Preview:

DISTRICT COURT, LA PLATA COUNTY, COLORADO Court address: 1060 E. 2nd Ave., Durango, CO 81301 Phone Number : (970) 247-2304 Fax: (970) 259-0258

RICHARD PARRY, et al. Plaintiff(s) COURT USE ONLY v. AMOCO PRODUCTION CO., a Delaware Corporation, n/k/a BP AMERICA PRODUCTION COMPANY Defendant(s) David L. Dickinson District Court Judge 1060 E. 2nd Ave. Durango, CO 81302

Case Number: 94CV105 Division: II Courtroom:

ORDER ON MARKETABILITY AND REASONABLENESS OF COSTS Named Plaintiffs and the members of Plaintiff subclasses consist of royalty and overriding royalty owners1 who received royalty payments from Amoco for production of gas

A royalty owner is typically the lessor under an oil and gas lease, or an assignee of the lessor. An overriding royalty is a royalty carved out of the working interest of the lessee, typically when the lease is assigned by the original lessee or its successor in interest. As the

1

1

from June 1, 1991, and who acquired their interest prior to October 31, 2001 (see Order of May 21, 2002). Plaintiffs bring this action against Defendant ("Amoco"), alleging that Amoco wrongfully deducted gathering, treating and compression costs (in the interest of brevity the Court will refer to these costs hereinafter as "GTC costs") from their royalty payments. Amoco contends that GTC costs were properly deducted pursuant to the lease language in the royalty instruments and/or that the gas is marketable at the well head, arguing that the history of gas sales in the San Juan Basin, together with existing well head sales, show that gas is marketable at the well. The primary issue before this Court is whether the gas is marketable, both in condition and location, at the well prior to GTC, or is marketable only after these processes have been completed and the gas is ready to enter the interstate pipeline. Plaintiffs originally filed this action in 1994, and in August of 2002, a bench trial was held before this Court on the issues of marketability and reasonable costs (the damages phase of the action was bifurcated). Having considered the twenty-nine volumes of trial and pretrial

distinction between royalty and overriding royalty interests is not significant for purposes of this Order, the Court will, for brevity, occasionally refer to all such interests as lessors.

2

pleadings, fifteen days of testimony, deposition designations, expert reports, thirty volumes of exhibits offered, and arguments of counsel, 2 and being advised in the premises, the Court concludes that the gas in question is marketable only at the inlet to the interstate transmission pipeline (i.e., the tailgate of the processing plant), after completion of all GTC, and that Amoco's costs, with two exceptions, are reasonable and may be assessed on a "postage stamp" basis. I. FACTUAL OVERVIEW AND CASE HISTORY The gas wells at issue are located within what is known as the San Juan Basin, which extends from northwest New Mexico to southwest Colorado. The San Juan Basin is located in an area where there is no significant local consumptive demand for natural gas. Involved in this action are some 600 wells in which Amoco owns a working interest and which are located in La Plata or Archuleta Counties in Colorado. Both conventional and coal seam gas (also known as

2

Citations to this record will be as Tr., followed by the date of the testimony and name of the witness, or to the witness and the date. Plaintiffs' exhibits will be cited as P.E. (or PE) ___; Amoco's, as Ex. ___.

3

"coal bed gas," "coal bed methane," or "CBM")3 are extracted from these wells, although the majority of the gas at issue in this case is coal seam gas (see below for a discussion of the development of coal seam gas). Plaintiffs are holders of royalty and overriding royalty interests in these gas wells. The Court considered the large number of royalty owners, commonality of their interests, typicality of the representative plaintiffs, and compelling reasons of judicial economy and certified this action as a class action by this Court's Order of September 6, 1996 (Hon. Timothy A. Patalan, Judge). The lease instruments that define the contractual relationships between the royalty owners and Amoco fall into three main categories, and the plaintiffs have been divided into three main subclasses, as discussed in more detail infra. This action was commenced after these royalty owners experienced deductions in their royalty payments for services which they now claim were inappropriately deducted. II. A. HISTORICAL BACKGROUND San Juan Basin Pipeline

3

Wells producing CBM were often referred to as "coal degas wells," because the production process involves degasification of the coal in which the gas is found.

4

Although the presence of natural gas in the San Juan Basin was known in the 1920's, no development occurred, because there was no market for the gas in the Basin. Even today, there is virtually no commercial demand for gas in the Basin. Tr. 8-15-03 (White). In the early 1950's the El Paso Natural Gas Company ("El Paso") built an interstate pipeline linking the San Juan Basin with California, and development of conventional natural gas began. A few years later, the Northwest Pipeline Co. ("Northwest") constructed a pipeline connecting the San Juan Basin with the Pacific Northwest region. The interstate pipelines built by El Paso and Northwest spurred significant activity by exploration and production companies of conventional gas, including Amoco's predecessor (Stanolind Oil Co.) and other companies whose leases Amoco later acquired. Tr. 8/21/02 (Jack); Tr. 8/20/02 (Mueller). In addition to their long-haul interstate pipelines, El Paso and Northwest also built, owned, and operated field transportation systems for conventional gas in the San Juan Basin. These systems connected individual wells with the various Central Points of Delivery ("CPD's"). The field transportation systems included compressor stations, dehydrators and plants for removal of natural gas liquids and delivered the processed gas to the inlet for the interstate transmission pipelines. Exs. 3024, 3042; Tr. 8/21/02 (Jack and Mummery)

5

From the early 1950's until the 1980's or early 1990's, gas producers in the San Juan Basin sold almost all of their conventional gas at the well head, and later coal seam gas, to the interstate or intrastate pipeline companies. Tr. 8/20/02 (Mueller); Tr. 8/19/02 (Mitchell); Tr. 8/21/02 (Jack); Exs. 2580, 3012. B. Federal Regulation and "Open Access" Beginning in 1954, oil and gas prices, as well as pipeline transmission companies, began to be regulated first in interstate commerce, and later in intrastate commerce. The federal government promulgated rules through the Federal Power Commission ("FPC"), and later the Federal Energy Regulatory Commission ("FERC"), which formed a pervasive regulatory scheme for control of well head prices, transportation charges, and charges to end users. Between 1985 and 1992, the character of the natural gas industry underwent fundamental changes due to reform of these natural gas regulations, including deregulation of well head prices and transmission pipelines. Under open access, interstate pipeline companies were required to sell space in their pipelines to gas shippers, and thereby became transporters instead of purchasers of gas. The services previously provided by pipeline transmission companies (gathering, treatment, compression, and transportation) were, in industry parlance, "unbundled."

6

Interstate pipeline companies switched from being "merchant" companies that bought gas at the well and re-sold it downstream to "common carrier" companies much like railroads. Open access enabled gas producers to sell their gas downstream from the well. Mueller; Exs. 3007, 3008. This period of regulatory reform in the natural gas industry coincided with large-scale development of coal seam gas in the San Juan Basin. Tr. 8/20/02 (Mueller); Tr. 8/19/02 (Mitchell); Tr. 8/21/02 (Jack). For a detailed discussion of this regulatory reform, see Associated Gas Distributors v. F.E.R.C., 824 F.2d 981 (C.A.D.C., 1987). For a discussion of the effects of deregulation, as well as repeal of depletion allowances, on natural gas producers, and the royalty litigation which resulted, see Anderson II (complete citation infra), at 553-571, theorizing that the net effect of open access and repeal of the depletion allowance was to give producers an incentive to "push profits downstream away from the well head and to push costs upstream toward the well head," Id., at 554. During the transition to open access, interstate pipeline companies often negotiated to be released from their contracts with oil and gas companies, as the contracts were no longer economically beneficial or even feasible. Once released, these producers were able to sell gas to alternative buyers at the well or at a downstream location. Tr. 8/20/02 (Mueller). Eventually, the

7

interstate pipeline companies substantially ceased their "merchant" functions and terminated their long-term traditional well head sales contracts with San Juan Basin producers, including Amoco. Tr. 8/20/02 (Mueller); Ex. 2807. Amoco, along with the other major oil companies, began marketing gas downstream and moving towards vertical integration to access premium markets. This gas had previously been sold at the well head. Tr. 8/21/02 (Mueller, Jack); Tr. 8/27/02 (Parker). Open access also resulted in interstate pipeline companies "spinning down" the GTC facilities that they had built in the San Juan Basin to affiliates or independent companies, thereby creating opportunities for others to purchase or build and operate the GTC facilities themselves. Tr. 8-21-02 (Jack); 8-19-02 (Kelly); Ex. 3056. After deregulation, some major gas producers in the San Juan Basin, including Amoco, chose to become "vertically integrated," providing all production and GTC services before sale of the gas at the plant tailgate or further downstream. In the New Mexico portion of the San Juan Basin and in portions of Colorado Amoco sold its gas at the well to Amoco Energy Trading Corporation ("AETC"), which contracted with third parties to gather, compress, dehydrate and process or treat the gas. AETC is a wholly owned subsidiary, formed to market Amoco's gas as

8

well as an unknown quantity of gas from other companies. AETC then resold the gas at downstream locations. Also in Colorado, Amoco built the Florida System (described infra at p. 9), and AETC was charged a fee by Amoco for gas purchased by AETC at the well and moved through the Florida System. AETC then typically resold the gas downstream, either at the plant tailgate or to end users such as major industrial users or local distribution companies ("LDCs"). C. Development of Coal Seam Gas in the San Juan Basin In the late 1980's, due to the incentive provided by a federal tax credit, gas producers began large-scale development of coal seam gas in the San Juan Basin. Under the federal tax credit, both working interest owners and royalty/overriding royalty interest owners were allowed a credit against federal income tax based on sales of CBM. Tr. 8/21/02 (Jack); Tr. 8/22/02 (Smith). As new CBM wells were drilled and existing conventional wells were re-completed to access the coal seam gas, 4 CBM wells were at first connected to the existing field pipeline systems owned by interstate pipeline companies, and the producers sold the gas at the well under

4

Wells producing conventional gas usually passed through the Fruitland formation, which is the source of CBM. By recompleting the well, it could produce CBM gas from the Fruitland formation as well. In some cases, the conventional and CBM gas was commingled; in others, each was separately produced. Tr. 8-20-02 (Mueller).

9

existing traditional well head sales contracts. These contracts were still regulated by FERC. (See below for a discussion of why construction of an entirely new gathering and treatment system for CBM wells eventually became necessary.) III. A. PRESENT OPERATIONS Natural Gas Properties and Extraction Normally the natural gas extracted consists mainly of methane, but other substances may be extracted along with the methane. For conventional gas wells, these additional substances include water vapor, "diluent" (non-combustible) gases, such as carbon dioxide (CO2), hydrogen disulfide (H2S), nitrogen, and natural gas liquids ("NGLs") such as butane and propane. For CBM wells, the additional substances include only water and diluent gases. At each well, any liquid water produced is removed by means of mechanical water separators. After the water is separated, the gas is moved to a measurement or "metering" station, also called a "custody transfer meter," by means of a short pipeline called a "flow line". The gas moves away from the metering stations near the wells in various field pipeline or "gathering" systems. Most of the gas then moves to CPD's where it is compressed and, in most cases, water vapor is removed. After leaving the CPD's, conventional gas typically is required to have the NGLs

10

removed and the diluent gases (H2S and, in some cases, CO2) reduced before it will be allowed to enter the interstate pipelines. Coal seam gas typically requires reduction in the concentration of CO2, a non-combustible diluent gas, to the specification required by the interstate pipelines, then dehydration (the amine process used to remove CO2 rehydrates the gas), then compression to interstate pipeline pressure. Conventional gas also contains CO2 but usually in concentrations below the specifications of interstate pipelines. The interstate pipeline companies' specifications are imposed for profit, safety and operating reasons. 2622 (Blauer) and 3005, 3006 (Mueller) B. The Florida River System and other San Juan Basin GTC Systems Most of the gas at issue in this case flows through the Florida River Field Transportation System ("the Florida System"), built by Amoco expressly to process CBM. The Florida System consists of field pipelines for both gas and the liquid or "free" water that is removed at the well sites, a water disposal system, CPD's, gas compressors, gas dehydrators, and the Florida River Plant. The Florida River Plant contains amine trains to remove CO2, compressors to compress the gas to transmission pipeline pressure (approximately 800 p.s.i.), and dehydrators to remove the water added by the amine trains. All of these activities are necessary to bring the gas to Tr. 8-23-02 to 8-26-02 (Blauer); Exs.

11

pipeline specifications. Amoco has owned and operated the Florida System since construction began approximately thirteen years ago. At various times since then, Amoco has added to the system as the need arose for additional capacity. Amoco bears all of the costs of the mechanical water separators, flow lines, metering stations, and well head compressors located at a small number of Amoco's wells. Amoco also bears all costs of the water disposal part of the Florida System. Those costs are not at issue. The Florida River Plant is located near major interstate gas transmission pipelines owned and operated by El Paso, Northwest (a division of the Williams Companies), and Transwestern Pipeline Co. Gas is delivered into one or more of these interstate pipelines after it moves through the Florida River Plant. Some of the gas from Amoco's wells moves away from the wells in field gathering systems owned and operated by third parties, including Red Cedar Gas Gathering Co., El Paso Field Services Co., and Williams Field Services Co. These third-party systems, like the Florida System, include field pipelines, CPD's, compressors, dehydrators, and plants. Amoco and the third parties have entered into field services contracts through which Amoco makes payments to the third parties, in the form of both money and gas, in exchange for the use of third party field

12

transportation systems. Tr. 8/22/02 (Kyle); Exs. 2273-2287. Similarly, some third parties purchase field services from Amoco. Pursuant to field service contracts, they pay Amoco for services provided to their gas in the Florida System. Tr. 8/22/02 (Kyle); Tr. 8/20/02 (Mueller); Exs. 2288-2294, 2539. Some gas produced by Amoco in this case moves between the well and an interstate pipeline using a combination of the Florida System and a system owned by a third party. Under Amoco's Third Party Purchase Program, Amoco or AETC, Amoco's wholly owned subsidiary, transacts with parties who own working interests in wells operated by Amoco. Amoco or AETC either buys the third party's gas at the well or transports the third party working interest owner's gas in the Florida System for a fee. Tr. 8-20-02 (Mueller); Tr. 8-28-02 (Kalt); Exs. 3014, 2539. IV. A. SPECIFIC FACTUAL ISSUES Royalty Instruments The royalty instruments at issue in this action have been categorized into three subcategories pursuant to the Court's Order of September 6, 1996, which the Court hereby incorporates by this reference. The categories were grouped according to their specific

13

provisions in the leases relative to the payment of royalties and allocation of costs. There have been additional orders on categorization of royalty instruments that did not vary the subclasses themselves, but only categorized additional instruments. Additional motions were filed requesting the Court to modify the categories, which the Court ultimately denied, and therefore the subclasses remain as originally defined by Judge Patalan. See Order on Modifications to Subclasses entered June 26, 2002, as well as Orders of May 17, 2002, as amended, June 13, 2002. The Court reaffirms the findings of those Orders; in particular, the finding in the May 17, 2002 Order, as amended June 13, 2002, that leases containing "at the well" or "at the mouth of the well" language but containing no other language allocating post-production costs,5 are silent as to allocation of costs, Rogers v. Westerman Farm Co., 29 P.3d 887 (Colo. 2000), hereinafter "Rogers," at 897. B. June 17, 1991 letter From the outset, Amoco expected to be able to require lessors to bear a proportionate share of GTC costs. See P.E. 65 ("All post production costs are deductible from the private

5

Throughout this Order, the Court will use "post-production" costs in the sense discussed in the May 17, 2002 Order, as amended June 13, 2002, at p. 3.

14

royalty owner unless the lease agreement specifically disallows them.").6 The initial conflict between royalty owners and Amoco began when royalty owners received a letter dated June 17, 1991(P.E. 17), in which Amoco informed leaseholders that beginning that month, their royalty check would reflect deductions for "post production" costs. Amoco stated, Beginning with your June, 1991 settlement, your check will reflect your share of post production costs associated with processing your gas through the Amoco operated Florida River Compressor Facility. Processing your gas through the components of compression, gathering and treating at the Florida River Facility is necessary to make your gas meet pipeline quality specifications and to move your gas to market.

V. A.

COMMERCIAL REALITIES OF THE SAN JUAN BASIN Production and Marketing of Gas Amoco stated to its royalty owners that "the gathering fee is primarily for compression

and dehydration of the gas to make it marketable" ( See Plaintiffs' Exhibit 69 at JM000797) and thus specifically acknowledged that their ability to market gas depends upon that gas being able

6

In other words, Amoco expected Colorado to adopt the so-called "severance rule." Amoco made a "blanket assumption" that post-production costs were deductible without review of lease agreements, P.E. 66. The GTC facilities were designed to generate revenue by charging a fee to the leases, P.E. 58, and Amoco began accounting for the Florida River and Bayfield Gas Gathering Systems as an independent profit center in April 1991, P.E. 61.

15

to enter the transmission pipeline(s) leading out of the San Juan Basin. Amoco controls most of the acreage from which CBM gas is being extracted in southern Colorado. Tr. 8/13/02 (Graham).7 When Amoco began developing the CBM reserves in the 1980's, the interstate pipeline "takeaway capacity" was not adequate to handle such additional production, Tr. 8/14/02 (White), and the conventional gas GTC facilities had insufficient capacity to handle the additional production and could not treat CBM efficiently because CBM did not need NGL removal but did need treatment to lower CO2 content. Tr. 8-19-02 (Kelly); 821-02, (Jack). To help address this problem, El Paso extended its interstate pipeline within 1

Download Parry v. Amoco Case - No. 94CV105.pdf

Colorado Law