JurisdictionUnited States
Midstream Oil & Gas from the Upstream Perspective
(Apr 2018)


Judith M. Matlock
Davis Graham & Stubbs
Devner, CO

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JUDITH M. MATLOCK is a partner in the Energy Group of the Denver law firm of Davis, Graham & Stubbs LLP. For thirty-five years she has represented companies in the oil and gas industry. Her practice has emphasized the post-production side of the business. She is involved in all aspects of the gathering, transportation, processing, fractionation, and marketing of natural gas, liquids, and crude oil and representing producers in connection with the calculation, payment, and reporting of royalties and production taxes. Her practice also includes public utility law involving both gas and electric utilities. She received her undergraduate degree (B.A. 1979) from the University of Colorado at Denver and her law degree (J.D. 1982) from the University of Colorado at Boulder. She is a member of Phi Beta Kappa, Order of the Coif, and the Denver, Colorado, and American Bar Associations. She has been named in The Best Lawyers in America® (oil and gas) since 1995. She is an active participant in the Rocky Mountain Mineral Law Foundation and has served on the Executive Committee, as a trustee, and co-chair of the Special Institutes Committee. She has also been the program chair for several RMMLF special institutes and short courses, was the program chair for the 2010 Annual Institute, and is a frequent lecturer and writer on energy topics. She teaches the oil and gas marketing section of the Foundation's Oil and Gas Law Short Courses. She is a frequent lecturer and writer on energy topics including two annual institute papers and over a dozen special institute papers for the Rocky Mountain Mineral Law Foundation, and numerous other papers for various oil and gas associations. Some of her papers include "Natural Gas Processing Agreements," Natural Gas Marketing I, Paper No. 7 (Rocky Mtn. Min. L. Fdn. 1987); "Natural Gas Processing Agreements," Natural Gas Marketing II, Paper No. 7 (Rocky Mtn. Min. L. Fdn. 1988); "Contract Considerations for All Buyers and Sellers," "The Natural Gas Wellhead Decontrol Act of 1989," 19 Colorado Lawyer 655 (1990); "Federal Regulation of Natural Gas," Natural Gas Conference, Handout (Energy Decisions, Inc. 1990); "Gas Marketing, Transportation, and Balancing," 1991 AAPL International Conference & Annual Meeting (Denver, Colorado); "Federal and State Regulation of Sales and Transportation," Negotiating Natural Gas Contracts in the Order 636 Environment, Paper No. 3 (Rocky Mtn. Min. L. Fdn. 1993); Who Rules Interstate Gathering?" Natural Gas: How to Keep Winning (Hart Publications 1993); "Transportation Tariffs and Agreements," Practical Natural Gas Marketing Short Course, Paper No. 5 (Rocky Mtn. Min. L. Fdn. 1994); "Workshop - Nominations, Allocations and Penalties in Detail," Practical Natural Gas Marketing Short Course, Paper No. 6 (Rocky Mtn. Min. L. Fdn. 1994); Overview of Federal Regulation," Oil and Natural Gas Pipelines - Wellhead to End User, Paper 2A (Rocky Mt. Min. Law Fdn. 1995); "Catching up: The Need to Reflect the Current Gas Marketing Environment in Oil and Gas Agreements," Journal of Land, Resources, & Environmental Law, pg. 305 (University of Utah College of Law 2004); Natural Gas Gathering, Transportation and Storage Agreements," Oil and Gas Agreements II (Rocky Mt. Min. L. Fdn. 2005); and "Federal Oil and Gas Pipeline Regulation - an Overview," Oil & Gas Agreements: Midstream and Marketing, Paper 4 (Rocky Mtn. Min. L. Fdn. 2011).


I. The Implied Duty to Market - Does It Require Producers To Construct Their Own Gathering Line?

II. Who's Going To Pay For It - Must or May It Be Constructed Under the Operating Agreement?

A. Analysis under the AAPL Model Form 610.

1. The 1982 Form 610 and Earlier Versions.

2. The 1989 Model Form 610.

3. The 2015 Model Form 610.

4. What If Not Everyone Wants to Participate - May a Gathering Line Still Be Built?

B. Ownership Options.

1. Separate Joint Operating Agreement.

2. Separate Legal Entity.

3. What Other Agreements Are Needed?

III. Who Can Use It - Can a Producer-Owned Gathering Line Be a Private Line?

A. Access to the Gathering Line By All Working Interest Owners in a Contract Area.

B. Qualifying For the Gathering Exemption Under the Natural Gas Act.

C. Federal Regulation of Crude Oil Movements Under the Interstate Commerce Act.

1. Jurisdictional Movements Under the ICA.

2. The Uncle Sam Company Private Line Exception.

3. Temporary Waivers.

4. Embracing Federal Jurisdiction - Capacity Rights to Fund New Construction.

D. Regulation of Offshore Oil and Gas Lines under the Outer Continental Shelf Lands Act.

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E. Common Carrier Regulation.
1. Rights-of-Way Acquired Under the Mineral Leasing Act.
2. Common Law Common Carriers.
3. State Ratable Take and Common Purchaser Statutes.
4. State Public Utility Regulation.

IV. Coming Up With a Gathering Rate.

A. Cost of Service Type Rate Under the 1985 COPAS Facility Rate Agreement.
B. Rates For Movements of Crude Oil Subject to Federal Regulation Under the ICA.
C. Non-arm's Length Transportation Allowances for Federal and Indian Production - Cost of Service Regulations.
D. State Requirements For Establishing Rates.

V. Royalty Implications of Non-Arm's-Length Transactions.

A. Fee leases.
1. Non-arm's length sales.
2. Non-arm's length services.
B. State leases.
C. Federal and Indian Leases.

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It seems like a simple idea: if a midstream company will not connect to you at all or at a reasonable price, then build your own gathering system to connect to them or someone else downstream. Producers making the decision to construct their own gathering facilities will have all of the same issues as third-party gatherers but, in addition, as producers they will have some unique issues to address as well. The purpose of this paper is to discuss those unique issues.

I. The Implied Duty to Market - Does It Require Producers To Construct Their Own Gathering Lines?

The first consideration in some cases may be whether producers must construct their own gathering lines to hold their leases? The answer depends upon the implied duty to market and the wording of any shut-in royalty clauses in the leases involved.

If a lease does not expressly address the duty to market production, courts imply a covenant to market.1 The duty is measured by "reasonable diligence under all the facts and circumstances of the particular situation."2 The diligence "is to be measured by what a reasonably prudent operator would have done under the circumstances, having in mind his own interest as well as that of the lessor."3

Some of the factors that are considered in evaluating a lessee's diligence are the availability of marketing facilities, such as pipelines, and efforts the lessee made to secure the extension of pipelines into the field.4 As to whether the implied duty to market obligates lessees to construct facilities, Professor Merrill's view in 1940 was that the answer should be yes if there is reasonable ground for anticipating profit from the adventure.5 However, Professor Merrill also recognized that the case law

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was to the contrary.6 Since Merrill's treatise was written, some cases have required the lessee to construct pipelines or other facilities, depending on the facts.7

Lessees, although subject to an implied covenant to market, have not been required to do more than arrange for the sale of production at the lease, if there is a market there.8 Lessees are not required to go into a separate business.9

Absent an express clause in the lease, the amount of time a lessee has to comply with the duty to market depends upon the facts and circumstances.10

In some cases, a lease may contain a shut in royalty clause. The purpose of a shut-in royalty clause is to allow a lessee to keep a lease in effect beyond the primary term by making shut-in royalty payments where a well is completed and capable of producing gas in paying quantities but there is no market for the gas.11 Note, however, that even if a lessee is making shut-in royalty payments, the implied duty to market applies and the lessee must still diligently search for a market. Levin v. Maw Oil & Gas LLC.12

The case of Union Oil Co. of Cal. v. Ogden,13 illustrates the benefit of having a shut-in royalty clause. The case involved one well covered by two leases, one containing a shut-in royalty clause and the other without a shut-in royalty clause. A well capable of producing in paying quantities was completed two days before the end of the primary term. Well testing was completed two months later.

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The well was then shut in for the next twenty months at which time the well was connected to the gathering lines of the Empire Southern Gas Company. In order to make that connection, the lessee paid for construction and installation of a gas line from the well to Empire Southern Gas Company system, a distance of half a mile.

The shut in royalty clause of the first lease allowed the lessee to make a shut in royalty payment on or before the first day of January of each year when there was no production, for lack of a market, until production could be profitably marketed by the lessee. The Court held that, as to the lease with the shut in royalty clause, the payment of the shut in royalties prevented the lease from expiring at the end of the primary term. As to the lease without the shut in royalty clause, the court held that because a well capable of producing in paying quantities had been discovered prior to the expiration of the primary term, "the lessee should have a reasonable time to market the gas, even though the time required should extend beyond the primary term." However...

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