia Well Review Board and the Virginia Oil and Gas Conservation Board into the Virginia Gas and Oil Board, provided a new pooling mechanism to encourage the production of coalbed methane gas,[13] and enhanced enforcement procedures allowing civil penalties and charges to be assessed.[14]

Applicable Law and Discussion

The current Board was established as an adjunct to the Division of Gas and Oil within the Department of Mines, Minerals and Energy.[15] As such, the Board is an agency of the state.[16] The Board's statutorily delegated powers are expansive. "The Board shall have the power necessary to execute and carry out all of its duties specified in [Chapter 22.1]."[17] Further, § 45.1-361.15 provides that:

B. Without limiting its general authority, the Board shall have the specific authority to issue rules, regulations or orders pursuant to the provisions of the Administrative Process Act (§§ 2.2-4000 et seq.) in order to:
….

12. Take such actions as are reasonably necessary to carry out the provisions of [Chapter 22.1].

The overriding goal of statutory interpretation is to discern and give full force and effect to the entire legislative intent.[18] The Act granted the Board considerable power. Such conclusion is supported by the detailed history associated with the passage of the Act in 1990.[19]

In addition to its broad general powers, the Board's specific duties include holding evidentiary hearings to consider applications to allow compulsory pooling of unleased interests in drilling units.[20] After ruling on such pooling applications, the Board issues written orders setting out its rulings and findings.[21] Another of the Board's specific duties is to promulgate regulations to enter pooling orders and establish drilling units.[22] One of the Board's regulations governs compulsory pooling orders: "[w]here there are conflicting royalty claims to coalbed methane gas, the unit operator of a forced pooled coalbed methane gas unit shall deposit proceeds in accordance with § 45.1-361.22 of the Code of Virginia, to be determined at the wellhead."[23]

Section 45.1-361.22(4) provides that "[t]he coalbed methane gas well operator shall deposit into the escrow account one-eighth of all proceeds attributable to the conflicting interests plus all proceeds in excess of ongoing operational expenses as provided for under § 45.1-361.21 and the order of the Board attributable to a participating or nonparticipating operator." (Emphasis added.)

Section 45.1-361.22(4) reflects the traditional definition of the resource owner's royalty as being one-eighth of production.[24] However, it does not establish the point source at which the one-eighth royalty is measured. Such distinction is important because one-eighth of the proceeds "at the wellhead" would be an amount significantly different from one-eighth measured at the point of ultimate sale or at an interim point in the transfer from well to market. Thus, the Board promulgated a regulation to specifically provide that the measurement is to be made "at the wellhead."[25]

The source of the "at the wellhead" language developed from industry practice where common carriers regularly purchased the gas at the well, i.e., the point where the gas entered the pipeline stream.[26] When such practice developed, it provided an easy point of reference for computing royalty interests. There is considerable case law in jurisdictions where the gas and oil industry developed earlier than in Virginia and where energy resource case law is extensive that interprets "at the wellhead" language in other states.[27]

Additionally, there is another important factor to consider. Traditionally, "at the well" or "wellhead" has been used to describe not only location but also quality. In many jurisdictions, "at the well" describes a cruder product with a market value that is not yet enhanced in value by processing and transportation to far-reaching retail markets.

One of a series of such cases in Mississippi stated unequivocally, "that 'at the well' refers to gas in its natural state, before the gas has been processed or transported from the well."[28] Similarly, in an early Louisiana case involving "wet gas," the court was faced with reconstructing a value for the one-eighth royalty and reasoned that

in determining market value costs which are essential to make a commodity worth anything or worth more must be borne proportionately by those who benefit. To put it another way: in the analytical process of reconstructing a market value where none otherwise exists with sufficient definiteness, all increase in the ultimate sales value attributable to the expenses incurred in transporting and processing the commodity must be deducted. The royalty owner shares only in what is left over, whether stated in terms of cash or an end product.[29]

Likewise, in a case where the gas operator installed a compressor to move the gas from two wells with insufficient wellhead pressure to reach a nearby gathering line, that court examined the "net proceeds" language:[30]

It is well settled that the phrase "at the well received," or similar terminology, establishes the "point" at the mouth of the well …. [Royalty owners] are entitled to receive one-eighth (1/8) of the total gas delivered (produced) to the mouth of the well or the market value thereof. Accordingly, the royalty is free of all costs (e.g. exploration, drilling, operation, etc.) up to this point.

Further, "net proceeds" clearly suggests that certain costs are deductible. "Net proceeds" is typically defined as the sum remaining from gross proceeds of sale after payment of expenses.[31]

"Regardless of whether the gas is sold on or off the leased premises, royalty is based on the value of all gas produced at the mouth of the well. Cost incurred prior to production are to be borne by the operator, while costs incurred subsequent to production (those necessary to render the gas marketable) are to be borne on a pro rata basis between operating and nonoperating interests."[32]

Based on the foregoing cases, there is no inconsistency between the one-eighth royalty and the net proceeds computation set out in the standard Board order. That standard order language simply calculates the "at the wellhead" royalty under today's market conditions by using the net-back method.[33]

Substantial differences in language can be found in case law defining the basis upon which payment should be made.[34] Generally speaking, where the royalty is referred to in terms of market "price," an actual sale is envisioned. By contrast, reference to market "value" usually supports a distinction between actual sales in the vicinity and market value that may be established by opinion evidence.[35] The concept of "proceeds" traditionally looks to the receipts from the sales of the gas, wherever made.

The Board, in using the language about which you inquire, has taken this last approach. The royalty computation is made on the basis of the sales price ultimately received for the gas less the cost of marketing, transportation, and treatment.[36] Under this formula, as usually applied, the lack of actual sales in the field at the wellhead or other evidence, such as expert opinion testimony, becomes irrelevant.

Not dispositive, but certainly indicative of the reasonableness of the Board's approach, is the federal regulation that defines the "net-back method (or work-back method)" for computing royalties that is very similar to the Board's standard order language.[37] The federal net-back method[38] deducts the costs for transportation, processing, or manufacturing of the gas from the proceeds received at the first point reasonable value may be determined by an arm's-length contract or by comparison to other sales of similar products.[39]

Finally, it should be noted that much of the case law regarding royalty payments involves the interpretation of contracts, as opposed to the construction of statutes. The Board's language in the orders in question only deals with unleased owners, and the Board does not interpret private lease contracts between any parties.[40] Private contracts are a matter for judicial resolution.

The Board has implemented its statutory authority and regulations using the standard compulsory pooling order language about which you inquire for more than fifteen years. During that time, the Board consistently has applied the same interpretation in issuing its orders. Such practice is not arbitrary or capricious. An agency's interpretation and application of its regulations in matters within its specialized competence is entitled to deference.[41]

A compulsory pooling order also is in effect a guidance document[42] as that term is defined in the Administrative Process Act.[43] Guidance documents, while not having the force and effect of law, serve to advise the agency's staff and the public of the agency's interpretation of its regulations.[44] Courts generally will give such "interpretative" rules persuasive effect.

[A]n agency "has incidental powers which are reasonably implied as a necessary incident to its expressly granted powers for accomplishing [its] purposes." This includes the adoption of interpretative rules. Since such rules do not undergo the same scrutiny as do formally promulgated regulations, they "do not purport to be a substitute for the statute." "[T]hey do not have the force of law." In spite of this, interpretative rules carry persuasive effect. We give "great deference to an administrative agency's interpretation of the regulations it is responsible for enforcing" for "it is inappropriate for a court to second-guess the manner in which an agency responds to its responsibility of carrying out the Commonwealth's policy when those means are not prohibited."[45]

The interpretation given to a statute by the agency charged with its administration is entitled to great weight.[46] The General Assembly is presumed to be cognizant of the agency's construction of a particular statute and when such construction continues without legislative alteration, the legislature will be presumed to have acquiesced in it.[47]

Conclusion

Accordingly, it is my opinion that the Virginia Gas and Oil Board may issue compulsory pooling orders that permit deduction of post-production costs downstream of the wellhead when computing gas owners' one-eighth royalty interests.

Thank you for letting me be of service to you.

Sincerely,

William C. Mims
3:723; 1:941/09-018

1. Although the term "compulsory pooling" is not defined in the Code, it is a term of art in the gas and oil industry and for purposes of this opinion, the term means the pooling of interests within a drilling unit pursuant to § 45.1-361.21 or § 45.1-361.22. The federal government provides for a "compulsory unitization" and may require "lessees to unitize operations … if unitized operations are required" to prevent waste, conserve natural resources, or protect correlative rights. See 30 C.F.R. § 250.1301(b) (2008); see also E.H. Shopler, Annotation, Validity of compulsory pooling or unitization statute or ordinance requiring owners or lessees of oil and gas lands to develop their holdings as a single drilling unit and the like, 37 A.L.R.2D 434, 435 (1954) (defining "compulsory pooling" as "[a] statute under which owners of small or irregularly shaped tracts can be required to develop their lands as a single drilling unit for conservation purposes").
2. See VA. CODE ANN. § 45.1-361.13(A) (2002) (establishing Board).
3. See Ohio Oil Co. v. Indiana (No. 1), 177 U.S. 190, 209 (1900); Tex. Am. Energy Corp. v. Citizens Fid. Bank & Trust Co., 736 S.W.2d 25, 26 (Ky. 1987).
4. Id.
5. Coastal Oil & Gas Corp. v. Garza Energy Trust, 268 S.W.3d 1, 13 (Tex. 2008).
6. "[T]he owner of a tract of land acquires title to the oil and gas which he produces from wells on his land, though part of the oil or gas may have migrated from adjoining lands. He may thus appropriate the oil and gas that have flowed from adjacent lands without the consent of the owner of those lands, and without incurring liability to him for drainage." Elliff v. Texon Drilling Co., 210 S.W.2d 558, 561-62 (Tex. 1948) (emphasis added).
7. Id. at 562; see also § 45.1-361.1 (2002) (defining "correlative rights" as "the right of each gas or oil owner having an interest in a single pool to have a fair and reasonable opportunity to obtain and produce his just and equitable share of production of the gas or oil in such pool or its equivalent without being required to drill unnecessary wells or incur other unnecessary expenses to recover or receive the gas or oil or its equivalent") (emphasis added).
8. Couch v. Clinchfield Coal Corp., 148 Va. 455, 460, 139 S.E. 314, 315 (1927).
9. See Hunter Co. v. McHugh, 320 U.S. 222, 227 (1943).
10. See 1990 Va. Acts ch. 92, at 150, 150-69; tit. 45.1, ch. 22.1, §§ 45.1-361.1 to 45.1-361.44 (2002 & Supp. 2008). Prior to 1990, the Gas and Oil Act provided for drilling units and compulsory pooling, but did not define coalbed methane or include provisions regarding coalbed methane in the drilling unit or compulsory pooling statutes. See Elizabeth A. McClanahan, Coalbed Methane Myths, Facts, and Legends of Its History and the Legislative and Regulatory Climate into the 21st Century, 48 OKLA. L. REV. 3, 471, 540 n.532 (1995).
11. I note that the predecessor act, the Virginia Oil and Gas Act, also made significant changes to the common law treatment of oil and gas in Virginia. See §§ 45.1-286 to 45.1-361 (1989).
12. See REPORT OF VA. COAL & ENERGY COMM'N, THE STUDY OF THE REGULATION OF INDEPENDENT POWER PRODUCERS AND THE OIL AND GAS ACT, H. DOC. NO. 79 (1990) [hereinafter "H. DOC. NO. 79"]. The Coal and Energy Commission held five meetings between the 1989 and 1990 Sessions of the General Assembly, and the Commission's Oil and Gas Subcommittee and Energy Preparedness Subcommittee also held meetings. Id. at 1. The Commission allowed public comment at each of its meetings and solicited written comments throughout the process. Id. at 2. After extensive review of the comments and consideration of draft proposals, the Commission unanimously recommended that the General Assembly enact the Gas and Oil and Act. Id. at 1.
13. See § 45.1-361.22 (Supp. 2008).
14. See § 45.1-361.8 (2002).
15. See § 45.1-161.5 (Supp. 2008) (including Division of Gas and Oil within Department of Mines, Minerals and Energy); § 45.1-361.13 (2002) (establishing Board with statewide jurisdiction).
16. Section 45.1-361.13.
17. Section 45.1-361.14(B) (2002).
18. Turner v. Commonwealth, 226 Va. 456, 459, 309 S.E.2d 337, 338 (1983); Vollin v Arlington Co. Electoral Bd., 216 Va. 674, 678-79, 222 S.E.2d 793, 797 (1976).
19. See supra note 12.
20. See § 45.1-361.20 (2002) (governing field rules and drilling units), § 45.1-361.21 (Supp. 2008) (governing pooling of interests in drilling units); § 45.1-361.22 (governing pooling of interests for coalbed methane gas wells; conflicting claims to ownership); see also VA. CODE ANN. 2005 UPL Op. 209 (Supp. 2008) (acknowledging authority of Board to carry out its duties and conduct its hearings).
21. See § 45.1-361.19(C) (Supp. 2008); §§ 45.1-361.20, 45.1-361.22.
22. See § 45.1-361.15(B)(3)-(4) (2002).
23. 4 VA. ADMIN. CODE § 25-160-100(B) (Supp. 2008) (emphasis added).
24. "The term 'Royalty' in the oil and gas industry is commonly and ordinarily understood to be that share or part of production reserved or to be paid during the life of a lease; courts will take judicial notice that the usual royalty in an oil and gas lease is one-eighth of the oil and gas produced." Badger v. King, 331 S.W.2d 955, 958 (Tex. App. 1959).
25. 4 VA. ADMIN. CODE § 25-160-100(B).
26. See generally Interstate Natural Gas Co. v. Fed. Power Comm'n, 331 U.S. 682 (1947); Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672 (1954) (holding that Federal Power Commission must regulate producers' wellhead gas sales to interstate pipelines).
27. See infra notes 28, 31-32 and accompanying text.
28. Piney Woods Country Life Sch. v. Shell Oil Co., 726 F.2d 225, 242 (5th Cir. 1984).
29. Freeland v. Sun Oil Co., 277 F.2d 154, 159 (5th Cir. 1960).
30. For purposes of this opinion, the methods discussed herein as "net proceeds," "net-back method," and "proceeds" essentially are the same for purposes of determining royalty payments. Different courts use terminologies standard within their jurisdictions, but there is no distinct difference in the outcome of the royalty calculation based on these methods.
31. Martin v. Glass, 571 F. Supp. 1406, 1411 (N.D. Tex. 1983).
32. Id. at 1411-12 (citation omitted).
33. See supra notes 31-32 and accompanying text; see also infra note 37 and accompanying text.
34. See, e.g., La Fitte Co. v. United Fuel Gas Co., 284 F.2d 845 (6th Cir. 1960) ("gross income received"); Armstrong v. Skelly Oil Co., 55 F.2d 1066 (5th Cir. 1932) ("market value"); Clear Creek Oil & Gas Co. v. Bushmiaer, 264 S.W. 830 (Ark. 1924) ("market price at the well"); Gilmore v. Superior Oil Co., 388 P.2d 602 (Kan. 1964) ("proceeds at the well"); Warfield Natural Gas Co. v. Allen, 88 S.W.2d 989 (Ky. 1935) ("proceeds from the sale"); Wall v. United Gas Public Serv. Co., 152 So. 561 (La. 1934) ("market price"); Katschor v. Eason Oil Co., 63 P.2d 977 (Okla. 1936) ("market value at the well"); Cotiga Dev. Co. v. United Fuel Gas Co., 128 S.E.2d 626 (W. Va. 1962) ("rate received by lessee"); Natural Gas Distrib. Corp. v. Williams, 355 S.W.2d 194 (Tex. App. 1962) ("net proceeds at the well"). Although these terms seem similar, courts have reached very different results when considering these from time to time. Conversely, at other times the decisions have treated these as distinctions without a difference.
35. See supra note 30.
36. This method is similar to the definition of "market value" adopted in Piney Woods. See 726 F.2d at 242.
37. Cf. 30 C.F.R. § 206.151 (2008) (providing that for federal gas leases "costs of transportation, processing, or manufacturing are deducted from the proceeds received for the gas … or from the value of the gas … at the first point at which reasonable values for any such products may be determined by a sale pursuant to an arm's-length contract or comparison to other sales of such products, to ascertain value at the lease").
38. See supra note 30.
39. See supra note 37.
40. See § 45.1-361.11(C) (2002); see also § 45.1-361.18(B) (2002) (providing that voluntary pooling agreements are valid in Commonwealth). This becomes an important distinction in cases where contrary holdings were made on the basis of rules of contract interpretation. See, e.g., Estate of Tawney v. Columbia Natural Res., LLC, 633 S.E.2d 22 (W.Va. 2006) (concluding that lease language calling for royalty "at the wellhead" was ambiguous). In relying on the general rules of contract interpretation, the court concluded that the lease should be construed against the party who drafted the document and did not allow the deduction of costs incurred between the wellhead and the point of sale from the lease royalties. Id. at 273-74. Similarly, some case decisions have denied deduction of post-production costs from royalty interests on the basis that a duty to market the gas produced should be implied in the lease contract. See, e.g., Rogers v. Westerman Farm Co., 29 P.3d 887, 901 (Colo. 2001); Garman v. Conoco, Inc., 886 P.2d 652, 659 (Colo. 1994) (noting that implied covenant to market obligates lessee to incur post-production costs to place gas in condition for market). While implied duties such as a duty to market a product can be ascribed to the parties of a contract by a court interpreting a lease, that is not appropriate in the present context.
41. See infra note 45 and accompanying text.
42. VA. CODE ANN. § 2.2-4001 (2008) (defining "guidance document" as "any document developed by a state agency or staff that provides information or guidance of general applicability to the staff or public to interpret or implement statutes or the agency's rules or regulations, excluding agency minutes or documents that pertain only to the internal management of agencies").
43. Sections §§ 2.2-4000 to 2.2-4031 (2008).
44. As noted, the General Assembly has charged the Board, like all administrative agencies, with the interpretation and application of its regulations. See § 45.1-316.15. Reviewing courts will afford varying degrees of deference to the decision of an administrative agency. If the issue to be resolved falls within the specialized competence of the agency, the latter's decision is entitled to special weight. See Johnston-Willis, Ltd. v. Kenley, 6 Va. App. 231, 243-44, 369 S.E. 2d 1, 8 (1988). An agency interpretation will not be reversed unless it is arbitrary and capricious. See Va. Real Estate Bd. v. Clay, 9 Va. App. 152, 159-60, 384 S.E. 2d 622, 626 (1989). The Board's interpretation of its regulations in the present situation would be such an issue.
45. NRV Real Estate, LLC v. Va. Dep't of Health, 51 Va. App. 514, 526-27, 659 S.E. 2d. 527, 533 (2008) (alterations in original) (citations omitted), rev'd on other grounds, Va. Dep't of Health v. NRV Real Estate, LLC, 278 Va. ___, 2009 Va. LEXIS 74 (2009).
46. See, e.g., Forst v. Rockingham Poultry Mktg. Coop., 222 Va. 270, 276, 279 S.E.2d 400, 403 (1981).
47. 1990 Op. Va. Atty. Gen. 231, 232. Legislation to amend the Act to remove the Board's authority to provide for deduction of post-production costs in its orders failed in the 2009 Session of the General Assembly. See 2009 S.B. 1204, available at http://leg1.state.va.us/cgi-bin/legp504.exe?ses=091&typ=bil&val=sb1204; 2009 H.B. 2518, available at http://leg1.state.va.us/cgi-bin/legp504.exe?ses=091&typ=bil&val=hb2518. Thus, the General Assembly clearly is aware of the provision about which you inquire and chose not to enact a change.