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Volume MMXXV • No 2
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Contents Feature
Articles
NADOA 2025 Officers President Kimberly Bowman 1st Vice President Jean Hinton 2nd Vice Presiden t Armando Lopez Treasurer Iris Alcantara Corresponding Secretary Nichole Dwire, CDOA Recording Secretary Samantha Rodelo
Legal Updates Colorado Water Usage Standards...............................................6 North Dakota Risk Penalties (Liberty v. NDIC)...........................................11 Statutory Interest on Suspended Overrides...........................14 Does the Texas Form Title Opinion Work in Oklahoma, Part I.........................................................20 Texas Supreme Court Clarifies Effect of Double Payment Under Lease Savings Clause......................................................27 Legal Watch Ohio Dormant Minerals Act......................................................28 Basic Division Order Skills.........................................................32 Addressing the Shortage of Entry Level DOAs.............................34 National Niche - LNG Regulation Amendments.........................35 Cheers to Education in Boston! ...................................................37
The NADOA News Magazine is a quarterly publication of the National Association of Division
In This
Issue
Order Analysts P O Box 1656 Palm Harbor, FL 34682
President’s Corner..............................................................1 Decimal Points...................................................................2 Cob Webs............................................................................3 Nominations for 2026 Board..............................................4 Certification....................................................................... 4 In Memory - Russell T. Rudy.............................................30 New Members...................................................................45 Counterpart Connection...................................................46 Interaction - NAPE 2025..................................................49 NADOA Board & Committee Chairs................................50 Institute Committee..........................................................51 Calendar of Events...........................................................52
Subscription: By membership to NADOA, at $100.00 per year. News Magazine Editor Rona L. Erickson, CDOA magazine@nadoa.org
Graphic Design, Paul Beach
On the Cover: Charles River view Photo Courtesy of The Westin Copley Place
All rights reserved. No part of this publication may be reproduced/copied without written permission. Editorial disclaimer: The contents of this newsletter are intended for member use only and any other use without permission from the NADOA Board of Directors is strictly prohibited. Articles published herein represent the view of the authors; publication neither implies approval of the opinions expressed nor accuracy of the facts stated and NADOA accepts no liability for misprints.
President’s
Corner
Kimberly A. Bowman 2025 NADOA President
Cheers to Education in Boston: Join Us for the 52nd NADOA Institute!
For the first time in NADOA history, we are heading to Boston—and what an exciting destination it is! Known for its rich history, academic excellence, and vibrant culture, Boston is the perfect backdrop for our 52nd Annual Institute , themed: “Cheers to Education in Boston!” I recently had the pleasure of exploring the city on a personal trip with my daughter. We were captivated by the stories etched into every cobblestone and corner. One of our first stops was the Old State House , built in 1713, which once served as the center of royal government in the Massachusetts Bay Colony. This historic landmark was also the site of the infamous Boston Massacre in 1770 , a pivotal moment that stoked the flames of revolution. We also visited the Old South Meeting House , constructed in 1729. In colonial times, it was Boston’s largest public building and a key gathering place for debates and discussions that led to the Boston Tea Party —one of the most iconic acts of resistance in American history. Boston’s deep historical roots stretch back to 1630 when Puritan settlers founded the city on the Shawmut Peninsula . Throughout the American Revolution , Boston was at the heart of the action, witnessing major events such as Paul Revere’s midnight ride , the Battle of Bunker Hill , and the Siege of Boston . But Boston is more than its past—it’s a dynamic, modern city filled with innovation, art, education, and energy. It’s an ideal setting for NADOA’s 2025 Institute as we look toward the future of our industry. Currently, NADOA proudly counts 851 professionals in its growing membership. We’re excited to welcome new and returning members in what promises to be a standout year for growth, collaboration, and fresh ideas. If you have suggestions to enhance our organization, I encourage you to reach out to me or any board member—we value your voice and are always open to new perspectives. This Year’s Institute: What to Expect The 52nd Annual Institute will take place August 27–29, 2025 , at The Westin Copley Place . Registration is officially open, and we strongly encourage everyone to take advantage of Early Bird pricing before the June 30th deadline. Located in the heart of Boston’s Back Bay, our venue offers easy access to the Boston Public Library , Old South Church and trendy Newbury Street . The hotel is also connected to Copley Place Mall , making dining, shopping, and sightseeing incredibly convenient. Whether by foot or Uber, you’re only minutes away from Boston’s top attractions, museums, and historical treasures. The Institute Committee has poured countless hours into curating a remarkable lineup of industry-leading speakers , engaging sessions, and fresh content designed to keep pace with our rapidly evolving field. This year, expect a few new twists that reflect the energy and change happening across our profession. So, mark your calendars, secure your spot, and prepare for an inspiring few days in one of America’s most storied cities. Boston is calling—and NADOA is ready to answer.
NADOA’s 2025 Board and Institute Committee can’t wait to see you there!
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NADOA
Decimal Points
Special Institute Edition......................... June 6 Third Quarter.............................September 12 Fourth Quarter............................November 14 2025 News Magazine Deadlines
Regional Reporters
ABADOA
Steptoe & Johnson PLLC Ryan.daniels@steptoe-johnson.com
CAPDOA
OPEN
DADOA
Kelly Sandoval, CDOA Kelly.sandoval@sitio.com
DALWORTH Lewis Box, CDOA lewis.box@gmail.com HADOA Emily Sheffield
NADOA online Job Bank has new postings. Visit https://nadoa.wildapricot.org/page-662233 ADVERTISE WITH NADOA Advertising in the NADOA Newsmagazine is a great way to get your business name out to NADOA members. Contact Cheryl Hampton at champton@limerockresources.com for details.
esheffield@oglawyers.com
PBADOA
Kaprice Pearson kpearson@vtxep.com
SADOA
Dena Blevins dblevins@frontierland.net
Arkansas
OPEN
Kansas
Amy Flaming Amy.flaming@chsinc.com Kimberly A. Backman kbackman@crowleyfleck.com Zachary P. Oliva zoliva@oglawyers.com Margaret Patton mpatton@pattonfirm.com
North Dakota
New Mexico
2025 News Magazine Team
Louisiana
Be sure to keep your NADOA directory information up to date. With the many changes happening in our industry and the world, staying connected with professional contacts and taking full advantage of the educational opportunities NADOA membership offers has never been more crucial. If you have a suggestion for someone to act as a Regional Reporter to help NADOA keep abreast of current legislation and legal issues for a region, please submit the name or name of the firm to magazine@nadoa.org .
Rona Erickson , CDOA Editor
Melanie White, CDOA Associate Editor
Susan Bradley, CDOA Associate Editor
Somchay Fairbanks, CDOA Associate Editor
Sara Buck Associate Editor
Cheryl Hampton Associate Editor, Advertising
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Cob Webs
Educational webinars can be approved for 1 (one) CDOA certification point. NADOA webinars, Steptoe & Johnson
Opportunities include: creating webinar flyers, contacting speakers before a webinar event to obtain biographies and presentations, and helping modernize NADOA’s GoToWebinar site. Please email webinars@nadoa.org if you are interested. The 2025 Webinar Co-Chairs, Gordon Gallet, Sara Buck, and Yoli Bazan would love to hear from you! Steptoe & Johnson PLLC – Visit: https://www.steptoe-johnson.com and click on News for details. The Steptoe webcasts are recorded: to access previously recorded webcasts, go to www.Steptoe- Johnson.com and enter Webcasts in the search feature. Oliva Gibbs LLP – Energy Education Series: Visit: www.oglawyers.com/ events for further information. NARO – Visit: https://www.naro-us.org/events/list for webinar schedule. If you are aware of other educational webinars, please advise the NADOA News Magazine of details to be added to the Calendar of Events ( magazine@nadoa.org ).
PLLC webcasts and Oliva Gibbs LLP webinars are pre-approved. Please check the certification page to determine if other webinars are pre-approved or need to be submitted for approval to the NADOA Certification Committee. Contact the CDOA committee to obtain pre-approvals at cdoa@nadoa. org . Certification points should only be applied for after completing the event. If you are unable to attend an event due to unforeseen circumstances, it is an ethics violation to apply for the credit. NADOA – Webinar information and registration links will be posted on the website ( www.nadoa.org ). Webinars are free for NADOA members and $15.00 for non-members. NADOA members may use the following link to log in and register for upcoming webinars, as well as listen to previously recorded webinars https://nadoa.wildapricot.org/ page-1709226 or by using the Webinar link in the Members Only section on the homepage. Please send suggestions for NADOA webinar topics/ speakers to webinars@nadoa.org . Details for upcoming NADOA Webinars can be found at: https://nadoa.org/news-events/ The webinar committee is looking for volunteers.
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LOOKING FOR CANDIDATES FOR 2026 NADOA BOARD POSITIONS:
• 2nd Vice President • Recording Secretary • Corresponding Secretary
Contact Vicki Danielson by June 1, 2025, vdanielson@att.net For more details on positions, log into NADOA.org / Publications / Bylaws For candidates who have already contacted me, please provide a picture and your bio by June 1, 2025.
CANDIDATES FOR CERTIFICATION Publication of the following “Certified Division Order Analyst” applicant(s) fulfills the requirement as stated in the Voluntary Certification Policy, III C.2, which states: “…applicant’s name will be published in the NADOA Newsletter or other official publication of NADOA.” This allows the NADOA membership an opportunity to present objections to the certification of the applicant. Any objection to the certification of the applicant must be in writing and signed by a NADOA member or non-member who qualifies his knowledge and objection of the applicant. All such letters will be considered confidential and must be received by the NADOA Certification Committee at the following address within thirty (30) days following the last day of the month in which the Newsletter or other official publication of NADOA was published: NADOA Certification Committee P O Box 1656 Palm Harbor, FL 34682 If the objection warrants denial of the certification or temporary withholding of certification, the applicant will be notified by Certified Mail. CANDIDATE FOR CERTIFICATION
Kyndall Leone – Midland, TX
CANDIDATES FOR RECERTIFICATION
Lisa Leigh Greer – Rockwall, TX
Dea Anna Mengers – Mustang, OK
Melanie B. Finnegan – Frisco, TX
CDOAs WHOSE CERTIFICATIONS ARE DUE TO EXPIRE (These CDOAs need to contact the CDOA committee to confirm that you have been informed of the decision to move your expiration date to 1/1/2026. If we do not hear from you, we will take your non-contact as a request to move your CDOA status to “Inactive”).
Annette Boyd – SADOA John Cameron – HADOA Michelle Carter – CAPDOA Lyndsay Cavanagh – HADOA Lazara Coronado Deborah Godwin – HADOA
Sally Holt – PBADOA Erica Honeycutt – DADOA Tara Miller – SADOA Lauretta Randle – HADOA Kelly Sandoval Monica Wamsley - HADOA
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Interested in becoming a CDOA?
Schedule for Upcoming Events May 22, 2025 – NADOA Webinar – High Level Overview of Section 3 (Chapters 9 - 15) presented by Stephanie D. Moore, CDOA July 2 4 , 2025 – NADOA Webinar – High Level Overview of Section 3 (Chapters 16 - 24), presented by Luanne Johnson, CDOA, CPLTA August 27, 2025 – NADOA Institute, Boston, MA – 2 Wednesday sessions covering Sections 1 and 2. Presenters – Eli Murray, CPL, CDOA, CPLTA and TBD
QUIZLET www.quizlet.com/search/ Utilize quizzes, flashcards, and more super easy on your phones! Create an account for FREE to track your progress Minimum of 9 pages of flashcards Multiple quizzes available. ***NOTE*** There is another group named CDOA that uses Quizlet, so if the material isn’t DO related, just move on to the next set . www.quizlet.com/search/ Utilize quizzes, flashcards, and more super easily on your phone! Create an account for FREE to track your progress. Minimum of 9 pages of flashcards. Multple quizzes available.
LINKS https://nadoa.org/certification/ https://nadoa.org/wp-content/uploads/2024/01/NADOA-CertificationPolicy- 1.1.2024.pdf https://nadoa.org/wp-content/uploads/2024/01/CDOA-Blank-App.pdf https://nadoa.org/wp-content/uploads/2021/11/CDOASponsorFormNew.pdf CERTIFICATION EMAIL cdoa@nadoa.org
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Legal
Updates
Articles are not intended to be and should not be relied upon as legal advice or to establish any kind of an attorney-client relationship with the author.
Colorado Finalizes New Water Usage Standards for Oil and Gas Operations By Jim Tartaglia, Steptoe & Johnson PLLC
The Colorado Energy and Carbon Management Commission (ECMC or Commission) recently adopted a set of new regulations aimed at limiting freshwater usage, and in turn promoting the use of recycled produced water, to support oil and gas operations across the state (collectively, Rules). This article provides a high-level summary of the Rules.
§ 34-60-135(2-3). The Consortium was tasked with developing a series of recommendations to guide the Commission in its development of the Rules. See id. at -135(4). In accordance with those recommendations and the statutory directives, and based on a six-month administrative record with substantial public and industry input, the Commission finalized its 2024-2025 Produced Water Rulemaking on March 15, 2025.
Background
Produced water is any water that is co-produced with hydrocarbons at the wellhead. Depending on several factors, a well operator will either dispose of produced water that it extracts (often by subsurface injection) or instead will recycle or reuse that produced water to support other drilling, completion, or enhanced recovery operations. A primary goal of the Rules is to incentivize the recycling and reuse of produced water by operators, and in turn, decrease the amount of fresh water used in oil and gas development processes. The impetus for the Rules dates back to House Bill (H.B.) 23-1242 (effective June 7, 2023), which enacted directives focused on the use of fresh water in oil and gas operations. That legislation imposed certain specific reporting requirements, and further mandated that the Commission adopt new regulations “to require a statewide reduction in freshwater usage, and a corresponding increase in usage of recycled or reused produced water, at oil and gas locations.” C.R.S. § 34-60-134(5) (c)(I). H.B. 23-1242 also created the Colorado Produced Water Usage Consortium (Consortium), comprised of 31 members representing an array of public and private stakeholder groups. See C.R.S.
New Produced Water Usage Standards
The Rules establish basin-wide targets that each operator must meet by ensuring that, for a given compliance period, a minimum percentage of its total water usage is recycled produced water or an acceptable alternative. Under the Rules, “Recycled Produced Water” includes any produced water that is reused in oil and gas operations, with or without reconditioning or other treatment. See 2 C.C.R. 404-1-100. Further, the reuse of any of the “Recycled Produced Water Alternatives” (Alternatives) enumerated in the Rules’ definition will be accounted for like Recycled Produced Water when measuring compliance. These Alternatives include brine and other chemical-rich liquids that are commonly disposed of and not returned to the hydrological cycle. See id. Basin-Wide Usage Measurements. As noted above, compliance with the Rules is a basin-wide assessment. When determining if an operator has met the minimum percentage required, the Rules focus on that operator’s aggregate water usage across all applicable wells within a designated geologic basin (as those geologic basins are identified in the 2002 version of the Colorado
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Geological Survey’s MS-33 Oil and Gas Fields of Colorado). See 2 CCR 404-1-431(e)(2). In line with the Consortium’s recommendations, these new water usage standards will be phased in, and measured over the course of four-year compliance periods starting on January 1, 2026. Operators must also account for any permitted wells outside of an established geologic basin; for purposes of compliance, any ‘non-basin’ well must be treated as and allocated toward the basin nearest in proximity to such well location. See id. The Commission’s decision to measure compliance with the Rules across each basin (as opposed to a state-wide average, as the Consortium recommended), or on the other hand, measuring at a micro level, was an intricate one. Historically, there has been a large disparity in produced water usage across the state due to differences in topography, infrastructure, and localized water scarcities. Four-Year Compliance Periods. In the first compliance period, “an Operator’s geologic basin- wide combined oil and gas developments permitted on Oil and Gas Development Plans (OGDPs) filed after January 1, 2026, and the combined subsequent operations to recomplete or restimulate any existing well within the relevant geologic basin, will use a minimum average of 4% Recycled Produced Water and Recycled Produced Water Alternatives for Well Stimulations commenced before January 1, 2030.” 2 C.C.R. 404-1-905.c.(6)(A)(i) . During the next period, which begins on January 1, 2030, “an Operator’s geologic basin-wide combined oil and gas development, regardless of when the Wells were permitted, will use a minimum average of 10% Recycled Produced Water and Recycled Produced Water Alternatives for Well Stimulations commenced before January 1, 2034.” See id. at 905.c.(6)(A)(ii). The Commission declined to formalize the Consortium’s recommended targets for later compliance periods. Instead, the Rules call for the Commission to conduct further rulemakings by June 1, 2028, to set minimum requirements for the periods beginning in 2034 and 2038; but if later rulemakings do not occur, the recommended averages of 20% for 2034- 2037 and 35% for 2038-2041 will become effective. See id. at 905.c.(6)(A)(iii).
An operator must demonstrate compliance with the water usage standards, measured by that operator’s proportionate, aggregate usage of Recycled Produced Water (or Alternatives) across all of a relevant geologic basin. See 2 C.C.R. 404- 1-905.c.(6)(B). More specifically, the calculation of this compliance measurement is (i) the total volume of Recycled Produced Water used, plus the total volume of Alternatives used, (ii) plus Recycled Produced Water Credits (Credits, discussed further below) created at all applicable wells within the basin during the relevant four-year compliance period; (iii) divided by the total volume of all water used for Well Stimulations at all applicable wells within the basin during the relevant four-year compliance period.” See 2 C.C.R. 404-1-431.e.(2)(G) . Compliance with these standards, including the creation or transfer of any Credits, will be tracked by several new reporting requirements introduced by the Rules.
Additional Reporting Requirements to Monitor Compliance
Operators must demonstrate compliance with the new usage targets via new reporting and filing requirements that call for water usage data to be reported monthly, quarterly, and annually, as further explained below. Annual Certifications. While the Rules establish four-year compliance periods as described above, it is important to note that the reporting of relevant water usage figures, and whether an operator is on pace to meet the compliance targets, is required on a yearly basis. Starting in 2027, by April 1 of each calendar year, each operator will be required to submit a certification to the ECMC that states whether it met the applicable water usage standard for the previous year(s) in the compliance period. See 2 C.C.R. 404-1-905.c(6)(D) . Notably, with respect to the first year in any compliance period, operators must show that they reached no less than 50% of the applicable percentage target for the period during that first year.
For example, in the first Annual Certifications due before April 1, 2027, an operator would
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demonstrate that it met a 2% usage target for calendar year 2026; for each year thereafter, the operator would demonstrate its average compliance equaled or exceeded the 4% usage target across all wells for the entire four-year compliance period to date. In the event an operator does not meet the minimum usage requirement in any Annual Certification, it must file with the Commission a compliance plan that outlines further steps the operator intends to take in order to achieve the minimum usage target by the end of the compliance period. Form 47 – Quarterly Water Use Reports. The content required in Form 47, which operators must submit on a quarterly basis, is driven directly by statutory amendments from H.B. 23-1242. In these filings, an operator must provide a detailed report of its water usage, for each Oil and Gas Location ( i.e. , for each well pad), including but not limited to: (i) the sources and volume of fresh water used by the operator at the location; (ii) the sources, types, and volumes of all Recycled Produced Water and Alternatives used by the operator at the location; (iii) the methods and amounts of Produced Water and Recycled Produced Water Alternatives disposed of by the operator at the location; and (iv) the total volume of all water used at the location in each month of the preceding quarter. 2 C.C.R. 404-1-431.e.(1); see also C.R.S. § 34- 60-134(3). Each Form 47 must also contain similar volumetric data reported on a basin-wide basis, and if applicable, must contain information regarding the creation and/or transfer of Credits earned by the operator during the quarter, and during the applicable four-year compliance period. See 2 C.C.R. 404-1-431.e.(2). Other Reporting Changes. The Rules also impose several other changes to the ECMC’s reporting requirements, including Form 7’s report of monthly downhole water usage and disposal or treatment practices for each well. Each operator must also report total fluids and water types used in drilling operations and well stimulation on each Form 5 (Drilling Completion Report) and Form 5A (Completed Interval Report) that the operator files. See 2 C.C.R. 404-1-431.a., -431.b.
Produced Water Credit System Incentives Continued Improvement
One major highlight of the Rules is the potential to earn tradeable Credits for exceeding the minimum standards in a compliance period. In that event, an operator can claim Credits for the total volume of Recycled Produced Water and/or Alternatives used in excess of what was necessary to meet the minimum threshold for that compliance period. See 2 C.C.R. 404-1-905.c.(6)(C). The creation of a Credit must be identified on the new Form 47, or on an operator’s Annual Certification. See id at 905.c.(6) (C)(i). All water volumes reported under the Rules must be expressed in Barrels; with respect to the credit system, one Credit earned or used is equal to one barrel of water used in excess of or toward satisfaction of the applicable percentage standard for the compliance period. See 2 C.C.R. 404-1- 905.c(6)(C). These Credits may be traded to third party operators in the marketplace, encouraging continued commitment to recycling and reuse by operators that are well above the compliance minimum; provided, however, Credits may be traded and applied only within the same geologic basin and may be held only by approved “Operators” in the state (there being no avenue for ‘credit-trading’ entities to enter the market). See id at 905.c.(6)(C)(ii) . Any transfer of Credits must be reported to the Commission within ten (10) days of the transfer by filing the new Form 48. See id. The Credit system is intended to bring flexibility to compliance and incentivize continued improvement of recycling practices beyond meeting minimum targets. It does, however, carry certain notable limitations. For example, Credits are subject to expiration – when an operator seeks to utilize Credits that it created, or acquired by trade, to meet its compliance targets, it must apply those Credits within the same four-year compliance period as they were created, or within the first two years of the ensuing period. See id at 905.c.(6)(C)(i).
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to conduct further rulemakings before the end of 2026 that will impose additional requirements on operators to report air emissions associated with their produced water recycling efforts. See generally, Cause No. 1R, Docket No. 240900229 (https://ecmc. state.co.us/hearings.html#/rulemaking/producedwater).
Other Aspects of the Rules
The Rules formalize several additional requirements relating to the water usage standards, several of which were specifically directed by the statutory amendments of H.B. 23-1242. Examples of these other considerations are outlined below. Waste Management Plans. New Rule 905.a.(4) requires any operator submitting a Form 2A (Oil and Gas Location Assessment) to have a detailed waste management plan that outlines “how the operator will treat, characterize, manage, store, dispose and transport all types of [E&P Waste] generated” at the proposed well site. Further, each OGDP filed after January 1, 2026, must include a plan that specifies how the operator intends to recycle and reuse produced water as necessary to meet the minimum percentages imposed by the Rules. See 2 C.C.R. 404-1-905.a.(4). DIC Siting Prohibition. While the water usage system will necessitate the eventual growth of water treatment facilities and related infrastructure development, the Rules reiterate the broad legislative prohibition against the siting of any new “Centralized E&P Waste Management Facilities” in any area designated as a Disproportionately Impacted Community under existing ECMC regulations. See 2 C.C.R. 404-1-907.b.(5) . This includes any facility that “receives for collection, treatment, temporary storage, and/or disposal of Produced Water, drilling fluids, completion fluids, and any other exempt E&P Wastes” generated from oil and gas operations. See 2 C.C.R. 404-1-100 . Air Quality Concerns. As directed by H.B. 23-1242, the Commission acknowledged in its rulemaking that these new water usage standards would, over time, require infrastructure improvements and operational changes, which themselves could pose additional environmental impacts, namely with respect to air emissions. To address those concerns, the Rules require the submission of quarterly reports that detail, in mileage, the operator’s reliance on water transport trucks to take fresh and produced water from each well location to and from recycling or disposal sites. See 2 C.C.R. 404- 1-431.f .(1). Finally, the Commission has committed
Conclusion
As outlined above, while their enforcement will be phased in over the coming years, the Rules pose a host of new monitoring and reporting burdens on operators in Colorado. Time will tell whether compliance with the Rules will significantly impact the economic viability of new development, at least in certain basins or regions in the state.
The Author:
James M. Tartaglia, Member Charleston, WV
Phone : (304) 353-8185 Email : jim.tartaglia@steptoe-johnson.com Jim Tartaglia concentrates his practice
in the area of energy and natural resources law. Mr. Tartaglia regularly assists clients with a variety of their transactional needs, including mineral title and due diligence, corporate and securities matters, and oil and gas lending. Licensed In • Colorado • West Virginia • Virginia
Avoid headaches from explaining the ins and outs of royalty ownership to your interest owners... ...Let us help! National Association of Royalty Owners PO Box 131090, Spring, TX 77393 www.naro-us.org Phone: 918-794-1660
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No Risk No Reward: The Liberty v. NDIC Decision Holds That Risk Penalties Can be Recovered from Total Unit Production By: D. Bradley Gibbs
In Liberty Petro. Corp. v. N.D. Indus. Comm’n , 1 the Supreme Court of North Dakota addressed whether nonconsent risk penalties must be assessed on a well-by-well basis or can be recovered from overall unit production. The court agreed with the North Dakota Industrial Commission’s (“NDIC’s”) approval of a unit plan that allowed risk penalties to be recovered from unit production as opposed to limiting recovery to the specific nonconsent well.
The Haystack JOA provided that the operator could recover risk penalties out of unitized production – including the prior outstanding balances due on the 4 nonconsent wells. In other words, under the JOA, the operator could withhold production from the 7 consent wells to satisfy Liberty’s penalty balances on the 4 nonconsent wells. Liberty, on the other hand, argued that penalties could only be recovered from production from the specific nonconsent well in which the penalty accrued. Anything else, Liberty argued, was “unfair and inequitable” and even a constitutional regulatory taking. Rejecting Liberty’s arguments, the NDIC approved the Haystack UA and JOA, finding that the unitization as proposed was in the public interest, protected correlative rights, and maximized production of oil and gas. The NDIC based this reasoning on the fact that production from the wells in the unit area is no longer attributable to individual wells and spacing units, but instead is attributable to the tracts in the unit on a pro rata acreage basis. Liberty appealed this decision to the district court who affirmed the NDIC’s decision. On appeal to the Supreme Court, the issue was narrowly framed as whether pre-unitization risk penalty balances can be recovered out of subsequent unit production or must be recovered at the well level.
I.
Background & Unitization
In 2022, Burlington Resources Oil & Gas Co. LP (“Burlington”) filed for unitization with the NDIC, creating the Haystack Butte Unit (the “Haystack Unit”) in McKenzie County, North Dakota. The goal of unitization was to allow wells to be drilled without regard to prior drilling and spacing unit (“DSU”) boundaries that would restrict the length and location of horizontal wellbores. As part of the application process, Burlington submitted a proposed unit agreement (the “Haystack UA”) and a proposed unit operating agreement (the “Haystack JOA”). Liberty Petroleum Corporation (“Liberty”) contested the unitization.
Prior to the plan of unitization, the Haystack
Unit area consisted of multiple DSUs with 19 producing wells. Liberty owned a working interest in 6 of the DSUs containing 11 of the producing wells. Liberty had elected to participate in 7 of the 11 wells and was “nonconsent” in the remaining 4 wells. Notably, 3 of the 4 nonconsent wells were located in DSUs that also had wells where Liberty was participating. Liberty had been assessed a 200% risk penalty for each nonconsent well under the North Dakota Compulsory Pooling Statute, 2 and had an outstanding drilling, completion, and risk penalty balance at the time of the petition for unitization.
II.
How are Past Risk Penalties Assessed?
Chapter 38-08 of the North Dakota Century Code (“Control of Oil and Gas Resources”) creates separate but similar compulsory pooling schemes for: (i) pooled units (for example a 2-section or “1280” DSU); and (ii) larger reservoir-based unitized
[1] 11 N.W.3d 851 (N.D. 2024). [2] N.D. Cent. Code § 38-08-08.
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areas covering a common source of supply. The Compulsory Pooling Statute authorizes a risk penalty on leased working interest owners in the amount of 200% of the nonparticipating owner’s share of the reasonable actual costs of drilling and completing the well. The Pooling Statute goes on to state that the risk penalty may be recovered “out of, and only out of, production from the pooled spacing unit .” 3 Similarly, the Compulsory Unitization Statute authorizes a risk penalty on leased working interest owners in the amount of 200% of the nonparticipating owner’s share of the unit expense. The Unitization Statute then provides that the 200% risk penalty can be “recovered out of, and only out of, production from the unit. ” 4 Article 11.8 of the Haystack JOA similarly states that risk penalties shall be satisfied out of proceeds from the sale of Unitized Substances attributable to the affected tract.
to prior NDIC Order No. 32353 (the “Twin City Technical Case”) that had ruled that risk penalties on nonconsent wells can only come out of that specific well’s production. The court also rejected Liberty’s argument that Article 11.8 of the Haystack JOA was an unconstitutional taking under the United States and North Dakota Constitutions. So-called “total regulatory takings” occur when regulations completely deprive an owner of all economically beneficial use of their property. To the contrary, Liberty continued to own its own working interests and be credited with its share of production while the production pays down its penalty balance. Per the court, “[t]his is not a situation where Liberty is not receiving any economic benefit for its interest – rather, this is a situation where Liberty is receiving a different economic benefit than what it would prefer.” 6 Finally, the court deferred to the NDIC order itself, holding that its findings were supported by substantial and credible evidence, and contained fair, reasonable, and equitable provisions. The NDIC’s decision (1) was in the public interest and reasonably necessary to increase ultimate recovery, prevent waste, and protect correlative rights, (2) complied with Chapter 38-08 of the Century Code, and (3) was for the common good. The court also noted that under its deferential standard of review, it “accord[s] greater deference to Industrial Commission findings of fact than we ordinarily accord to other administrative agencies’ findings of fact.” 7
III.
The Supreme Court Takes a Broad View on Recovering Risk Penalties
Neither the Compulsory Pooling Statute nor the Compulsory Unitization Statute specifically address recovering a risk penalty that accrued in a spacing unit that was later made part of a larger unitized area. However, the court found that “unit expense,” as used in the Unitization Statute has a broad meaning, covering “any and all cost and expense in the conduct and management of its affairs or the operations carried on by it.” 5 Thus, the court held that under the Unitization Statute and Article 11.8 of the Haystack JOA, the prior risk penalties can be satisfied out of proceeds from the sale of unit production. An analysis of the Compulsory Pooling Statute leads to a similar result. The statute allows for recovery of a risk penalty on nonconsent wells from production from the pooled spacing unit. The Statute does not state that the risk penalty must be recovered from a specific well. Therefore, under either Statute risk penalties are assessed and recovered at the unit level regardless of whether a non-operator has consented and/or is being carried in one or more wells. The court declined to defer
IV.
Takeaway
This holding allows operators more flexible accounting procedures when it comes to calculating payout thresholds at the DSU or unitized level. It may be particularly useful for situations where a party has consented to some wells and is being
[3] Id. at § 38-08-08(3)(a). [4] Id. at § 38-08-09.4(3)(a). [5] N.D. Cent. Code § 38-08-09.13(4). [6] 11 N.W.3d 851, 858. [7] Id at 861.
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carried or has “gone nonconsent” in others. Note that this case addressed recovering risk penalties allocable to prior DSUs when they have been “dissolved” into a larger, unitized area covering a common source of supply. The court holds that risk penalties can be recovered on unitized (or pooled) lands at the unit level as opposed to the well level, regardless of when the penalties accrued. What is slightly less apparent is the effect this holding may have on overlapping lease line wells and units. Overlapping units occur when two or more prior DSUs are “combined” to allow for drilling in a lease line setback corridor, but the lands are not formally unitized. Overlapping pooling orders typically state that they do not reallocate production for wells producing on the underlying “base” units. The base unit wells remain committed to their base units, and the overlapping units typically contain a single lease line well (or occasionally two stacked lease-line laterals) that is committed to the new overlapping unit. It would thus appear that although risk penalties can be recovered from the collective wells on a DSU, it would be less likely that recovery could be made from a lease line well in an overlapping unit for prior penalties allocable to the base unit wells. This is because the Compulsory Pooling Statute allows recovery only from the actual “pooled spacing unit” of which the wells are a part.
NDIC, affording them even greater deference than they do other administrative agencies. This is generally because courts recognize the high degree of specialized and technical knowledge it takes to regulate oil and gas production.
The Author:
Brad Gibbs Partner and Co-owner, Oliva Gibbs
bgibbs@oglawyers.com 713/229-0360
Brad advises clients on due diligence, complex mineral titles, pooling issues, lease analysis, joint operating agreements, surface use issues, renewables, litigation, and other upstream matters. He earned his J.D. from the University of Houston Law Center and his B.S, cum laude, from Texas State University. He serves on the board of WHAPL and the HBA Energy Law Section. Brad is Board Certified in Oil, Gas, and Mineral Law by the Texas Board of Legal Specialization and has been recognized as a top-rated energy and natural resources lawyer in Houston since 2018. Education • J.D., University of Houston Law Center, University of Houston • B.S., Texas State University Bar Admissions
New Mexico North Dakota Texas
This case also underscores the level of consideration North Dakota courts give to the
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The Kings in the North! – North Dakota Operators Are Kings (For Now) When it Comes to Statutory Interest on Suspended Overrides By: D. Bradley Gibbs, edited by Rohit Raghavan & Brad McCamy
Do North Dakota operators have to pay suspense penalties on all types of late-paid interests? Not according to a recent line of decisions from the North Dakota Federal District Court. These cases interpret the North Dakota Suspense Statute as relieving operators of the obligation to pay statutory interest on suspended overriding royalty interests – and possibly working interests too. This article discusses why operators should proceed with caution when relying on this strict interpretation of the Suspense Statute. However, until the state courts or the legislature weigh in, North Dakota operators arguably wield the kingly power to suspend overrides – and working interests – for any reason or no reason at all!
Although the formalities vary by state, division orders typically include some combination of an effective date, a description of the property where the oil or gas is being produced, the type of production, the fractional or decimal interest claimed by the payee, the type of interest, an authorization to suspend payment in the event of a title dispute, the name and address of the payee, and the valuation and timing of settlements of oil and gas production. The effect of executed division orders also varies by state. In some states, division orders are a prerequisite to receiving revenue payments, 1 and in other states, they are mere nice- to-haves and of limited effect. 2 Most states’ statutory schemes pair a “division order statute” with a “suspense statute” in one or more code sections. A “suspense statute” [1] See, e.g ., Tex. Nat. Res. Code § 91.402(c); N.M. Stat. Ann. § 70-10-5.D; Utah Code § 40-6-9(8)(d). [2] See, e.g ., Mont. Code Ann. § 82-10-110(2) (“A division order does not relieve a lessee of any liabilities or obligations under the terms of the underlying oil or gas lease.”); N.D. Cent. Code § 47-16-39.3 (“Royalty payments may not be withheld because an interest owner has not executed a division order.”).
I. Division Order & Suspense Statutes Generally
The obligation to pay royalties on the sale of production from an oil or gas well generally arises on first production from the well. In many instances, an operator may circulate a document called a division order prior to the distribution of funds. A division order is an instrument executed by the lessor of an oil or gas lease to direct the payment of proceeds from the sale of hydrocarbons.
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allows operators to place funds that have not been timely distributed in a “suspense account” to be held for the rightful distributees. If the late payments are improperly suspended, they will begin to accrue statutory interest. However, this penalty may be excused under a “safe harbor” provision. For example, the funds can often be held in suspense without accruing interest if: (i) there is a legitimate title dispute; (ii) the operator is relying in good-faith on a requirement in a title opinion; or (iii) an owner simply cannot be found with reasonable diligence. In many states, suspense statutes and the right to receive interest on unpaid royalties are held to apply to more than just unleased mineral interests and lease royalty interests. They may cover a combination of royalty interests, nonparticipating royalty interests, unleased mineral interests, overriding royalty interests, and working interests. For example, the suspense statute in New Mexico applies to all persons entitled to the payment of “oil and gas proceeds,” 3 including royalty interests, overriding royalty interests, and working interests. 4 The Texas suspense statute defines a “payee” as “any person or persons legally entitled to payment from the proceeds derived from the sale of oil or gas . . .” 5 This broad definition includes payments to working interest owners, royalty owners, and overriding royalty owners. 6 The Montana statute applies to the payment of “royalties to the royalty owner or the owner’s assignee,” which may include overriding royalties. 7 Despite this “majority” view on the types of interests that fall within the scope of a suspense statute, there is a recent line of federal court decisions in North Dakota that appear to limit statutory interest on suspended funds to mineral royalties only. These decisions are driven by a combination of the unique wording of North Dakota’s suspense statute and strict interpretation by the federal district court.
“The obligation arising under an oil and gas lease to pay oil or gas royalties to the mineral owner or the mineral owner’s assignee . . . is of the essence in the lease contract, and breach of the obligation may constitute grounds for the cancellation of the lease in cases in which it is determined by the court that the equities of the case require cancellation. If the operator under an oil and gas lease fails to pay oil or gas royalties to the mineral owner or the mineral owner’s assignee within [150] days after oil or gas produced under the lease is marketed and cancellation of the lease is not sought or if the operator fails to pay oil or gas royalties to an unleased mineral interest owner within [150] days after oil or gas production is marketed from the unleased mineral interest owner’s mineral interest, the operator thereafter shall pay interest on the unpaid royalties, without the requirement that the mineral owner
[3] N.M. Stat. Ann. § 70-10-3. [4] N.M. Stat. Ann. § 70-10-2.B. [5] Tex. Nat. Res. Code § 91.401(1).
[6] See Concord Oil Co. v. Pennzoil Exploration & Prod. Co. , 966 S.W.2d 451 (Tex. 1998); Stable Energy, L.P. v. Newberry , 999 S.W.2d 538 (Tex. App.—Austin 1999, writ denied). [7] Mont. Code Ann. § 82-10-103(2). We note that there is little case law interpreting the Montana statutes. However, it is possible that the conspicuous use of the phrase “royalties to the royalty owner or the owner’s assignee” instead of North Dakota’s “royalties to the mineral owner or the mineral owner’s assignee” could very well be interpreted to include overrides. Whether statutory interest can be assessed on late payments to non-operated working interest owners in Montana is an open question. [8] We note that the first portion of N.D. Cent. Code § 47-16- 39.1 is sometimes referred to as the “Prompt Pay” provision. We refer herein to the Prompt Pay provision and the “Safe Harbor” provision collectively as the Suspense Statute.
II. North Dakota’s Suspense Statute
North Dakota’s suspense statute is set forth in N .D. C ent . C ode § 47-16-39.1 (hereinafter the “Suspense Statute” 8 ), which provides in relevant part:
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or the mineral owner’s assignee request the payment of interest, at the rate of [18%] per annum until paid . . . (emphasis added) This section does not apply if mineral owners or their assignees elect to take their proportionate share of production in kind, in the event of a dispute of title existing that would affect distribution of royalty payments, or if a mineral owner cannot be located after reasonable inquiry by the operator; however, the operator shall make royalty payments to those mineral owners whose title and ownership interest is not in dispute.”
Court for the District of North Dakota held that the Suspense Statute does not apply to the holders of overriding royalty interests. The court first noted that there is no North Dakota Supreme Court case specifically addressing the application of the Suspense Statute to overriding royalty interests. 11 Defendant Equinor argued that Plaintiff SunBehm, as the holder of an unpaid overriding royalty, was not entitled to 18% interest because it is not a “mineral owner” or a “mineral owner’s assignee.” 12 SunBehm countered that an override is: (i) a type of royalty; and (ii) is effectively a smaller carveout of the mineral estate, such that an overriding royalty owner is technically a “mineral owner’s assignee.” 13 In rejecting SunBehm’s argument, the district court looked to the plain meaning of the Suspense Statute. An overriding royalty interest, it reasoned, is carved out of the net revenue interest under an oil and gas lease, and not directly from the mineral estate. Overriding royalty interest owners thus do not have an ownership interest in the minerals under the ground. Put differently, the right to a landowner’s royalty interest does not rise from the lease but from the ownership of the minerals, while an overriding royalty interest springs from the lease itself. 14 This is – in the court’s view – a critical difference between overriding royalties and other types of royalties, and takes overrides outside the scope of the Suspense Statute. [9] Some commentators state that “as a practical matter, the [lease cancellation portion of the Suspense Statute] may not be that useful. If the company missed a royalty payment, but later acknowledged the fact and paid the royalty plus interest, an equitable situation would then exist and the lease most likely couldn’t be cancelled. However, if the landowner could prove some kind of bad faith on the part of the company, he may have a case for cancellation.” Anderson, Ron, North Dakota Oil & Gas Leasing Considerations, Extension Bulletin 26 (Revised October 2006, available at https://www.dmr.nd.gov/ oilgas/leasingconsiderations.pdf, last retrieved February 24, 2025). [10] 2020 U.S. Dist. LEXIS 73097 (D.N.D. Apr. 27, 2020). [11] Id . at 5.
Note that the North Dakota Suspense Statute creates a heightened obligation to timely pay royalties, as long as there is no legitimate title dispute, and the mineral owners can be found. Failure to pay lease royalties on time can lead to lease cancellation if “equitable.” Only one other state, Montana, takes this approach, which stands in contrast to the majority of states where the payment of royalties is a covenant rather than a condition of lease maintenance. Only in the event that a mineral owner or mineral owner’s assignee does not seek lease cancellation does the remainder of the statute apply. 9 But who exactly falls within the robust protection of the North Dakota Suspense Statute? This is a question that has been posed in the federal district court numerous times in recent years. Of particular interest in the decisions outlined below is the Suspense Statute’s repeated use of the phrase “mineral owner or the mineral owner’s assignee.” What the legislature intended in including this phrase has been hotly contested, and the federal district court has consistently adhered to a narrow reading.
III. Au Revoir to Overrides – SunBehm Gas, Inc. v.Equinor Energy, LP 10
[12] Id . [13] Id . [14] Id . at 9.
In SunBehm Gas , the United States District
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