STCL Energy Newsletter Spring 2022 by South Texas College of Law Houston

ENERGY NEWSLETTER South Texas College of Law Houston

Harry L. Reed Institute of Oil & Gas

Oil & Gas Law Society’s Update Community Involvement, Career Expo, and Energy Students “Courage is knowing what not to fear. Courage is a kind of salvation.” Simple, yet profound, Plato’s words lend guidance to twentyfirst century law students in their pursuit of education. In an environment that is frought with adversity, achieving and maintaining balance is an arduous journey. This is where we eliminate illusions of fear and in turn, grow. At the onset of the pandemic, growth seemed to be a castle in the air. However, the SOUTH TEXAS OIL & GAS LAW SOCIETY quickly acclimated to the remote environment. To remain connected, the Society utilized and grew our social media platforms, hosted virtual events, and stayed up to date on the latest industry trends. Thanks to the support from Director and Professor Christopher Kulander, Dean and President Michael Barry, and the South Texas Energy Alumni Board we have been able to uphold and advance the Society’s mission: provide networking opportunities to students interested in the oil and gas industry. Since the last publication in Spring 2021, the OIL & GAS LAW SOCIETY has seen increased community involvement through both in-person and virtual events. Through invaluable opportunities to attend events hosted by the Institute of Energy Law, the Houston Bar Association Oil, Gas & Mineral Law Section, and the Association of International Energy Negotiators (AIEN), students are able to advance their industry knowledge outside of the classroom. Most notably, the OIL & GAS LAW SOCIETY hosted a CAREER EXPO for South Texas College of Law Houston students in March 2022, bringing students and practitioners together on STCLH’s campus for an exclusive networking opportunity. For the 2022-2023 school year, the Oil & Gas Law Society’s focus will be split between internal and external growth. Internally, the Society will work to develop student leaders into future industry leaders. Externally, the Society will work on its external relations within the energy industry by further developing relationships with stakeholders.

Spring 2022 Edition

Contents •••

Editorial Board •••

Oil &Editor-in-Chief Gas Law Society’s CRISTINA GOULET

Update .................................... 1 Managing Editors

Letter from the Editor............. 2 LAUREN DANIELSON VIKESH Political and PATEL Economic Senior Articles/Note EdiFeasibility of Contracted tors American Liquefied Natural EMMA BECKWITH Gas for Energy Security in H. JETT BLACK Poland and theDAVIS Baltic States — MICHAEL Can the American Government Article/Note Editors Help? ...................................... 3 ALLISON JONES GUNNER WEST Runsheet 101 – Revisited 2021 KENNETH CLARK .............................................. 11 LATRICIA ROUNDS NAHEAAN ISLAM Texas Resiliency: The AfterWILLIE RODRIGUEZ

math of Winterstorm Uri ..... 21 Global Carbon in Emissions: Authors PracticeA Race to Zero ......................... 28 ••• CLARK, JR. The BERNARD Most Important Figure CHRISTOPHER KUYou’ve Never Heard Of: It’s LANDER TimeRANDALL to Readdress the DisK. SADLER countGRANT FactorsARMENTOR Inherent in the Social Cost of Greenhouse Gas Emissions ............................. 34

Student Authors

• • • Interest The Texas Mineral CRISTINA GOULET Pooling Act: An Analysis of its COLIN DAVIS Recent Application in District H. JETT BLACK Eight of the Railroad Commission and the Future Implications of the Commission’s Order ........................................ 41

Letter from the Editor Dear Reader, On behalf of the Editorial Board and the Members of the ENERGY NEWSLETTER, we are pleased to present you Edition 1, Volume 5. The ENERGY NEWSLETTER is a student-run scholarly newsletter committed to bringing to the global energy community timely and unique perspectives in the industry. South Texas College of Law Houston has an extensive student, Energy Alumni association, and general footprint across the world in oil, gas, and all things energy. The ENERGY NEWSLETTER seeks to bring all their perspectives in one place at the center of the global energy community in Houston. This is the fifth volume of our ENERGY NEWSLETTER publication through South Texas College of Law Houston. Having such a center stage in downtown Houston, the newsletter team looks forward to bringing exciting articles authored by students and alumni. We look forward to growing the intellectual prowess of the ENERGY NEWSLETTER and South Texas College of Law Houston. This publication begins with a look at the political and economic feasibility of contracted liquefied natural gas for energy security in the Poland and the Baltic States and a discussion on whether the American government can help. Next, is a discussion regarding how a landman prepares a title runsheet concerning real property interests in Texas. We then turn to look at what Texas has done to prevent a second electricity crisis. Thereafter, is an assessment on global carbon emission reduction. Next, is a discussion on the social cost of greenhouse gas emissions. Finally, the newsletter ends with an analysis of the Texas Mineral Interest Pooling Act, its recent application, and future implications. On behalf of the Editorial Board and the Harry L. Reed Institute of Oil & Gas, we thank the authors who have added their support to this enterprise through their submissions. We would also like to thank South Texas College of Law Houston and all organizations in and surrounding the College for making the ENERGY NEWSLETTER possible. Sincerely,

Cristina Goulet Editor-In-Chief Disclaimer: The opinions expressed in this publication are those of the authors. They do not purport to reflect the opinions or views of South Texas College of Law Houston or the Harry L. Reed Oil & Gas Law Institute, their students, staff, faculty, or associates.

Editorial Board •••

Editor-in-Chief CRISTINA GOULET Managing Editors LAUREN DANIELSON VIKESH PATEL Articles/Note Editors ALLISON JONES EMMA BECKWITH GUNNER WEST H. JETT BLACK KENNETH CLARK LATRICIA ROUNDS MICHAEL DAVIS NAHEAAN ISLAM WILLIE RODRIGUEZ

Authors in Practice ••• CHRISTOPHER KULANDER RANDALL K. SADLER GRANT ARMENTOR

Student Authors ••• COLIN DAVIS CRISTINA GOULET H. JETT BLACK NEIL SEGEL NOLAN WLECZYK

Political and Economic Feasibility of Contracted American Liquefied Natural Gas for Energy Security in Poland and the Baltic States—Can the American Government Help?

Introduction The energy security of Poland and the Baltic states must remain strong to provide political and economic stability to the region. Use of North American-sourced LNG and, possibly, locally derived sources of unconventional natural gas as alternatives to coal and Russian natural gas provides a means of curtailing carbon dioxide emissions, a goal of the EU, while restraining Putin’s Russia. Even without Russian aggression in Ukraine, the Putin regime is a concern to the collective security of the EU, and relations between the two have deteriorated in the last decade. Despite this, the completion and potential activation of the NS2 pipeline appears imminent.

By: Christopher Kulander and Grant Armentor Director of the Oil & Gas Institute and Professor of Law at South Texas College of Law Houston; Associate, Haynes Boone Summary At the heart of the European Union (EU) energy policy is energy security. Energy security is maintained, in part, by diversification of supply. Despite the fact that the EU has prioritized diversification, its dependency on Russian natural gas has increased in recent years. Contemporaneously, the political relationship between the EU and Russia has worsened. Construction of Nord Stream 2 (NS2) will further establish Russia as the dominant supplier of natural gas to the EU while lessening the diversification of its energy supply. To further the EU’s stated goals of energy diversification and security, another steady source of natural gas imports for the countries along the Baltic Sea1 is needed.

Will it be economically viable and politically possible to export steady and significant amounts of North American-sourced LNG into the Baltic region? Under the right circumstance, a restrained and realistic American-led effort could deliver some measure of energy security to its friends bordering Russia. This article provides a response by the U.S. and the countries along the Baltic Sea to Russia’s direct export of natural gas to Germany. First, the need for energy diversification in the EU is discussed. Then, the current status of LNG assets in Poland and the Baltic states are covered. Next, the state of natural gas production in the U.S. is discussed. Finally, the feasibility of expanded long-term exports of North American LNG to countries along the Baltic Sea is considered. Here, domestic political and economic issues arise, such as the private ownership of minerals, the need of private financing, the ability to get construction of American export terminals approved, and a realistic assessment of what American and European governments can (and cannot) do in order to move a larger portion of the LNG trade going across the Atlantic from the spot market to contracted trade.

Liquified Natural Gas (LNG) importation assets in Poland and the Baltic states exist for this purpose. Unlike other EU members, these countries have demonstrated the economic and political will to curb the coercive influence of Russian natural gas imports. America is awash in natural gas, with plenty for export, and can send increasing volumes of LNG worldwide. In contrast to other sources, America is well located to supply Europe with secure LNG and its importation should be a shared goal of the EU and America. Despite the desire of some American statesmen to use the “shale gas revolution” to further U.S. geopolitical goals, the U.S. hydrocarbon industry (unlike in Russia) is overwhelmingly controlled by private landowners and industry. The goal of the American, Polish, and the Baltic states should therefore be narrowly focused on establishing free trade agreements and encouraging longer term contractual relationships between America and Poland and the Baltic states.

Energy Security & Diversification of the European Union Russian natural gas provides Europe with one of its primary sources of energy. Russian natural gas also provides the Putin regime with a tool of resource-based aggression. Again and again over the last two decades, Gazprom (publicly traded but 38.37% owned by the Russian Federation directly 3

and 10.97% by Rosneftegaz, a holding company owned by the Russian state through the Federal Agency for State Property Management)2 appeared to respond to directives from the Russian government by curtailing exports at inopportune times with dubious excuses. These excuses primarily related to Russian designs on Ukrainian territory and conflicts with Naftogaz, Ukraine’s stateowned national oil and gas company.3 Russia has flexed its natural gas muscles elsewhere, including indirectly curtailing exports to Belarus, Slovakia, Romania, and Bulgaria in the depths of winter.

and oil suggests that no realistic immediate alternative to replace the reliance on Russian gas exists.7 All the while, NS2 approaches completion. Once complete, it will, despite anxious words from the European Commission and voracious complaints in the EU Parliament, eventually be placed into service. The pipeline will give Russia, yet another, means to flex its geopolitical muscles. Poland and the Baltic states should have no doubt who will likely get curtailed first in future supply pinches, to say nothing of the threatened curtailments that loom over future political tangles with Russia. This uncertainty must be considered alongside the costs of natural gas when determining the desired source portfolio for imported natural gas.

Despite this history of belligerence, Germany, the largest economy in Europe, is on the cusp of accepting an even larger volume of natural gas directly from northwestern Russia. NS2 is to be a 1,230 kilometer long pipeline running along the bed of the Baltic Sea, taking production from the Yamal Peninsula in Siberia directly to Greifswald, Germany. NS2 has drawn invective from several sources—national governments in Eastern and Northern Europe, the U.S., and the European Parliament. Yet, companies from Germany, England, France, and the Netherlands are participating in the project. The future of NS2 is not certain, but it will likely become operational—construction is more than fifty percent complete and it runs parallel to Nord Stream 1, whose capacity the new pipeline will match. NS2 will significantly increase Russian export capacity and will connect the single largest natural gas market in Europe with one of the largest production regions via a subsea route that crosses the land of no other country.

Fortunately, the Baltic Coast is now dotted with ports wherein imported LNG can be lifted off tankers and re-gasified for pipeline transport inland. Bordering the Baltic Sea, Belorussia, and Russia itself, Lithuania, and Poland lie at the crossroads of natural gas in Northeastern Europe—a position that could be weakened by Russia’s NS2 plans. Poland, for example, concentrating on lowering the volumes of imported Russian natural gas, has paid significantly more for natural gas from Qatar than it might from Gazprom after constructing its LNG regasification terminal in 2015. Poland is partially dependent upon Russia for natural gas imports. In order to diversify its natural gas supply and reduce this reliance, Poland made plans to enhance its energy security. In 2010 construction was launched for Poland’s first LNG importation terminal—the President Lech Kaczyński's LNG Terminal in Świnoujście, on the western edge of Poland’s Baltic coast.8 By October 2015, it was complete, and operations began in April 2016. Polskie Górnictwo Naftowe i Gazownictwo S.A. (PGNiG), through its subsidiary Polskie LNG S.A., developed the terminal. The terminal is operated by Polskie LNG. The project was originally estimated to cost around €400 million but this increased to €950 million, of which €200 million was supplied by the European Bank for Reconstruction and Development and the outstanding €750 million was provided from the sale of Polskie LNG bonds to ten other banks, each valued at seventy-five million euros.1 The LNG terminal includes an unloading jetty and mooring system, two 160,000 cubic meters cryogenic LNG

Opposition to NS2 in Europe is centered in Northern and Eastern Europe and focuses on EU energy policy. Energy security is the core principle, meaning “the uninterrupted availability of energy sources at an affordable price,”4 which could be endangered by a disruption from countries from which the EU imports fuel.5 This desired “security” is brought into reality through “diversification” of sources. In 2017, the Security of Gas Supply Regulation was enacted. Within the regulation, diversification of gas supplies is expressly defined as promotion of increased access to extra-EU LNG.6 The EU’s reliance on Russia to meet approximately 38.5% of its total gas demand and thirty percent of the value of all EU imports of gas 4

storage tanks, and a regasification capacity amounting to five billion cubic meters annually. The terminal also has the ability to send out natural gas through the connected eighty-five kilometerlong pipeline from Świnoujście to Szczecin to the National Transmission System, onto tanker trucks, and into other containers.10

LNG Terminal connecting to the Polish gas transmission grid, Poland can provide an alternative energy supply from previous coal-powered industries, commercial purchasers, and Polish citizens. The terminals provide for the import of natural gas to Poland from anywhere, and create a path for the actual diversification of gas supplies. This permanently changes the natural gas market in Poland and environs, and increases the competitiveness of LNG vis-à-vis piped-in natural gas, particularly from American LNG.16 Between 2016 and 2019, roughly four years after the construction of the LNG terminal, Poland’s LNG imports grew three and a half times over—from ninety-four Mmcf/d in 2016 to 331 Mmcf/d in 2019—accounting for eighteen percent of the country’s total consumption.17 The ability to cover almost twenty percent of demand for natural gas from alternative sources has provided Poland significant independence from Russian influence and will further help to reduce natural gas prices as Poland’s negotiating position over Russia improves.18

Polskie LNG is currently executing a contract to expand the re-gasification facility of the Świnoujście LNG Terminal. In the first phase, additional Submerged Combustion Vaporizer units will be installed, which will increase the annual regasification capacity from five billion cubic meters to 7.5 billion cubic meters.11 The second phase will consist of constructing a third cryogenic storage tank, a second jetty for loading and unloading of LNG carriers, and an LNG-to-Rail transshipment installation for tankers and ISO containers. Furthermore, on June 24, 2020, Polskie LNG signed a deal with a consortium of Porr and TGE Gas Engineering to further expand the LNG terminal to 8.3 billion cubic meters per year by the end of 2023.12 Poland continues to search for new methods to further reduce their reliance on Russian LNG imports and increase its energy security. Piotr Naimski, the Polish secretary of state responsible for energy projects, has stated Poland plans to begin installing a Floating Storage and Regasification Unit (FSRU) located in the Bay of Gdansk.13 The FSRU will add a storage capacity of four billion cubic meters of LNG per year to supplement the current storage expansion of Świnoujście LNG Terminal.

Concerned about the high cost of Russian natural gas and facing the loss of its own primary source of electricity—the Ignalina nuclear power plant—Lithuania made its own plans for LNG imports. Lithuania constructed an LNG importation terminal, the Lithuanian Natural Gas Terminal, which opened in early 2016. The Lithuanian project was funded through a loan of eighty-seven million euros through the European Investment Bank. Höegh LNG, a Norwegian company, constructed the FSRU Independence in South Korea to be used as an LNG import terminal in Klaipeda Harbor. It has an annual capacity of between two to three billion cubic meters of natural gas. In addition, the Klaipedos Nafta AB (Lithuania’s statecontrolled energy company) hired PPS Pipeline Systems to connect the terminal to Lithuania’s natural gas grid. The link to shore is a twenty-kilometer pipeline, completed in 2014. All this effort shows the seriousness with which Lithuania considers its energy security. Lithuania accepted its first LNG spot shipment from America at Klaipeda on August 18, 2017, with final client destinations being in Estonia and Latvia, as well as Lithuania.19 By the middle of 2020, five cargos from the U.S. had arrived, and LNG imported from the U.S. accounts for more than six percent of the total

In the mid-twentieth century, natural gas only represented a small percentage of energy sources consumed in Poland as coal was favored.14 With the expansion of natural gas transportation to a range of consumers, however, the demand for gas consumption has grown and even accelerated. According to the U.S. Energy Information Administration, Polish natural gas consumption has increased over thirty percent during the past ten years—from 1.4 Bcf/d in 2010 to 1.8 Bcf/d in 2019. In 2010, around ninety percent of the gas imported was supplied by Russia. By 2019, in part due to the construction of the Świnoujście LNG Terminal, Russian imports declined to sixty percent, overall accounting for forty-eight percent of total gas consumption.15 With the Świnoujście 5

amount of LNG arriving at the Klaipeda LNG terminal thus far.20

The U.S. has strong economic reasons to support LNG sales contracts to Europe. Since significant U.S. domestic oversupply—currently made worse by COVID-19 issues—curtails any near-future price hikes, LNG exports offer a far better option over domestic use to increase demand for gas. By the end of 2018, U.S. LNG exporting capacity passed six billion cubic feet, up from no capacity outside of distant Alaska at the end of 2015, enough natural gas to provide electricity to all the homes in California, Texas, and Florida. The continued expansion of this exporting capacity provides the best way to bleed off the current overabundance of domestic natural gas and lift the fortunes of domestic shale producers.25 For Europe, alternatives to American LNG are more politically unstable (e.g. Nigeria), more distant and closer to the Southeast Asia demand sink (e.g. Australia), or in unstable regions (e.g. Qatar). The primary competition is, as always, Russian natural gas.

Finland and Estonia recently completed the Balticconnector, a 152 kilometer-long bi-directional pipeline between their countries that will also connect to the pipeline grid of Latvia. Completion of this pipeline will enable a planned LNG lifting terminal to serve all three countries with natural gas derived from imported LNG.21 American Production and Exportation The U.S. is almost unique in that the surface owner may also own the mineral estate (or an exclusive license to develop the same), unlike most other countries where the national government or its state-owned corporate interests own and direct development of minerals.22 While private ownership has its drawbacks—fractionalized ownership among cotenants and problems of overproduction caused when conservation practices are ignored—the history of production in America shows that development is tied to commodity prices and only secondarily to government control. Further, recovery of slowed American production triggered by a trough in prices occurs very quickly when prices later rebound, as OPEC learned to its woe after it relented on its late 2014 decision to depress oil prices with increased production in the hope of strangling America’s burgeoning shale gas development.23

The LNG transportation business relies on longer-term contracts designed to guarantee the income stream necessary to finance the very expensive liquefaction, gasification, and transportation assets, while simultaneously providing investors and lenders with a relatively predictable return.26 Such long-term agreements link all the parties involved in the transportation chain: (1) the consuming importers; (2) the terminal facilities and shippers; and (3) the financiers that make it all possible.27 LNG projects generally employ multiple lenders. Liquefaction projects must be designed so that they include both pipelines to the export trains and long-term lifting contracts with buyers’ worthy of credit.28

Modern directional drilling and fracturing practices, access to capital and pipeline space, and private ownership of minerals means that America is inundated with natural gas. Estimates suggest that the U.S. has almost 1,750 Tcf (trillion cubic feet) of technically recoverable natural gas, including 200 Tcf of proved reserves (the discovered, economically recoverable fraction of the original gas in place). Technically recoverable unconventional gas—a category that includes gas derived from shale and “tight sandstone” formations as well as coalbed methane (“CBM”)—accounts for approximately sixty percent of the onshore recoverable resource. At 2007 production rates, about 19.3 Tcf, the current recoverable resource is sufficient to supply the U.S. for the next ninety years. Separate estimates of the shale gas resource extend this supply to 116 years.24

The last ten years have brought optimistic forecasts by politicians from both major American political parties prognosticating that the “shale gas revolution” would give American diplomats a new tool with which to leverage geopolitical power. The nature of private ownership of minerals, combined with private exploration, development, transportation, and refining of oil and gas in the U.S., all financed with private lending, however, means that the investment determinations of thousands of companies, primarily based on economic forecasts, lifting costs, and transportation models, sideline diplomatic puffery. The basis for investment decisions is based on a variety of factors such 6

as price forecasts, estimates of reserves, production costs, availability of transport, the terms of production sales contracts, and the volume of competing domestic demand. Thus, while private ownership of minerals and private sources of financing ensure that oil and gas are developing, they also ensure that economic factors—instead of geopolitical—dominate the decision to develop and export hydrocarbons. Claims that American production and export of hydrocarbons could harness in the service of broad but unfocused regional diplomatic ends that are unrealistic and steadily promoted are imprudent.29

Moving to the proactive, establishing Free Trade Agreements (FTAs) with Poland and the Baltic states are needed. While the current American administration has not looked favorably upon some current FTAs such as NAFTA, it was open to superseding it with the United States–Mexico– Canada Agreement (USMCA). The USMCA suggests openness to other FTAs, provided that the flow of trade is at least initially favorable to the U.S.32 The U.S. Department of Energy (DoE) through the Federal Energy Regulatory Commission (FERC) requires permits for the construction of LNG exporting facilities. The DoE’s Office of Fossil Energy then requires Fossil Energy permits for the export of LNG to most countries. As provided in Section 3 of the Natural Gas Act, anybody wishing to export LNG from America to a country without an FTA needs authorization from the Secretary of Energy. The Secretary shall then determine if the proposed LNG export is consistent “with the public interest”—a decision point subject to political whim. If found so, the DoE then issues a conditional authorization. This authorization may be affected by subsequent applications, as the DoE will continually scrutinize the cumulative effect of all approved exports on the American natural gas market. The potential impact from changing the permit could have on projects after construction concerns project lenders.33 Establishment of FTAs with Poland and the Baltic states that prevent these permitting concerns would help facilitate future LNG trade.

In contrast, Russia, with its government ownership of minerals, its mercurial control of taxes on exported gas, and its political influence on its domestic oil and gas companies, can easily manipulate the price of Russian gas. Moreover, even though Gazprom is publicly owned, the pressure the Putin regime can exert means that Gazprom sometimes acts with motives other than economic ones. In addition, while oil production and exportation in Russia are more tied to economic forces as the primary product of the Russian hydrocarbon industry, natural gas sits on the margin—a toy to be manipulated, not a GDP staple dependent on market forces.30 Obviously, Russia has geographic advantages as well, being both far closer to the EU and possessing outlets to the Baltic and Black Seas. NS2’s purpose is to accentuate this inherent benefit by bringing natural gas directly to industrial consumers and utilities in the most heavily populated portion of Europe located within its biggest and richest country.

A secondary goal of the U.S. and Polish/Baltic governments might be to fund studies inquiring about the feasibility of developing locally derived sources of natural gas from shale formations found in Poland, Lithuania, and their neighbors located along the northern Carpathian shale belt. Prior tentative exploration has not been overly promising.34 However, continued cooperation between the U.S. Geological Survey, its local counterparts, and the industry might prime future development and provide some measure of geopolitical leverage to the U.S. government, the Polish/Baltic governments, and their respective regulated industries involved with natural gas import and distribution.

Passive and Active Steps The first tenant of any American government desiring to support LNG exports to Europe should be to do no harm. This means not holding up federal approvals of LNG exportation terminals, as well as not actively hindering the completion and operation of pipelines. Although America’s increasingly activist judicial branch has proven more than capable of holding up the development of pipelines,31 the executive branch should not pressure agencies to hinder domestic infrastructure projects or international trade. 7

Past that, more focused proactive steps avail themselves. The U.S. can structure American LNG projects in any number of ways, and this inherent flexibility means that American exporters have a good chance of becoming a swing supplier. For example, unlike other countries, U.S. LNG tolling agreements generally do not have fixed destination clauses, allowing U.S.-sourced LNG cargoes to participate more freely in spot markets.35 In addition, because American LNG export projects take years to go from planning to activation, they are not competing with current liquefied natural gas supplies, but for the gap that will exist in the future for new demand around the world. The responsiveness of the U.S. market and the idea that future demand in Europe exists at the right price bodes well for lasting LNG exports across the Atlantic.

Conclusion All the pieces are coming together in the countries bordering Russia for LNG imports and natural gas distribution among themselves. These expansion programs have been in response to increased domestic demand and will provide a means of reducing the Baltic littoral’s reliance on Russian natural gas. The question is if—or under what conditions—when will contracted American LNG, and perhaps native European shale gas, step-up to help provide energy security to the Baltic region? The first steps are complete, with limited volumes of American LNG landing on a contract basis in Poland in the last couple of years36 and more planned for later.37 The international energy market is dependent on prices and politics. Although it is almost impossible to predict the individual events that affect energy prices, North American LNG should flow to Europe in increasing quantities for the foreseeable future.

In the Baltic states and Poland, filling that future gap with American LNG, which can resell without penalty away from shore, should actively encourage the respective governments to encourage long-term purchase and sale contracts. However, they should recognize that companies in the LNG trade primarily respond to price and not entreaties or fiats of governments. Therefore, direct federal backing’s limited goal should be to alleviate price concerns to push long-term contracts into reality. When new demand is forecast in Poland and the Baltic states, and the marginal cost of meeting that new demand is within a reasonable measure of the cost to fill that same demand with Russian gas, the American government, with the assistance of the importing country, could disperse a hedging subsidy. This subsidy would entice the importer and exporter to execute a certain desired length purchase and sale agreement. To be sure, recognizing economic realities is crucial. Therefore, the success of enticements to contract may hinge on keeping subsidies small and relatively unheralded. 1

This article was first printed in the Bialystok (Poland) Legal Studies Journal [-] The authors thank Byron Kulander and Ben Semmes for their assistance with this project. This article is dedicated to the memory of Anna Mary Sullivan, Sep. 9, 1920—Dec. 19, 2019. © 2020 Christopher Stewart Kulander. All rights reserved.

Lithuania, Latvia, and Estonia.

* Director and Professor, Harry L. Reed Oil & Gas Law Institute, South Texas College of Law Houston, B.S. (Geology) and M.S. (Geophysics), Wright State University; Ph.D., Texas A&M University (Geophysics—Petroleum Seismology); J.D., University of Oklahoma College of Law. ⸷ J.D. Candidate, 2021, South Texas College of Law—Houston.

** This article is reprinted from CHRISTOPHER KULANDER, Political and Economic Feasibility of Contracted American

Andrius Sytas, Lithuania Receives First LNG from the United States, REUTERS (Aug. 21, 2017, 6:56 AM), https://www.reuters.com/article/us-lithuania-lng/lithuaniareceives-first-lng-from-the-unitedstatesidUSKCN1B11BW. 20 Lydia Woellwarth, Lithuanian LNG Terminal Proving to be a Player in the Global Market, LNG INDUS. (May 26, 2020, 1:00 PM), https://www.lngindustry.com/liquid-natural-gas/26052020/lithuanian-lng-terminal-proving-to-be-aplayer-in-the-global-market/. 21 Balticconnector Gas Pipeline Up and Running Since 1 January 2020, EUR. COMM’N (Jan. 8, 2020), https://ec.europa.eu/info/news/balticconnector-gas-pipeline-ready-use1-january-2020-2020-jan-08_en. 22 EUGENE KUNTZ ET AL., A TREATISE ON THE LAW OF OIL & GAS 59 (Anderson Publishing Co., 2019). 23 See Bernard F. Clark, Jr., Oil Capital: The History of American Oil, Wildcatters, Independents and Their Bankers, 2 OIL & GAS, NAT. RES. & ENERGY J. 23, 72–85 (2016) (describing the attempt by OPEC to stymie burgeoning American shale development by lowering prices in late 2014, only to see the American producers almost immediately rebound when OPEC relented approximately two years later). 24 JOHN S. LOWE ET AL., CASES AND MATERIALS ON OIL AND GAS LAW 20 (West Academic, 7th ed. 2018). 25 Scott DiSavino, After Six Decades, U.S. Set to Turn Natgas Exporter Amid LNG Boom, REUTERS (Mar. 29, 2017, 12:08 AM), http://www.reuters.com/article/us-usanatgas-lng-analysis/after-six-decades-u-s-set-to-turn-natgasexporter-amid-lng-boom-idUSKBN1700F1. 26 Mark Tay & Aaron Sheldrick, UPDATE 2-LNG Supply Gap May Form as Investment Drop Stymies Projects, REUTERS (Apr. 4, 2017, 2:32 AM), http://in.reuters.com/article/japan-gastech-lng/update-2-lng-supply-gap-may-formas-investment-drop-stymies-projects-idINL3N1HC1B4. 27 See Bernard F. Clark, Jr., Oil Capital: The History of American Oil, Wildcatters, Independents and Their Bankers, 2 OIL & GAS, NAT. RES. & ENERGY J. 23 (2016), for a discussion of the past and present of financing oil and gas transactions from exploration to transportation to distribution. 28 See Brad Richards, New Transport Options for Liquefied Gas, ENERGY WORLD, Dec. 6, 2016, at 20–21. 29 See generally TIM BOERSMA & COREY JOHNSON, U.S. ENERGY DIPLOMACY, (Colum. Univ. Center on Global Energy Pol’y eds. 2018), available at https://energypolicy.columbia.edu/sites/default/files/pictures/CGEPUSEnergyDiplomacy218.pdf. 30 Interview with Ben Semmes, LNG Trading Analyst (Jun. 15, 2020); see Russia’s Natural Resources Valued at 60% of GDP, THE MOSCOW TIMES (Mar. 14, 2019), https://www.themoscowtimes.com/2019/03/14/russias-natural-resources-valued-at-60-of-gdp-a64800; see also Dumitru Dediu et al., How Did the European Natural Gas Market Evolve in 2018?, MCKINSEY & CO. BLOG (Apr. 15, 2019), https://www.mckinsey.com/industries/oil-andgas/our-insights/petroleum-blog/how-did-the-european-natural-gas-market-evolve-in-2018.

Liquified Natural Gas for Energy Security in Poland and the Baltic States – Can the American Government help?, 25 BIALSTOCKIE STUDIA PRAWNICZE 55 (2020). 2 Equity Capital Structure, GAZPROM, https://www.gazprom.com/investors/stock/structure/ (last visited Aug. 19, 2020). 3 Tim Boersma & Jonathan Elkind, Talking Past Each Other: Transatlantic Perspectives on European Gas Security, COLUM. UNIV. SCH. INT’L & PUB. AFF. (May 18, 2018), https://www.energypolicy.columbia.edu/research/commentary/talking-past-each-other-transatlanticperspectives-european-gas-security. 4 Energy Security: Ensuring the Uninterrupted Availability of Energy Sources at an Affordable Price, INT’L ENERGY AGENCY, https://www.iea.org/areas-of-work/ensuring-energy-security. 5 See generally Energy Security, EUR. COMM’N, https://ec.europa.eu/energy/topics/energy-security_en. 6 See generally Anette Danielsson, European Debate on Nord Stream 2: Framing of the Gas Pipeline Project in IntraEU Debate in the Context of Deteriorated EU-Russia Relations from 2012 to 2018, (May 2019) (M.A. thesis, University of Helsinki) (on file with Helsinki University Library) (providing an excellent compendium of topics related to NS2 and the related political battles within the EU). 7 Id. para. § 2.2. 8 LNG Terminal in Świnoujście, GAZ SYS., https://en.polskielng.pl/lng-terminal/lng-terminal-in-swinoujscie/ (last visited May 4, 2022). 9 Świnoujście LNG Gas Terminal, Baltic Coast, Poland, HYDROCARBONS TECH., https://www.hydrocarbons-technology.com/projects/swinoujscie/ (last visited May 4, 2022). 10 Gaz-System Will Expand the LNG Terminal in Świnoujście, GAZ SYS. (Apr. 4, 2017), https://en.gaz-system.pl/centrum-prasowe/aktualnosci/informacja/artykul/202479/. 11 LNG Terminal Expansion Program, GAZ SYS., https://terminallng.gaz-system.pl/en/lng-terminal/lng-terminal-expansion-program/ (last visited May 4, 2022). 12 Agnieszka Barteczko, Poland Signs Deals to Expand its LNG Terminal, REUTERS (June 24, 2020, 6:12 AM), https://www.reuters.com/article/poland-energy-lngidUSL8N2E12PB. 13 Parvez Jabri, Poland Plans Floating Terminal to Boost LNG Imports, BUS. RECORDER (May 2, 2019), https://www.brecorder.com/news/494139/. 14 See generally Ewelina Chlopińska & Maciej Gucma, The Impact of a Liquified Natural Gas Terminal on the Gas Distribution and Bunkering Network in Poland, 53 SCI. J. MAR. U. SZCZECIN 154, 155 (2018). 15 Natural Gas Weekly Update: Poland Seeks to Diversify Natural Gas Imports, U.S. ENERGY INFO. ADMIN. (May 21, 2020), https://www.eia.gov/naturalgas/weekly/archivenew_ngwu/2020/05_21/#jm-trends. 16 LNG Terminal, GAZ SYS., https://en.gaz-system.pl/en/lng-terminal/ (last visited May 4, 2022). 17 Natural Gas Weekly Update, supra note 14. 18 See Chlopinska & Gucma, supra note 13, at 159–60.

2015), https://lnghub.biz/lng-tolling-agreements-exportkey-considerations/. 36 See, e.g., Agnieszka Barteczko, Poland’s PGNiG Receives LNG Delivery from U.S., REUTERS (Apr. 28, 2020, 9:30 AM), https://www.reuters.com/article/health-coronavirus-poland-pgnig/polands-pgnig-receives-lng-deliveryfrom-u-s-idUSL5N2CG6QW. 37 See, e.g., Timothy Gardner, Poland’s PGNiG to Buy More LNG from U.S. Company Venture Global, REUTERS (June 12, 2019, 9:54 AM), https://www.reuters.com/article/usa-poland-lng/polands-pgnig-to-buy-more-lng-from-us-company-venture-global-idUSL2N23J0MZ.

See Patrice Douglas, INSIGHT: DAPL Ruling Accomplishes What It Should Have Prevented, BLOOMBERG L. (Aug. 4, 2020, 3:00 AM), https://news.bloomberglaw.com/environment-and-energy/insight-dapl-ruling-accomplishes-what-it-should-have-prevented. 32 Leon Teeboom, Negative Effects of Free Trade, HOUS. CHRON.: SMALL BUS. (Feb. 12, 2019), https://smallbusiness.chron.com/negative-effects-trade-5221.html. 33 Richards, supra note 27, at 20–21. 34 Poland Overview, U.S. ENERGY INFO. ADMIN., https://www.eia.gov/international/analysis/country/POL (last updated July 2020). 35 See generally Kathryn Marietta, LNG Tolling Agreements (Export) – Key Considerations, LNG & GAS HUB (May 8,

RUNSHEET 101 – REVISITED 2021*

approving the title for its exploration and production purposes.

By: Randall K. Sadler Managing Partner, Sadler Law Group PLLC

I. Runsheet Preparation A “Runsheet,” as the term is commonly used today in the oil and gas exploration industry, is— in its simplest form—a chronological list of all recorded instruments and proceedings, of whatever kind and character, which affect an estate or ownership in the subject land that is within the record chain of title. The goal of the Runsheet is to identify every recorded instrument affecting the subject land and then to communicate such information to the client and the examining attorney. Traditionally, following the characteristics of an abstract of title prepared by an abstractor located in the county where the land is located, the Runsheet should cover the period of time from sovereignty of the soil to the most current date obtainable in the present. A Runsheet containing the “record chain of title” is prepared from the Official Public Records of the county where the subject land is located. Texas courts have held that a“chain of title” refers to the documents that show the successive ownership history of a tract of land commencing with the severance of title from the sovereign to and including the conveyance to the present holder.

Preamble This paper was originally presented on February 18, 2006, to the San Antonio Association of Professional Landmen at their Annual Mid-Winter Seminar. In the recent weeks, it was suggested that an update to the paper would be welcomed, particularly in light of the changes in law and technology in the past fifteen years. During that period, numerous technological advances have occurred, most notably the digitization of records, remote access to county records online from the County Clerk’s websites, and third-party county records websites. As a result of such changes, the aggregation of documents has become more efficient and expedient. However, the fundamental methods and manner of preparing a “title runsheet” has not changed substantially, although the aggregation of the information is now mostly prepared in a digital world. This paper presents the relevant material from the 2006 paper along with the addition of the adaptations presented by technological advances and changes in the law.

When a landman is assigned the task of preparing a Runsheet they may be given an extensive package of materials, including: the lease purchase reports, a mineral take-off or mineral ownership report used for leasing the land, copies of the oil and gas leases, plats, and other related information the client may have in its possession. However, there may be times when a landman will only receive a copy of the current oil and gas lease and a plat. This paper has been prepared on the assumption of the latter.

The purpose of this paper is to discuss how a landman prepares a title “Runsheet” concerning interests in real property in Texas. A landman will pull data from the records of an abstract company, if available, from the Official Public Records of the County Clerk, and the Minutes of the District Clerk, collectively “Public Records,” in the county where the land covered by an Runsheet (“subject land”) is located. This paper provides a practical hands-on description of the necessary steps to follow to prepare a Runsheet. The first part of this paper is addressed to lesser experienced landmen, who are now assigned the task of preparing a Runsheet for use by an attorney in the preparation of a title opinion. The latter part of this paper will contain a discussion on “risk management,” as applied to the content of Runsheets, which is included in this paper for company management charged with the task of

A. TOOLS. The preparation of Runsheets has not changed much in the last forty years, with the exception of the dramatic abundance of digital data and the assistance of computers for the actual drafting and presenting the Runsheet. However, despite technological advances, the necessary skills and knowledge to prepare a Runsheet has remained unchanged. To prepare a Runsheet, a 11

landman may use all or some of the following tools: ● ● ● ● ● ● ● ● ● ● ●

the abstract to the most current date in the public records. C. ABSTRACT OR TITLE COMPANY. Where available, the records of the abstract company or title company in the county where the work is to be completed should be used covering the period from sovereignty of the soil to and including the most current recorded date. Nowadays, many abstract companies have converted to title companies that may allow a landman to use the old survey books or survey cards as a beginning point of the collection of information for the Runsheet. The records are set up by survey or the abstract number and, therefore, quickly limit the scope of the review necessary to prepare a Runsheet.

computer or laptop; cellphone; other camera device; platting software; runsheet software; spreadsheet software; word processing software; records index checklist; Runsheet form; plats; and internet access.

The tools used will be dependent, in part, on the landman’s computing skills and equipment, the County Clerk’s disposition and rules, how many other landmen who are crowded into the same records vault, and/or whether the preparation of the Runsheet is to be attempted only by accessing remotely the available public records or third-party online records.

The records of the abstract company will be used to develop a preliminary Runsheet, which will be completed later by a review of the Official Public Records. The preliminary Runsheet should be prepared using all or some of the following steps: 1. Determine the current date of the abstract company’s records, particularly in relation to the current date of the records, in the County Clerk’s office and District Clerk’s office.

B. USE OF ABSTRACTS. Prior to a courthouse review, a landman will determine whether any abstracts of title are available for review. An abstract of title is a collection of all recorded instruments affecting the title to a tract of land prepared by an abstractor who certified the same as to the land covered, the records, and time period covered. Historically, mineral owners and/or lessors received copies of abstracts of title from the oil companies when they had completed their examination or the landowner acquired them as a part of their acquisition of the subject land. If an abstract of title exists and is available, if possible, borrow it and forward a copy to the title attorney. If an abstract is not available to borrow, then obtain the owner’s permission to review the abstract in the most reasonable manner possible. At that point, copy it, scan it, or hand copy the index of the documents contained, including the abstract number, the description of the land covered, and the beginning and closing date of the abstract. If an abstract is obtained and authorization is given to rely on the abstract, then the Runsheet will cover the period of time from the closing date of

2. Examine all cards or books as to the particular survey in which the property is located. 3. Ensure that all instruments affecting title to the property are listed on the Runsheet and include the following: name of parties, date of instruments, date of the recording of instruments, recording data, number of acres included in conveyance, and any relevant remarks regarding mineral reservations or conveyances, or other related documents included in the Runsheet. 4. Verify that other instruments are listed on the Runsheet, including but not limited to: deeds of trust, abstracts of judgments, probate matters, and district court matters. 5. In addition to the survey book or survey cards in the abstract or title company office, a 12

check should be made with the local abstractor as to whether there is a name card file in the abstract company. If there is a name card file in the abstract company, check each name listed in the preliminary Runsheet with regard to the record title owners of the property. Names of parties in oil and gas leases, or other extraneous instruments, will not need to be checked. The name card files will reveal probate proceedings and affidavit type instruments, some of which may be difficult to locate in the Official Public Records.

recorded, but such term shall not include Financing Statement Records. c. “Lien Records” refers to State Tax Lien Records, Federal Tax Lien Records, Abstract of Judgment Records, Lis Pendens, or similar records by which liens are statutorily granted or obtained by recordation of an instrument (and may include Mechanics and Materialmans Lien Records). d. “Probate Records” refers to the original court files and the files as transcribed and maintained, which are generally maintained by volume and page, in the office of the County Clerk relating to the probate or administration of the estate of a decedent.

D. REVIEW OF OFFICIAL PUBLIC RECORDS. Once the preliminary Runsheet has been prepared by the abstract company, a landman must review the necessary instruments in the Official Public Records of the County Clerk and District Clerk to confirm that the Runsheet covers the subject land and that all instruments relating to the subject land have been included. This review should be made from the Indices, both Direct and Reverse, of the “Official Public Records of Real Property” of the county in which the land is located, which may include, by way of example, Deed Records, Oil and Gas Lease Records, Deed of Trust Records, State and Federal Tax Lien Records, Lis Pendens Records, Abstract of Judgment Records, Mechanics and Materialman’s Lien Records, Financing Statement Records, Probate Records, and District Court Records, both those maintained by hard copy in books or volumes and those maintained in digital form, to determine the record chain of title to the subject land.

e. “District Court Records” refers to the original court files and the Minutes of the District Court, whether one or more, which are generally maintained by volume and page, and shall include for the purposes of this paper, the Lis Pendens Records maintained in the office of the County Clerk. 1. Check with the County Clerk to determine that all Deed Records, Deed of Trust Records, State and Federal Tax Lien Records, Lis Pendens Records, Lien Records, and Probate Records were examined during the records search, and likewise, check with the District Clerk regarding District Court Records. Many counties have used different names for different records throughout the history of the respective county, such as: Real Records, Real Property Records, Official Records, Oil and Gas Records, Oil and Gas Lease Records, Mortgage Records, or any derivation of any such records. It is important to correctly identify the proper name of the record in which the instrument is filed in the Runsheet, as such reference is the proper reference for the title opinion.

As used in later sections of this paper: a. “Deed Records” refers to Deed Records, Real Property Records, Official Public Records, or similar named records in which conveyances of any interest in the subject land, or other instruments relating to the ownership of the subject land, such as affidavits, may be recorded.

2. All discrepancies in the descriptions should be noted in the Runsheet. 3. All discrepancies in the Official Public Records should be noted in the Runsheet. As to the dates and periods of time covered, determine the closing date of all Records in the Indices and the Daily Register from the County Clerk. Should any Index not cover both Direct and Reverse,

b. “Deed of Trust Records” refers to Deed of Trust Records, Mortgage Records, Mechanics and Materialmans Lien Records, or similar named records in which the instruments creating real property liens by agreement of the parties are 13

date each grantor acquired the property forward to the date of filing for record of the instrument that transfers the entire interest in the property to a grantee, and then the records for all names in the chain of title should be searched forward to the closing date of the Runsheet to locate competing instruments. The date of the conveyance itself, not the date of filing for record, controls whether an instrument is in the chain of title.

note the same in the Runsheet. If there are any unusual Records which have been examined note the same in the Runsheet. E. COURTHOUSE RECORDS REVIEW. The following procedures generally outline the steps necessary to proceed with the preparation of the Runsheet. All records are organized somewhat differently and it will be helpful to use a commonsense approach to the methods and procedures utilized. The following procedures apply whether an abstract has been reviewed or the records of an abstract company have been reviewed. The only difference will be the periods of time reviewed at the courthouse.

4. In a “pure notice statute” state, there are three types of notice: constructive notice, actual notice, and implied notice. The County Clerk’s records provide constructive notice to all persons of the instrument’s existence. Actual notice is the information within the knowledge of the landman, examining attorney, or client. Inquiry notice is derived from facts that would prompt a reasonable person to inquire about the possible existence of an interest in property. Ultimately, the Runsheet should attempt to provide all three types of notice.

1. A chain of title is “run” and established for a period of time, whether it be from sovereignty of the soil, or some later date, to the most current date present. The chain of title includes the name of all the owners of any interest in the subject land in chronological order for the period of time in which they own an interest in the land, which in its simplest form is a “flowchart.” The chain of title reflects the passage of title to the subject land from one owner to the next. Because Texas maintains only official grantor and grantee indices, a landman should search under the name of each grantor from the date the grantor acquired the subject land forward to the date of filing for record the instrument that transfers all of the interest of the grantor in the subject land to a grantee.

5. To establish a chain of title, a landman will begin with a copy of the oil and gas lease(s) pertaining to the land covered by the Runsheet. Most leases set forth a short description of the subject land, which typically refers to the specific volume and page in the Deed Records where an instrument containing a metes and bounds description can be found. This reference instrument is usually the instrument by which the lessor acquired title to the subject land. Once this instrument is located, record the pertinent information as a beginning point. This method for establishing a chain of title is useful for each instrument in the chain of title which refers to an earlier instrument.

2. A flowchart is a diagram of the transactions revealed by the abstract or records review, containing the names of the grantors and grantees, the date of instrument, its nature, recording reference (book/volume and page), and what it purports to cover. The flowchart facilitates the recognition of ownership of the various estates and interests in the subject land; it is a visual roadmap of the chain of title.

6. If a copy of the oil and gas lease, or other instrument in the chain of title, does not refer to an earlier instrument, then the landman will have to use the Grantee or Reverse Index to Deed Records. Begin with the date of the lease or the date of the last instrument that has been found, and run (examine) the grantee index back in time against the subject person until the instrument by which the subject owner acquired title to the subject land is located. Continue with this or the above method until a complete chain of title from the present owner back to sovereignty has been

3. The recording statutes in Texas are called “pure notice statutes.” Not all states have pure notice statutes, some have “pure race statutes” or “race-notice statutes.” Texas statutes are not dependent on when an instrument is filed; therefore, once a name is encountered in the chain of title, the name should be run in the indices from the 14

established, and then reverse the process using the Grantor or Direct Index starting with the sovereignty of the soil to the present. It is worth noting that many instruments contain recitals to earlier instruments in the chain of title which will make the search much easier.

and reverse several times to establish the early title. F. CHECKLIST OF RESEARCH. Once a complete chain of title for the subject land has been established, a landman should search each of the indices set forth below against all owners of the subject land, to wit:

7. In using the above methods to establish a chain of title from the present owner back to sovereignty, a landman will sometimes be unable to find a recorded conveyance of the subject land from the proceeding owner. In such case, it may be necessary resort to one or more of the following methods:

1. Grantor Index to Deed Records against all owners of the subject land in order to determine whether they have transferred the same land or any interest therein twice, or whether there are any competing instruments. 2. Grantee Index to Deed Records against all owners of the subject land in order to find any other instruments affecting the subject land.

(a) Search the Index to Probate Records against all persons with the same surname to determine whether the subject owner acquired the subject land by devise.

3. Index to Probate Records, where necessary, to determine ownership of the subject land.

(b) Search the Grantee Index to Deed Records against all persons with the same surname for conveyances, heirship affidavits or other instruments which would indicate that the subject owner acquired the subject land by inheritance.

4. Index to the District Court Records against all owners of the subject land in order to determine whether any civil suits affect the subject land.

(c) In the case where the owner is a woman, a search of the Index to Marriage Records may determine whether her name has changed.

5. Grantor Index to Deed of Trust Records against all owners of the subject land to determine whether any mortgages affect the subject land.

(d) Search the Index to the District Court Records to determine whether the owner acquired title through some legal proceeding.

6. Indices to the Lien Records, if other than Items 7-10 below, against all owners of the subject land to determine whether any liens affect the subject land.

8. If all of the above methods fail, the landman should attempt to establish a chain of title from the sovereignty of the soil down to the last owner of the subject land that is of record. Search the Grantee Index to Deed Records against the name of the original patentee to find the patent or grant from the sovereign. This search should begin with the earliest index and continue forward in time until the patent is found, if it is recorded. It is not uncommon to find a patent recorded for the first time as late as one hundred years after the date of the patent. Once the patent is found, begin with the date of the patent, and search the Grantor Index to Deed Records against the name of the original patentee and all successive owners until the chain of title is established. This may require the use of the Grantor/Grantee index going forward

7. Index to Lis Pendens Records against all owners of the subject land to determine whether any legal actions are pending against the subject land. 8. Index to Abstract of Judgment Records against all owners of the subject land for at least the ten year period preceding the present date to determine whether there are any judgment liens affecting the subject land. 9. Index to Federal Tax Lien Records against all owners of the subject land for at least the twenty year period preceding the present date to determine whether there are any Federal tax liens or abstracts of judgment affecting the subject land. 15

10. Index to State Tax Lien Records against all owners of the subject land for at least the twenty year period preceding the present date to determine whether there are any state tax liens affecting the subject land. A search should be made of the child support lien records, if available in the County Clerk’s records.

(d) Date of instrument (e) Date instrument filed for record (f) Recording information (g) Acreage (h) Remarks B. After completing the necessary steps in preparing the Runsheet, regardless of the method used to record the individual instruments or proceedings, the instruments and proceedings need to be arranged in chronological order by the date or the effective date of the instrument and the information relating to such instrument transferred to the final Runsheet.

11. A search should be made in the Daily Register of Instruments against all owners of the subject land from the date of the last entry in the Index to Official Public Records to the present date to determine whether any instruments affecting the subject land have been filed for record. 12. Prepare a list of all the names to run in the records, the dates covered and the particular indices reviewed; the preparation of the names list is more efficient if it is prepared during the examination of the record title.

C. In order to conduct the above search efficiently, a landman may choose to use a research checklist. In the “name” column, record the name of each owner of the subject land beginning with the original patentee and continuing down to the present owner. Then, in the “date” column, for each owner, record the month/day/year in which the owner acquired the title and the month/day/year in which the conveyance out of the owner was filed for record. If the instrument includes an effective date, then place the instrument in order by the effective date.

13. In the age of multitasking, the tendency is to try to make a simple process more complicated by reviewing multiple Indices for multiple names simultaneously rather than reviewing for one name at a time or reviewing one Index for multiple names in an orderly and prescribed manner. Nowadays, a landman uses software apps to facilitate recording his/her progress and speed up the process, but it is important to keep the process simple, it is a step-by-step process, and record the progress of work through the completion of the Runsheet.

1. Proceed to check each index set forth on the checklist one at a time against all owners of the subject land. The scope of search for each owner will be from the date the owner acquired title to the present. Record the pertinent information about each instrument and proceeding that affects the subject land.

In applying the methods presented in this paper into practice, each landman should develop their own version of the principles and methods set forth in this paper, and as such, the likelihood of errors will be lessened.

2. After each index has been searched, arrange the instruments and proceedings in chronological order. Determine whether there are any unreleased liens, leases, or any other outstanding matters. It may be necessary to search the indices again to find releases, heirship affidavits, or other instruments and proceedings in order to cure any outstanding matters.

A. The results of the search above for each instrument or proceeding should be recorded on the Runsheet software in the paper or digital medium of choice, and should contain the following information for each instrument or proceeding which affects the subject land:

G. ONLINE RESEARCH. A survey has not been conducted to determine how many County Clerk’s records are online through their website or the number of commercial records firms make the county records of the County Clerks in Texas

(a) Grantor (b) Grantee (c) Nature of instrument 16

available, and whether the online records are from the sovereignty of the soil or begin at some later date, and then to the present day. Care and attention should always be given to whether the online records are the authentic records of the County Clerk or whether the online records are copies of some, or all of the County Clerk’s records, which have been copied by a third party vendor who makes those records available for a fee. The time period of which the records of the County Clerk are posted online should be determined with certainty. Many of the Official Public Records may be accessed directly through the county website or, in some cases, the County Clerk’s website. Generally, some or all of the Official Public Records are available online through commercial online title search companies, but such online records may or may not cover the period of time from sovereignty of the soil to the present, nor should such records be considered the equivalent of the actual records themselves. Regardless of the manner in which the records are accessed, the commercial provider in each case will clearly state through a multiple page agreement or on the face of the document itself, that it disclaims any representation or warranty as to the accuracy of the information and use of such service and access of such records are at the users sole risk. The search engines are sometimes difficult to navigate, similar to the early digitized Official Public Records in the Courthouse, but many are organized in such a way that a Grantor/Grantee search may be conducted. As is always the case with research or indexing records at a computer terminal, whether it be at the courthouse or online at the landman’s office, no standardized system exists for data input, and in most cases, the person who is charged with the task of data input is left to decide how to abbreviate entities, trusts, or persons with more letters than will fit in the dialog box.

the County Clerk’s offices. The best practice in this respect is to confirm with the County Clerk that the records are identical. Some of the online records provide access to all of the county records from sovereignty to the present, but some clerk’s websites and online services do not have access to some of the older records of the County Clerks’ offices. Many landmen have had success with relying on the online records, if it can be determined that the online records are identical to the records in the courthouse or the County Clerk’s offices. It should be noted that many of the District Clerk’s records are oftentimes unavailable online. As is always the case with online, digitized records, poor copy quality will always be an issue and may require another approach to obtaining a copy of the affected instrument. While third party commercial online records are a useful tool, many such services utilize their own indexing methods, which creates a risk of missing a relevant document. In practice, attempting to prepare a Runsheet online has generally proven to be tedious and a time consuming exercise. Moreover, when a landman prepares a Runsheet online without the courthouse or the County Clerk’s verification of their online records, that landman assumes the responsibility for the accuracy of the data included in the Runsheet. However, online Public Records have proven to be very helpful in reviewing documents online from a Runsheet prepared by a landman from the Public Records at the courthouse. Most courthouses are open Monday to Friday, 8 a.m. to 5 p.m., if one is lucky, and may be very crowded depending on which counties are the most active at the time, but the online Public Records are available 24/7, which is very useful when time is of the essence. Many landmen have also found the online records very useful in a number of different situations as a stop-gap measure, but caution should always be used when relying on third party websites for title information. In addition to the county Public Records online, the Secretary of State, Comptroller of Public Accounts, Texas Railroad Commission, and most governmental agencies have websites in which to search for information regarding individuals and entities, and drilling activity upon the subject land.

Many of the Official Public Records are available through a monthly paid subscription through the County Clerk’s website or the commercial title search firms. In those instances where the County Clerk is providing access to the online records through the County Clerk’s website, most landmen seem to rely on such records in the same manner as the reliance on the physical records in 17

H. RUNSHEET ORDER AND CONTENT. Runsheets come in many shapes and sizes, containing all the information needed to conduct a thorough examination of title to the subject land, and sometimes not, as the case seems to be more often with the up and down influx of inexperienced persons to the land business in the upside cycle of the oil and gas business, and the intense pressure to meet drilling deadlines. To some extent, the content of a Runsheet is subjective, depending on the preparer and the extent of detail beyond the basic recording information included in the Runsheet.

requires a re-thinking and re-charting the chain of record title. 3. Probates should not be placed in the Runsheet on the date of the Will or the date that the probate is filed, but rather on the date of the death of the Decedent because a Will becomes effective upon the death of the Decedent. The date of death of the Decedent is usually stated in the application to probate a Will. If the probate proceedings do not reveal the date of death, then the probate proceedings should be placed in the Runsheet on the date the proceedings were filed and not on the date of the Will with a notation that the date of death is unknown. If the probate proceedings are filed in a county other than where the land is located, at a minimum, the Runsheet should include a reference to the Will and the Order Admitting the Will to Probate.

1. The Runsheet should contain a separate entry for each instrument and proceeding determined by review of the Official Public Records as described above. It should also include any instrument referenced in any instrument, whether the referenced instrument seems to apply to the subject land or not. Any recorded or unrecorded instruments referenced in a recorded instrument should be included in the Runsheet to the extent it is available. If the referenced instrument is recorded in a different county other than the county where the subject land is located, the preparer should note such exception. Landman’s notes as to correction instruments or future instruments in the Runsheet that affect an earlier entry are very helpful to the title attorney as an indication of upcoming documents.

4. Lawsuits should be inserted in the Runsheet on the date of the judgment. The recording statutes of Texas only apply to instruments that are filed in the Deed Records in the County Clerk’s Office and not the District Court Records. A person is only on notice of the instruments and proceedings of the District Court filed in the Deed Records (other than by actual notice). If there is some reference in the Deed Records to a lawsuit filed in the District Clerk’s Office, then under Texas case law, everyone is on notice and has a duty to make a reasonable review of the District Court Records to review the file and insert those proceedings in the Runsheet. Therefore, one is not on notice of a judgment in the District Court Records, unless a certified copy or an abstract of judgment thereof is filed in the County Clerk’s Office.

2. As noted above, the Texas recording statutes are not dependent upon when an instrument is filed; therefore, all Runsheets should be arranged in Texas by instrument date (or effective date, if applicable) and not by file date. Arranging the documents by instrument date not only makes it easier for the title attorney to examine the chain of the title, but also allows the attorney to determine when issues arise concerning the recording statutes. The recording statutes apply in Texas when a Grantor makes a conveyance of an interest in land which is not filed until after the same Grantor makes a subsequent conveyance of the same interest to a different Grantee. If the Runsheet is arranged by file date, the examining attorney will read the second instrument first and would not be aware at that point in time that a previous conveyance had been made, which then

5. With respect to Affidavits of Heirship, the examination is more logical for the examining attorney if such affidavits are placed in the Runsheet on the date of death of the decedent and not on the date of the affidavit. In this case, the examining attorney will recognize conveyances by heirs of the decedent immediately and can avoid the confusion caused by such conveyances as strangers to the title. If the subject of the Affidavit is a matter other than heirship, the Affidavit should be placed in the order of its date. 18

6. As noted above, it is very important to the examining attorney that the specific record where the instrument or proceedings are recorded be clearly identified, whether Deed Records, Official Records, Official Public Records, and so forth.

a. Runsheet containing all instruments and proceedings pertinent to the tracts, preferably in a common, digital format. b. Plats sufficient to identify the subject land, but preferably plats showing the outsale of tracts, and in the best situation, plats for each instrument in the Runsheet, including plats prepared on a plotting program that reflect if the metes and bounds descriptions close.

7. Beyond the basic recording information and in the proper chronological order, what should a Runsheet include. This depends in part on whether the examination is to a “stand-up” conducted by the attorney at the courthouse, or an examination in more of the nature of an abstract of title examination from the Runsheet with copies of all instruments listed on the Runsheet. Each approach will depend on the company ordering the Runsheet and title examination.

c. Copies of all documents contained in the Runsheet along with any curative documents that may have been obtained. The copies of the documents should be a complete copy of the instrument through the County Clerk’s recording stamp, and if the recording volume of the instrument is not present on the face of the document, the volume and page should be noted on the first page of the instrument.

8. A Runsheet for a stand-up examination should include as a minimum the following (this is the bare minimum and not the preferred): a. Runsheet containing all instruments and proceedings pertinent to the tracts, preferably in a common, digital format.

d. Separate copies of the current Oil and Gas Leases for the subject land, regardless of whether the period of time covered by the Runsheet begins after the date of the Oil and Gas Leases.

b. Plats sufficient to identify the subject land.

e. Copies of the reference Deeds described in any current Oil and Gas Lease.

c. Copies of all oil and gas leases, if only memoranda are recorded.

f. Tax Certificates, not uncertified tax statements, which may not be relied upon for establishing the payment of taxes in prior years, unless so directed by the client.

d. Cover letter identifying the preparer, description of the property, scope of the search as to surface and minerals or any limitation thereon, the time period covered and the order in which the instruments are included, the records reviewed in the preparation of the Runsheet, a list of the names/entities searched and the period of time searched for each, and any exceptions and limitations on the Runsheet.

g. If the Runsheet is prepared as a supplemental Runsheet to a prior title opinion, a complete copy of the prior title opinion should be included in the Runsheet. h. Cover letter or certification letter identifying the preparer, description of the subject land covered by the Runsheet, the scope of search as to the surface estate and the mineral estate or any limitation thereon, i.e., depth limitations, the time period covered, including the beginning date and the closing date, and the order in which the instruments are included, the records reviewed in the preparation of the Runsheet, a list of the names/entities searched and the period of time searched for each party, and any exceptions and

e. Tax Certificates, not uncertified tax statements, which may not be relied upon for establishing the payment of taxes in prior years. The attachments of tax statements to a Runsheet has become a common practice, but a Tax Certificate is the proper evidence of the payment of ad valorem taxes. 9. A Runsheet with copies of the instruments to be examined, more in the nature of an abstract of title, should include as a minimum the following: 19

limitations on the records searched and included or excluded from the Runsheet.

surface estate and include a notation that the chain of title to the surface was not included beyond such date.

II. Risk Management

3. Many companies limit the scope of the Runsheet by not running the leasehold title to the prior oil and gas leases of record, other than the current client leases, with a notation in the Runsheet that such chain of title has been excluded subsequent to the recordation of the related leases. There are many variations on this limitation, which involve picking a date in the past in after which not to include the prior oil and gas lease leasehold title, but rather including the chain of title of the leasehold title for all prior oil and gas leases which are recorded after a certain date in the past. Generally, thirty years seems to be a popular number of years. In some cases, the Runsheet contains a limitation that none of the leasehold title to prior oil and gas leases, based on the County Clerk’s records, was included after the date of the lease, rather the records of the abstract company were relied upon by the preparer.

This section of the paper will address “risk management” as applied to the content of Runsheets or limitations of the content of Runsheets based on the policy of management of the company requesting the preparation of a Runsheet. The trend in the policy or attitude of company management has been to view some aspects of title examination as a part of an overall risk management strategy. This may have occurred because of a need to complete examinations faster, to save money, or because title is something that can now be assigned a risk factor, similar to the way the production department and exploration department assign a risk factor to wells before they are drilled. Much of a company’s risk management strategy depends on the nature of the company and its goals for the company, whether short-term as with some private equity-funded companies or long-term as with the majors. Whatever the reason may be, on a company by company basis, the following discussion sets forth many of the limitations on the manner of the preparation of Runsheets by the landman in today’s oil and gas environment.

4. With respect to prior liens, whether they be created by mortgages, deeds of trust, mechanics and materialmans liens, security agreements, vendor’s liens, or supplements or amendments thereto (collectively “Prior Lien”), many companies limit the scope of the Runsheet by not considering a Prior Lien, which is dated prior to a certain date in the past. Generally, thirty to forty years is the time period selected. In some cases, Runsheets do not include a Prior Lien if it is dated before the selected date, or it may be listed and the chain of title to the Lien not “run” forward in the Official Public Records. Some companies will want a Runsheet to only include Prior Liens that occur before a certain date, but only if the same has been foreclosed. With respect to Prior Liens after the selected date, many companies will want a Runsheet to only list those liens which in the landman’s opinion have not been released. However, all lien documents should be identified in the runsheet if the recorded lien document does not reflect the maturity date of the underlying promissory notes referenced in the specific lien document. Some Runsheets will include all liens when there is no release of record, and

A. PUBLIC RECORDS REVIEW 1. Obtaining a Runsheet by a knowledgeable landman and a title opinion by an examining attorney usually represents a significant expense for most exploration companies. Many companies encourage their landmen to not review every document for overall content or in its entirety but to simply determine if it applies to the subject land and include it on the Runsheet. Their position is that the examining attorney has the responsibility of determining whether the instrument applies or is relevant to the subject land. Many companies take the position when in doubt include the instrument. 2. Many companies limit the scope of the Runsheet by not including title to the surface estate where the same has been severed from the mineral estate. The Runsheet will include the instrument severing the mineral estate from the 20

the date of the lien is less than forty years prior to the closing date of the Runsheet.

than severance from sovereignty, in which to start the review of the Official Public Records. In some cases, the date of 1900 has been selected, with instruction to the landman to include the patent or grant and to review all conveyances of the subject land prior to 1900 for any mineral reservations or conveyances.

5. Often, companies will limit the scope of the Runsheet to not include any subsequent title review of easements or rights-of-way beyond the date of the original conveyance with the appropriate notation of same in the Runsheet. In addition, any lien interest created in any right-of-way or easement would be excluded from the coverage of the Runsheet. This limitation in most cases is not significant.

B. CONSEQUENCES Every title to a specific tract of land is unique and subject to exceptions to the general rules. Although not common before Spindletop at the beginning of the twentieth century, the earliest mineral severance in Texas known to this author was in 1883, if one does not include the reservations by certain of the successive sovereigns prior to the Republic of Texas. Each instrument is unique and oftentimes has been drafted by the less artful, those who are not cognizant of the relevant statutes regarding liens and foreclosures, construction of descriptions, proper parties to conveyances, and many more discrepancies, too numerous to list. Each company in today’s environment must make its own decision as to the limitation of the information on which it chooses to base its decision to spend millions of dollars for one well. Suffice it to say, each limitation placed on a landman on the manner of preparation of the Runsheet on which the examining attorney is to base the title opinion limits the appropriate and best data available to the company in assessing its risks relevant to its operations.

6. Some companies will elect not to include a review of the District Court Records unless the Deed Records, Lien Records, or other records reveal a Lis Pendens or Abstract of Judgment, or an instrument in the Runsheet contains a reference to a cause of action in the District Court Records, whether or not the subject land is referenced in the cause of action. 7. Many companies will limit the scope of the Runsheet to not include any review of the Indices of Abstract of Judgment Records or Lien Records for more than ten to fifteen years prior to the closing date of the Runsheet, unless some instance occurs that would cause a reason to include the same. The period which the Runsheet should cover as to a lien search should always be at least twenty years due to the fact that some tax liens and federal judgment liens remain in effect for twenty years from the date of filing of such lien. Child support liens filed on or after September 1, 1997, and before May 26, 2009, are effective indefinitely. 8. In some instances, companies will limit the scope of the Runsheet by instructing the landman not to chain the title of a person or entity beyond the filing date of the instrument in which such person or entity purportedly divests itself of title to all interest in the subject land but review the chain of title of the names of all owners within the past ten years as to surface and mineral ownership. 9. The most radical departure from the traditional manner of preparing Runsheets has been by many companies, limiting the scope of the Runsheet to give the preparing landman a date certain, other 21

With regard to the preparation of Runsheet 101, as to the original paper, I would like to thank Randy Boatright for encouraging the presentation of a paper on the preparation of Runsheets, and acknowledge the assistance of Arthur Moore, John Clennan, Joel Muscat, and Howard Martin for their input on this paper, particularly the likes and dislikes of the Runsheets utilized by them, and acknowledge the writings of Fred A. Lange, and a prior paper on the subject by John R. Thomason, Huntsville, Texas.

Michael P. Miller for his time and effort in editing this revision of the original paper.

With regard to the preparation of Runsheet 101 – Revisited 2021, I would like to thank Robinson for his recommendation about updating the paper, and Mike Nelson and Clay Stanley for their input and experiences on the preparation of Runsheets in the digital world. Finally, I would like to thank

Texas Resiliency: The Aftermath of Winter Storm Uri

legislature to strengthen the state’s generation system, in turn preventing a second electricity crisis, highlight this resiliency.

By: Cristina Goulet & Colin Davis, J.D. South Texas College of Law Houston

The generation system of Texas is unique for a couple reasons. First, the Texas electricity markets are deregulated and have been since the late 1990s.4 A deregulated market allows for competition in the generation and distribution of electricity. Here, the customer has the option of selecting an electric supplier rather than being required to purchase electricity from their local electric utility. Second, Texas – like Alaska and Hawaii – is “off” the national grid. In the United States, the electrical power grid is divided into three primary regions: the Western Interconnection, the Eastern Interconnection, and the Texas Interconnection. Texas is the only state in the contintental United States not substantially interconnected with either the Eastern Interconnection or Western Interconnection. These characteristics allow for Texas energy policy to stand alone from our energy network-counterparts.

Introduction Amid international crises it may be easy to forget the hardships Texans endured just over a year ago. In February 2021, tragedy struck the Lone Star state in the form of a winter storm that left Texas in a complex bind. The storm resulted in over 200 fatalities spanning over 77 counties and an estimated financial loss ranging between $80 billion to $130 billion.1 Winter Storm Uri is considered as one of the worst natural disasters in Texas history.2 The infamy of Uri continues to haunt the state as efforts to prevent a second electricity crisis flood politics, regulation, and still – the courts. To appreciate Texas’ redemptive strides towards “electricity security”, one must look to policy, regulation, and science to understand how Texas has renewed the integrity of the electricity grid and how the Cold Snap occurred in the first place. The Texas Generation System In The Cold Snap of February 2021 – Initial Thoughts on the Energy Situation in Texas, Christopher Kulander addresses how Uri was an event beyond the ability of Texas’ entire generation system. He discusses trade-offs with regards to the reliability of electricity and concludes with this maxim3: Kulander’s Law of Electricity in America: “Everybody gets all the electricity they want all the time at non-exorbitant rates or heads roll.”

The three separate energy networks in the United States’ power grid system operate independently of each other and exchange little energy. The majority of the state's users are served by an intra-state grid, which is operated by ERCOT as an independent system operator with minimal connections to the country's other two main electrical grids. ERCOT is subject to oversight by the Public Utility Commission of Texas (PUC) and the Texas Legislature. ERCOT plays a vital role by

Heads did in fact, roll. Bankruptcies, lawsuits, and resignations from the Electricity Reliability Council of Texas (ERCOT) board members rolled across Texas. The storm’s effects were politicized by the media in every way. Nevertheless, Texan resiliency has continued to shine, with assistance coming from Austin, Atlanta, and Capitol Hill. The reactive measures taken by the Texas 23

managing the flow of electric power to more than 26 million Texas customers, or roughly 90% of the state's electric load.5 Power producing firms, electricity providers/utilities (i.e., investor-owned and municipally owned providers, electric cooperatives, and river authority), and transmission and distribution utilities that engage in the wholesale energy market are all used by ERCOT.6

As depicted below, Texas has enjoyed relatively low electricity rates. As reserve capacity and seasonal protection increase, the costs for reliability will eventually find their way to the consumer or investor.

Electricity Reliability Trade-Offs Our standard of living is reliant on a dependable bulk power system that is kept in constant demand balance. The bulk power system, also known as the bulk electric system, is a massive, linked electrical system made up of generation and transmission facilities. To maintain an uninterrupted supply of electricity to homes and businesses across the country, generation and transmission lines must be monitored around the clock. The facilities and control systems are required to operate and maintain the reliability of an integral electric energy transmission network.

Source: U.S. Energy Information Administration

Despite the three energy networks operating independently of eachother, after Uri, non-Texan agencies and organizations began to get involved. to address questions of electric reliability standards and the respective trade-offs. Following the storm, the Federal Energy Regulatory Commission (FERC), the North American Electric Reliability Corporation (NERC) and NERC’s regional entities issued a report which reviewed what happened during the freeze and outlined a series of recommendations, including mandatory electric reliability standards, to prevent a recurrence.11 NERC is an international regulatory organization that works to reduce risks to power grid infrastructure. The organization is subject to oversight by FERC and governmental authorities in Canada.

Power reliability is the degree to which the performance of the elements in this bulk system result in electricity being delivered to customers within accepted standards and in the amount desired.7 The degree of reliability may be measured by the frequency, duration, and magnitude of the adverse effects on the electric supply.8 As a result of Texas’ system failures, electricity reliability trade-offs were brought to the forefront of policy. Electricity reliability trade-offs include price, reserve capacity, and seasonal protection. The less expensive the electricity is, the less reserve capacity and less winterization. Conversely, more reserve capacity and additional seasonal protection increases the cost of electricity. Electricity prices generally reflect the cost to build, finance, maintain and operate power plants and the electricity grid.9 Several factors that influence the price of electricity include: (1) fuel prices (2) power plant costs (3) transmission and distribution systems (4) weather conditions and (5) regulations.10

What Went Wrong Winter Storm Uri hit Texas and the Midwest from February 8 to February 20, 2021, bringing bitterly cold temperatures and freezing rain. The arctic cold air mass resulted in average temperatures dropping well below freezing for areas including Texas, Oklahoma, Arkansas, Louisiana and Mississippi.12 On February 8, ERCOT issued notices to generation and transmission operators. On February 11, gas production in Texas ultimately dropped by 45%,13 with Governor Abbott issuing a disaster declaration the following day.

The storms affected several balancing authorities who are tasked with maintaining electricity balance within their respective regions. Of the three affected balancing authorities (Bas): ERCOT, the Southwest Power Pool (SPP) and the Midcontinent Independent System Operator (MISO), with ERCOT experiencing the most severe and drawn-out effects.14 Between February 15 and 18, ERCOT, MISO, and SPP Bas implemented energy emergency measures including firm load shed. During a load shedding event power companies shut off supply to certain groups of customers so that the entire system can avoid collapse.

the specific terms and conditions of natural gas commodity and pipeline transportation contracts, and other issues like low pressure. The crucial causes of the decline in natural gas wellhead production were shut-ins to protect natural gas production and process facilities from freeze-related impacts. These impacts include frozen equipment, loss of power supply, poor road conditions which prevented both the removal of fluids from production sites and access to facilities to make necessary repairs.19 The FERC-NERC Report made 28 preliminary recommendations, many of which have since been incorporated into Texas energy policy. Given the two biggest causes of the energy crisis involving freezing issues and natural gas fuel supply issues, it is no surprise recent legislation has focused heavily on designating natural gas facilities and weatherization.

Out of the three Bas, ERCOT needed to shed the greatest quantity of firm load to balance electricity demands with the generating units that were able to remain online. This was a significant problem during the storm and resulted in the largest controlled load shed event in U.S. history. The two largest causes of outages, derates, and failures were due to (1) freezing issues and (2) natural gas fuel supply issues.

Senate Bill 3 – Increased Texas Resiliency On June 8 2021, the Texas state legislature passed Senate Bill 3 (SB3) creating new law related to preparing for, preventing, and responding to weather emergencies and power outages. One faucet requires the PUC to implement weatherization standards for powerplants. Utilizing the state’s rainy-day fund consisting of over $11.4 billion, the Legislature created a $2 billion plan to help power companies pay for winterization upgrades. A significant problem during Uri was not only the implementation of “load shedding, but critical infrastructure facilities experiencing this. To avoid critical facilities experiencing this issue in the future, SB3 created a “Critical Infrastructure” designation for hospitals and fire stations.20

Freezing Issues Freezing issues were a result of failing to sufficiently “winterize” generating units for cold weather conditions. Over 1,000 generating units experienced outages, derates, or failures to start on more than 4,000 occasions during the extreme cold, resulting in the loss of 61,800 megawatts of electric power.15 In fact, of the 1,823 unplanned outages, derates, and failures to start caused by freezing issues, 1,244 were in ERCOT, 473 were in SPP, and 106 were in MISO South.16 Frozen equipment (sensor lines, transmitters) and ice on wind turbine generator blades were the most prominent sub-causes of generation outages and derates related to freezing concerns.17

Additionally, State Agencies were directed to determine methods for effectively reducing risks and impacts on utility facilities and critical infrastructure from disasters such as Uri.21 Not only are Agencies directed to determine risk reducing methods, but agencies are also required to encourage public and private entities which are responsible for utility facilities and critical infrastructure to implement these methods.22 This legislation has a drawback: by requiring facilities to register as critical infrastructure facilities with the State, there is

Natural Gas Fuel Supply Issues The second largest cause was natural gas supply issues. A majority of generation outages (87%) due to fuel issues were related to natural gas, mostly at the production and processing stages.18 Natural gas fuel supply issues included the combined effects of decreased natural gas production, 25

a chance of failure to register, potentially resulting in the same problems Uri created. For the facilities who do register, they will then have access to the allocated funds so that they can implement the weatherization requirements. The combination of research development and enforcement methods is meant to give the state a more thorough understanding of what the infrastructure problems are, who experiences those problems, and what the best route is to prevent these problems from occurring in the future.

facilities to be prioritized during an energy emergency that requires electric utility loadshedding. Critical status does not however guarantee uninterrupted supply of energy.27 Through the adoption of these rules, critical facilities including more than 19,000 of the state’s natural gas production facilities will be required to weatherize. It is no coincidence that these rules follow FERC-NERC’s recommendation report regarding weatherization. This adherence will allow for the generation system to operate at enhanced levels in the face of future winter weather events.

By requiring registered facilities to weatherize, the State helps secure the power supply so that in the event of another winter disaster, power producing facilities will be prepared and face a smaller risk of being shut down.

Texas Adopts Electricity Supply Chain Map As a part of SB 3, the Legislature created the Texas Electricity Supply Chain Security and Mapping Committee. In late April, the Committee adopted an Electricity Supply Chain Map of critical infrastructure – the first of its kind in the state – for use during disaster and emergency preparedness and response.28 The creation of this map was required under SB 3. The map identifies critical infrastructure facilities that make up the state’s electricity supply chain, including electric generation plants and the natural gas facilities that supply fuel to power the plants. Texas emergency management officials will utilize the map during weather emergencies, like Uri, to pinpoint the location of critical facilities and maintain emergency contact information for such facilities.29 The current map has more than 65,000 facilities of which are critical gas suppliers or critical gas customers. This unique measure is a living document that will be updated to ensure accessibility to pertinent information during energy emergencies.

Designation of Natural Gas Facilities for Energy Emergencies In June 2021, the 87th Legislature enacted House Bill (HB) 3648 requiring the PUC and Railroad Commission of Texas to collaborate on rules regarding critical natural gas facilities and entities.23 The rules adopted by the Railroad Commission of Texas implement provisions in HB 3648 and SB 3, intending to ensure that gas continues to flow during energy emergencies. They do so by establishing “the criteria and process by which entities associated with providing natural gas in Texas are designated as critical gas suppliers or critical customers during an energy emergency.”24 Critical gas suppliers are the key parts of the natural gas supply chain. These include gas wells, oil leases that produce gas, natural gas pipeline facilities, underground natural gas storage facilities and saltwater disposal facilities.25 Critical customer, a subset of critical gas suppliers, are gas suppliers for whom electricity is essential to the ability of such gas supplier to operate. These operators will provide crucial consumer information to their electric utilities so that they can supply power to the facilities with the correct information. Both critical categories will be subject to weatherization requirements if the facility is a gas supply chain facility included on the electricity supply chain map.26 This designation allows critical gas

Conclusion After Uri, Governor Abott made weatherizing the state’s electricity generation infrastructure an emergency priority. The motivation behind this was the Texans who were left without heat, power, and in some cases water, for days on end.30 The reactive measures taken by the Texas legislature and implemented by state Agencies will improve the reliability of the electric grid, forestall a second electricity crisis, and keep heads from rolling.

Jess Donald, Winter Storm Uri 2021 – The Economic Impact of the Storm, (Oct. 2021), https://comptroller.texas.gov/economy/fiscal-notes/2021/oct/winter-stormimpact.php. 2 One-time Reimbursement for Winter Storm Uri Remediation Costs, TEXAS EDUCATION AGENCY (Dec. 9, 2021), https://tea.texas.gov/about-tea/news-and-multimedia/correspondence/taa-letters/one-time-reimbursement-for-winterstorm-uri-remediation-costs 3 Christopher S. Kulander, The Cold Snap of February, 2021 – Initial Thoughts on the Energy Situation in Texas (Mar. 1, 2021), https://thepipeline742032307.wordpress.com/2021/03/01/the-cold-snap-of-february-2021-initial-thoughts-on-the-energy-situation-in-texas. 4 Jake Dyer, The History of Electric Deregulation in Texas, http://tcaptx.com/downloads/HISTORY-OF-DEREGULATION.pdf (last visited April 29, 2022). 5 About ERCOT, Electric Reliability Council of Texas, https://www.ercot.com/about (last visited May 4, 2022) 6 Id. 7 John D. Kueck and Brendan J. Kirby, Measurement Practices for Reliability and Power Quality (June 2004), https://info.ornl.gov/sites/publications/Files/Pub57467.pdf. (last visited May 1, 2022). 8 Id. 9 Electricity explained, U.S. ENERGY INFO. ADMIN., https://www.eia.gov/energyexplained/electricity/prices-andfactors-affecting-prices.php (last updated April 20, 2022) (explaining the factors which affect electricity prices). 10 Id. 11 February 2021 Cold Weather Grid Operations: Preliminary Findings and Recommendations, FERC, NERC, and Regional Joint Staff Inquiry (Sep. 23, 2021) https://www.ferc.gov/news-events/news/ferc-nerc-staff-review-2021-winter-freeze-recommend-standards-improvements. 12 Id. 13 Texas natural gas production fell by almost half during recent cold snap, U.S. ENERGY INFO. ADMIN, (Feb. 25, 2021), https://www.eia.gov/todayinenergy/detail.php?id=46896. 14 February 2021 Cold Weather Grid Operations: Preliminary Findings and Recommendations, FERC, NERC, and

Regional Joint Staff Inquiry (Sep. 23, 2021) https://www.ferc.gov/news-events/news/ferc-nerc-staff-review-2021-winter-freeze-recommend-standards-improvements. 15 Id. 16 Id. 17 Id. (explaining the sub-causes of freezing related generation outages). 18 Id. 19 Id. (specifying freeze-related impacts on natural gas facilities). 20 Tex. Gov’t Code Ann. § 418.0549 (West). 21 Id. at (c)(1). 22 Id. at (c)(1). 23 Critical Natural Gas, PUBLIC UTILITY COMM’N OF TEXAS, https://www.puc.texas.gov/industry/electric/cng/Default.aspx (last visited May 14, 2022). 24 Tex. S.B. 3, 83d Leg., R.S. (2021), available at: https://capitol.texas.gov/tlodocs/87R/billtext/pdf/SB00003F.pdf#navpanes=0; Texas H.B. 3648, 83d Leg., R.S. (2021), available at: https://capitol.texas.gov/tlodocs/87R/billtext/pdf/HB03648F.pdf#navpanes=0 25 Texas Establishes First of Its Kind Designation of Natural Gas Facilities for Energy Emergencies, RAILROAD COMM’N OF TEXAS (Nov. 30, 2021), https://www.rrc.texas.gov/news/113021-critical-infrastructure/ 26 16 Texas Admin. Code §3.65 27 Critical Natural Gas, PUBLIC UTILITY COMM’N OF TEXAS, https://www.puc.texas.gov/industry/electric/cng/Default.aspx 28 Texas Adopts First-Ever Electricity Supply Chain Map, PUBLIC UTILITY COMM’N OF TEXAS, (April 29, 2022), https://gov.texas.gov/news/post/governor-abbott-signs-ercot-reforms-power-grid-weatherization-legislation-into-law 29 Id. 30 Governor Abbott Signs ERCOT Reforms, Power Grid Weatherization Legislation Into Law, Office of the Texas Governor (June 8, 2021), https://gov.texas.gov/news/post/governor-abbott-signs-ercot-reforms-power-grid-weatherization-legislation-into-law

spread among these countries and inhabiting the earth.5 Despite the widespread reach of society, not all countries view this issue the same way. There are countries that are making large push for change, and others that seem unwilling to acknowledge the need for change.

Global Carbon Emissions: A Race to Zero By: Hector Jett Black South Texas College of Law Houston Introduction

The United Kingdom (U.K.) has proposed some of the most ambitious decreases in emissions seen around the world.6 The U.K. government set a “target of 68% cuts by 2030” compared to their 1990 emission rates.7 The government seems to have not accepted this sharp decrease as being a substantial enough effort. Therefore, they decided to take it one step further by setting a goal of seventy-eight percent reduction in emissions by 2035.8 Prime Minister Boris Johnson said, “We want to continue to raise the bar on tackling climate change, and that’s why we’re setting the most ambitious target to cut emissions in the world.”9 Should the 2035 goal be met, the United Kingdom will be far ahead of other countries in the race to zero.

Around the world countries are competing to become carbon neutral. Humanity is racing to reduce carbon emissions to avoid temperatures rising as much as 10.2 degrees Fahrenheit.1 The world is transforming as the amount of carbon dioxide in the atmosphere continuously increases due to the expansion of our technology driven society. From the Industrial Revolution to the Present Age, the amount of carbon being released into the atmosphere has increased each year. While society may be seen as prospering, the world around it is withering. For example, the United States of America (U.S.) is facing risk to the Great Lakes, increased droughts, insect outbreaks, and a variety of other issues as a result of current carbon levels.2 If one of the most technologically advanced and modern countries of the twenty-first century is facing these conditions, what does it mean for the rest of the world? In an attempt to take the lead in the race, the U.S. has attempted to implement executive regulations that have failed. Such as an injunction that brought a Presidential Executive Order to a grinding halt. Meanwhile, the State of Texas has succeeded in passing regulations to help promote carbon capture in their oil and gas fields. As time passes by, government entities, countries, states, and companies around the world are taking action to bring their respective carbon emissions levels to zero.

Overall, the United States accounts for about 15% of the world’s carbon emissions. It naturally follows that a country that plays such a significant role in the issue should make some of the biggest changes.10 For example, if the United States meets the goal of a reduction in fifty to fifty-two percent of 2005 emission levels by 2030, a huge decrease in global emission levels would follow.11 Making emission calculations is the easy step, while the challenging part will be implementing the solutions to reach the goal. As will be discussed later, the U.S. has had bumps in implementation in enacting executive regulations. The third contender is not a single country, rather it is an economic and political alliance of countries: the European Union (EU).12 The European Union represents “more than 340 million EU citizens in 19 countries.”13 The countries are collectively governed by the policy making European Commission among other government entities.14 Recently the Commission has adopted what has been termed “The European Green Deal.”15 This deal pledges that the EU will cut 55% of their 1990 emission levels by 2030.16 The Commission proceeded to take things a step further and pledged

Around the World Given the risks and effects that are naturally coupled with the increase in carbon levels, government entities around the world are taking strides to decrease their emission rates. There are three notable government entities who are taking the lead in bringing changes to society: the United Kingdom, United States of America, and the European Union.3 There are currently 195 countries recognized by the United Nations.4 As of January 31, 2022, there are an estimated 7,924,078,992 people 28

comprehensive review.”20 This comprehensive review would be coordinated by the Secretary of the Interior and in consultation with the Secretary of Agriculture, the Secretary of Commerce, the National Oceanic and Atmospheric Administration, and the Secretary of Energy.21 As a result, there was no other choice for oil and gas companies but to wait and see when the review would be complete and if the moratorium would be lifted before commencing drilling.

three major transformations: (1) no net emissions of greenhouse gasses by 2050; (2) economic growth decoupled from resource use; and (3) no person and no place left behind.17 The European Union already plays a large role in the global economic, political, and social issues. With the pledges that the EU has made, it has placed itself at the forefront of environmental issues as well. As the race to zero continues, government entities are taking bigger strides to be the first to reach and maintain zero. The government entities that are leading the charge now might not always be in the lead. Only time will tell who the international leaders in this great race will be.

Following the issuance of Executive Order 14008, the States of Louisiana, Alabama, Alaska, Arkansas, Georgia, Mississippi, Missouri Montana, Nebraska, Oklahoma, Texas, Utah, and West Virginia filed suit against a variety of Government Officials in the United States District Court for the Western District of Louisiana, Lake Charles Division.22 Plaintiffs sought a preliminary injunction to prevent the entities of the Federal Government from performing the actions or duties required by Section 208 of Executive Order 14008.23 In order for a preliminary judgment to be granted, a movant must show, “(1) the substantial likelihood of success on the merits, (2) that he is likely to suffer irreparable harm in the absence of a preliminary injunction, (3) that the balance of equities tips in his favor, and (4) that an injunction is in the public interest.”24 The Court found that the Plaintiffs met the elements required to issue a preliminary injunction.25 The Court ruled that the preliminary injunction should be applied across the country to promote uniformity in leasing practices around the country.26

The United States of America The United States has taken its own measures to stay ahead of other countries in the race to be carbon neutral. As will be discussed, mineral ownership in the United States is largely held in private ownership. This largely affects the efficiency of potential government regulation. This has not stopped the government from attempting to put regulations in place. On April 22, 2021, the White House published a fact sheet on behalf of President Joe Biden, laying out a 2030 goal for reduction of greenhouse gas pollution.18 The fact sheet outlines how the Biden administration aims to meet its goals on the elimination of greenhouse gas pollution. The White House has not limited its efforts to just a fact sheet. President Biden took action using authority from the Executive Branch to put regulations in place, but it did not end the way that the administration had hoped.

One might ask, what effect would this ban have had on the exploration and production of oil and gas on federal lands in the U.S. had the preliminary injunction not been granted? The answer is that it likely would have not had a considerable effect. The U.S. differs from most other countries in how they determine ownership of oil and gas mineral interest.27 Where most countries reserve mineral ownership for governments, the U.S. allows for ownership by private citizens and private entities.28

The Executive Branch of the United States Government attempted to act on the issue of carbon emissions via an Executive Order. On January 27, 2021, President Biden issued Executive Order 14008, “Executive Order on Tackling the Climate Crisis at Home and Abroad.”19 While the order focused on President Biden’s efforts to fight the climate crisis, one section focused on pausing the issuance of new leases for oil and gas drilling on various federal lands. Section 208 of the Executive Order directs the Secretary of the Interior to “pause new oil and gas leases on public lands, or in offshore waters pending completion of a

In fact, only thirty percent of the onshore minerals in the United States belong to the federal government.29 Thus, seventy percent of the 29

minerals are open to private ownership or ownership by local/state governments. The thirty percent of land owned by the U.S. constitutes about 700 million acres of land.30 With the U.S. only controlling a minority of the mineral interests, the opportunity for regulation already seems slim. The situation looks worse when looking at how the 700 million acres of land are managed and used. Only about twenty six million acres of the discussed federal land were leased to oil and gas developers as of the end of the 2018 fiscal year.31 Within these twenty-six million acres, there are only 12.8 million acres that produce economic quantities of oil and gas.32 These 12.8 million acres constitute approximately 1.82 percent of the lands held by the U.S. which is not a large percentage. With being able to directly change only a small amount of the oil and gas production in the country, future change relies on the regulation and use of privately held minerals.

is a mecca for oil production with little regulation, the Texas Legislature recently passed meaningful legislation to help the environment.36

The future of federal regulation is currently on rocky ground. As the winds of power change in Washington D.C., the efforts to regulate the energy industry and carbon change as well. Conservative and liberal ideologies continue to clash on how to handle the issues of climate change and carbon emissions. As this issue continues to unfold, the United States governing authorities will face an uphill battle littered with obstacles as they try to find remedies and solutions to reach a carbon neutral future. Decisions will have to be made as to whether the government should focus on regulating oil and gas production on federal or privately held lands.

Class VI Injection wells are used to inject captured carbon dioxide back into the earth.39 Some may recognize this process as geologic sequestration.40 Given the increase of CO2 in the earth’s atmosphere, this method of capture could become a significant remedy in the future. Forms of technology like these wells are crucial to moving society forward. These sort of capture methods are estimated to be capable of capturing large amounts of carbon emissions. Some models have estimated that using wells for carbon dioxide storage could account for a quarter of what is needed to bring global warming under control.41 The world’s hydrocarbon reservoirs are estimated to be able to store 800 gigatonnes of carbon dioxide.42 Man-made emissions are estimated to be about 24 gigatonnes of carbon dioxide every year.43 Assuming a perfect world scenario, about five years’ worth of carbon dioxide emissions could be injected back into the earth for storage. Carbon capture through carbon injection wells could make a large impact in the race to reduce carbon emissions.

During the 87th state legislative session of 2021, Governor Greg Abbott signed legislation into law that granted the RRC sole jurisdiction over Class VI Injection Wells and Carbon Capture, Use, and Sequestration (“CCUS”) in Texas.37 These injection wells play a large role in reducing carbon emissions by injecting carbon dioxide (“CO2”) into the earth.38 This came as a shock to many environmental activists as Texas has a history of being a conservative state. Conservative states have a public perception of being less environmentally cautious with less regulation, as opposed to liberal states. The importance in this legislation comes from the role that Class VI Injection Wells play in the energy industry by allowing Texans to store carbon.

The State of Texas The State of Texas usually lies at the heart of oil and gas matters when discussing the United States of America. As of 2019, Texas holds “twofifths of the nation's crude oil proved reserves and crude oil production.”33 Texas even has over a quarter of the top 100 largest oil fields in the country.34 Much like other states, Texas has vested its regulating authority in a state agency, The Railroad Commission of Texas (RRC). The RRC has authority from the State of Texas to regulate the oil and gas industry as laid out in the Texas Constitution.35 Despite stereotypes and beliefs that Texas

While the passage of this legislation is a signal that Texas is ready to help carbon neutrality become a reality, it is not the last step for the Lone Star State. Texas must now apply for primacy over this new class of injector well.44 It is expected that 30

this process should take a year or two.45 Should the EPA approve this primacy as it has done with previous classes of wells, Texas would join Wyoming and North Dakota as being front runners of this phase of CCUS operations.46

changes to their policies to make the push to zero. These include fuel efficiency, flight efficiency, facility efficiency, and a carbon offset program that can be invested in.54 Another notable airline making changes is Delta Airlines (Delta). Delta has identified that 98% of their emissions come from aircraft and their operations.55 Because of these findings, fuel efficiency, sustainable fuel, and fleet renewal are some of the critical areas that Delta is focusing on.56 They are also focusing on their global impact through carbon reduction and stakeholder engagement in an effort to target emissions around the planet.57 While the airline industry’s two percent of emissions may seem like an insignificant amount, every percent counts as the world races to carbon neutral and zero emissions. If the airline industry continues its push, they easily could remain a front runner in the emissions race for years to come.

The passage of carbon capture legislation in Texas could be a signal that other states and countries might begin to legislate and regulate carbon capture in their own jurisdictions. It will be worth the time to keep an eye out to see what other forms of emissions regulations are enacted in Texas as the world continues its race to zero carbon emissions. Corporations The race to zero is not limited to just government entities. Corporations around the world are taking steps to enter the race, and they aim to win it. These companies are setting high goals and most of them have the capital to accomplish them. From the oil and gas industry to the aviation industry, the competitors entering the race is expanding.

With major corporations taking strides to join the race to zero, the goal could come into fruition much more quickly. Modern day society is driven by the corporate world and the need for money to flow through society. As corporations continue to enter the race, it is likely more funding will be brought into the picture that will allow the world to reach zero emissions and carbon neutral at incredible speeds.

British Petroleum (BP), the world’s fifth largest oil and gas company, took on a role as a pioneer in the race to be carbon neutral.47 BP was the first “supermajor” oil company to make a commitment to achieve net zero emissions by 2050.48 They have even proposed a shift from current energy projects to other projects, like renewable energy sources, that do not emit carbon dioxide.49 It has been estimated that the amount of emissions that BP plans to eliminate equal those of Britain.50 With a major oil and gas player like BP coming into the race, the oil and gas industry might be seeing a shift in ideology and culture to encourage more companies to compete.

Conclusion As the race to zero emissions continues, the world will change either by the side effects of climate change or the benefits of zero emissions. Technology will advance to help humanity race to protect the earth and safeguard it for our posterity. As countries, governments, states, and corporations participate in this race, the world will change, and society will change with it. Society should keep an eye on how the energy industry and the world changes as the race to carbon neutral continues.

The oil and gas industry is not the only one looking at their carbon footprint. The airline industry accounts for about two percent of the total human-induced carbon emissions.51 United Airlines (“United”) pioneered the aviation industry’s dive into the race to carbon neutral. In 2018 United became “the first U.S. airline to publicly commit to a carbon emissions reduction target.”52 Since then, United has set a goal of reducing emissions 100% by 2050.53 United has proposed numerous 31

Rebecca Lindsey & Luann Dahlman, Climate Change: Global Temperature, CLIMATE.GOV (Aug. 12, 2021), https://www.climate.gov/news-features/understanding-climate/climate-change-global-temperature#:~:text=According%20to%20the%202017%20U.S.,much%20as%2010.2% 20degrees%20warmer 2 The Effects of Climate Change, NASA, https://climate.nasa.gov/effects/ (last visited Apr. 19, 2022). 3 Fiona Harvey, Which country has made the biggest climate commitment, THE GUARDIAN (Apr. 23, 2021 04:41 AM), https://www.theguardian.com/environment/2021/apr/23/which-country-has-made-the-biggest-climate-commitment. 4 Counties in the World, WORLDOMETER, https://www.worldometers.info/geography/how-manycountries-are-there-in-the-world/#:~:text=Countries%20in%20the%20World%3A&text=There%20are%20 195%20countries%20in,and%20the%20State%20of%20Palestine (Last visited Apr. 19, 2022). 5 Current World Population, WORLDOMETER, https://www.worldometers.info/world-population/ (Last visited Apr. 19, 2022). 6 Which country has made the biggest climate commitment?, supra note 3. 7 Id. 8 Press Release, Department for Business, Energy & Industrial Strategy, Prime Minister's Office, 10 Downing Street, The Rt Hon Kwasi Kwarteng MP, The Rt Hon Alok Sharma MP, & The Rt Hon Boris Johnson MP, UK enshrines new target in law to slash emissions by 78% by 2035 (Apr. 20, 2021), https://www.gov.uk/government/news/uk-enshrines-new-target-in-law-to-slash-emissions-by-78-by-2035. 9 Id. 10 As of 2017, a great portion of the global emissions were emitted from a handful of government entities. Hannah Ritchie & Max Roser, CO2 emissions, OUR WORLD IN DATA, https://ourworldindata.org/co2-emissions#co2emissions-by-region (last visited Apr. 19, 2020). China clocked in at 27%, the United States at 15%, the European Union at 9.8%, India at 6.8%, and the Russian Federation at 4.7%. Id. Asia accounts for 53% of carbon emissions, North America for 18%, Europe for 17%, Africa for 3.7%, South America for 3.2%, and Oceania for 1.3%. Id. 11 Harvey, supra note 3. 12 Id. 13 The European Union – What it is and what it does, PUBLICATIONS OFFICE OF THE EUROPEAN UNION, https://op.europa.eu/webpub/com/eu-what-it-is/en/ (Last visited Apr. 19, 2022). 14 Id. 15 Id. 16 Harvey, supra note 3. 17 A European Green Deal, EUROPEAN COMMISSION, https://ec.europa.eu/info/strategy/priorities-2019-

2024/european-green-deal_en (Last visited Apr. 19, 2022). “The European Green Deal” goes beyond setting goals for just reducing carbon emissions. The EU aims to reduce emissions as well as create jobs, create growth, address energy poverty, reduce eternal energy dependency, and improve health and wellbeing. Delivering the European Green Deal, EUROPEAN COMMISION, https://ec.europa.eu/info/strategy/priorities-2019-2024/european-greendeal/delivering-european-green-deal_en#transforming-oureconomy-and-societies (last visited Apr. 19, 2022). These goals have been set to include vulnerable citizens by ensuring that there are opportunities for everyone. Id. The expansive program will touch all parts of society in the EU. 18 FACT SHEET: President Biden Sets 2030 Greenhouse Gas Pollution Reduction Target Aimed at Creating GoodPaying Union Jobs and Securing U.S. Leadership on Clean Energy Technologies, THE WHITE HOUSE BRIEFING ROOM (Apr. 22, 2021), https://www.whitehouse.gov/briefing-room/statements-releases/2021/04/22/fact-sheet-president-biden-sets-2030-greenhouse-gas-pollution-reductiontarget-aimed-at-creating-good-paying-union-jobs-and-securing-u-s-leadership-on-clean-energy-technologies/. 19 Exec. Order No. 14008, 86 Fed. Reg. 7,619 (Feb. 1, 2021). 20 Louisiana v. Biden, 543 F. Supp. 3d 388, 396 (W.D. La. 2021). 21 Id. at 397. 22 Id. at 396. 23 Id. 24 Id. at 413. 25 Id. at 419. 26 Id. 27 Hobart M. King, Mineral Rights, GEOLOGY.COM, https://geology.com/articles/mineral-rights.shtml (last visited Apr. 19, 2022). 28 Id. 29 About the BLM Oil and Gas Program, U.S. DEP’T OF THE INTERIOR BUREAU OF LAND MANAGEMENT, https://www.blm.gov/programs/energy-and-minerals/oiland-gas/about (last visited Apr. 19, 2022). 30 Id. 31 Id. 32 Id. 33 Texas State Energy Profile, U.S. ENERGY INFORMATION ADMINISTRATION (Apr. 15, 2021), https://www.eia.gov/state/print.php?sid=TX. 34 Id. 35 About Us, TX RAILROAD COMMISION, https://www.rrc.texas.gov/about-us/#:~:text=The%20Railroad%20Commission%20of%20Texas%20(Commission)%20is%20the%20state%20agency,and%20uranium%20surface%20mining%20operations (last visited Apr. 19, 2022). 36 Madeline Thomas, New Legislation Signals Strong Support for Carbon Capture, Use, and Sequestration in Texas, ENERGY LAW ADVISOR (Nov. 2021),

Marshall Geck, Seven major companies that committed to net-zero emissions in 2020, PRINCIPLES FOR RESPONSIBLE INVESTMENT (Dec. 15, 2020), https://www.unpri.org/pri-blog/seven-major-companies-that-committed-tonet-zero-emissions-in-2020/6909.article. 49 BP, one of the world’s biggest oil-and-gas companies, says it is turning over a green leaf, supra note 48. 50 Id. 51 Fuel efficiency and emissions reduction, UNITED AIRLINES, https://www.united.com/ual/en/us/fly/company/global-citizenship/environment/fuel-efficiency-andemissions-reduction.html (last visited Apr. 19, 2022). 52 Id. 53 Id. 54 Id. 55 Delta commits $1 billion to become first carbon neutral airline globally, DELTA AIRLINES (Feb 14, 2020 7:00am), https://news.delta.com/delta-commits-1-billionbecome-first-carbon-neutral-airline-globally. 56 Id. 57 Id.

https://www.cailaw.org/media/files/IEL/Publications/2021/november/Thomas.pdf. 37 Id. 38 Id. 39 Id. 40 Id. 41 Storing CO2 Underground, IEA GREENHOUSE GAS R&D PROGRAMME (May 2007), https://ieaghg.org/docs/general_publications/storingCO.pdf. 42 Id. 43 Id. 44 New Legislation Signals Strong Support for Carbon Capture, supra note 38. 45 Id. 46 Id. 47 Steven Mufson, BP, one of the world’s biggest oil-andgas companies, says it is turning over a green leaf, THE WASHINGTON POST (Feb. 12, 2020), https://www.washingtonpost.com/climate-environment/2020/02/12/1a867124-4da4-11ea-bf44f5043eb3918a_story.html.

The Most Important Figure You’ve Never Heard Of: It’s Time to Readdress the Discount Factors Inherent in the Social Cost of Greenhouse Gas Emissions By: Neil Segel, J.D. University of Houston Law Center

capability have yielded increasingly more accurate assessments of the long-term climate-related ramifications of the rulemaking process. Nevertheless, policymakers are still seeking to determine the most accurate calculation of the long-term societal value of increasing or reducing a certain GHG’s emissions. Using various integrated assessment models (IAMs) to determine this value, the social cost encompasses a number of climate change impacts, such as property damage from the increased risk of natural disasters and flooding, future damage to human health, potential disruptions to energy production, detrimental changes in agricultural productivity, increased risk of conflict, risk of environmental migration, and the value of “ecosystem services.”7 A core component of the existing and proposed emissions damage models is the discount rate that is applied to calculate the present value of future expected damages.8 The notion of discounting refers to the process by which costs and benefits spread over current and future years can be compared in order to determine whether a particular choice in the present leads to an overall net benefit in the future. The discount rate refers to the reduction (“discount”) in value each year as a future cost or benefit is adjusted for comparison with a current cost or benefit. The uncertainty surrounding the climate damage discount rate has been labeled “arguably the most important uncertainty of all in the economics of climate change.”9 The reason for this is that because of the long residency times of GHGs in earth’s atmosphere, the damaging effects that present emissions will have in the future on subsequent generations needs to be calculated and expressed in today’s dollars as a cost that federal agencies can effectively incorporate into their cost-benefit analyses. The higher the discount rate, the lower costs that accrue to future generations are weighted, resulting in a lower SC-GHG estimate, and vice-versa. One of the most troubling aspects of employing a discount rate at any one point in time to value all future cash flows is the fact that interest rates and risk profiles are constantly changing in a dramatic way. The application of a particular discount rate to a cost-benefit analysis is at its peak accuracy only on the day of its calculation – once embedded into policy it may no longer be

“It’s the most important figure you’ve never heard of."1 I.

AGENCY COST-BENEFIT ANALYSES AND THE SOCIAL COST OF GREENHOUSE GASES

With the stroke of his pen in 1981, President Ronald Reagan signed Executive Order 12291, mandating that all new federal regulations undergo a cost-benefit analysis. This analysis has since come to entail “the systematic examination, estimation, and comparison of the potential economic costs and benefits resulting from the promulgation of a new rule.”2 Given that federal agencies with rulemaking authority implement regulations that carry the force of law, Congress seeks to hold these agencies accountable to the electorate for their actions, and one such way has been through requiring agencies to demonstrate reasoned consideration of their proposed rules. Since 1981, the requisite level of analysis has evolved3 as scientific and socio-economic insights have matured, allowing policymakers to incorporate increasingly more quantitative factors into their analyses. As a result of several landmark court 4 cases , one of the latest factors that has been incorporated into regulatory analysis is the social cost of greenhouse gases (SC-GHGs),5 which enables agencies to understand the long-term social costs or benefits of either increasing or decreasing the GHG emissions that will occur as a result of policymaking. The SC-GHG reflects “the monetary value of the net harm to society associated with adding a small amount of that GHG to the atmosphere in a given year.”6 This cost is not simply an administrative checkmark – it involves far-reaching financial consequences across the public and private sectors. Over the last few decades, evolutions in climate comprehension and modeling 34

reflected in [agency] analysis.”13 Furthermore it instructed that the ending point of the effects considered in an analysis “should be far enough in the future to encompass all the significant benefits and costs likely to result from the rule.”14 Recognizing that costs and benefits could be incurred very far into the future, the guidance instructed that “the further in the future the benefits and costs are expected to occur, the more they should be discounted.”15 The consequence of this particular guidance is not well-appreciated. Extrapolation of discounted annual damages associated with different discount rates demonstrates that for a given pattern of GHG emission related damages, the present social cost is significantly higher for low discount rates and the modeling horizon needed to include most of the discounted damages varies drastically based on the discount rate.16 [See: Figure 1].17

reflective of an evolving economic situation. A substantial number of economic research papers have sought to ascertain the most accurate discount rates and stochastic discount factors10 to apply in long-run discounting formulae. Until such point that climate damage modeling and economic forecasting can achieve a near-perfect accuracy of long-run (i.e., 100+ year) forecasting, there is an urgent need within the government to establish an authority that can advise on the state-of-the-art calculations to be employed at any particular time an agency analysis is warranted. This paper therefore advocates for the establishment of an entirely new government agency, namely the Advanced Research Projects Agency – Climate (ARPA-C). This new agency should be tasked, inter alia, with continuously maintaining a state-of-the-art IAM that accurately reflects the latest understanding of a climate science-based discount rate, taking into account both domestic and global considerations. II.

ASCERTAINING AN APPROPRIATE DISCOUNT RATE FOR CLIMATE DAMAGES

In 2003, the OMB issued Circular A-4 as a non-binding guidance to federal agencies to ensure a standardized way of measuring and reporting the costs and benefits of federal regulatory actions. Circular A-4 suggested 3% and 7% discount rates regarding the domestic effects of agency actions. The 7% rate reflected an estimate of the average before-tax rate of return to private capital in the U.S. economy. Circular A-4 implored agencies to use this discount rate “whenever the main effect of a regulation is to displace or alter the use of capital in the private sector.”11 The 3% rate was suggested to be applied to regulation primarily and directly affecting private consumption. This rate reflected the social rate of time preference, namely the rate at which society discounted future consumption flows to their present value, to be determined by assessing the real rate of return on long-term government debt. In 2003, when Circular A-4 was published, the prior 30 years from 1973 to 2003 revealed 3% in real terms on a pre-tax basis.12 Complementary to the suggested discount rates, Circular A-4 also advised that “If benefits or costs are delayed or otherwise separated in time from each other, the difference in timing should be

Figure 1. Discounted future damages from one ton of CO2 emitted in 2015 dollars. The most discounted impacts are captured by ~2150 when the discount rate is 5%. However, a significant amount of discounted damages may be missed even with a 300-year horizon when the discount rate is 2.5%.17

One notable aspect of Circular A-4’s guidance that has been overlooked in historical agency analysis since its issuance is the ethical consideration it suggests should be given to intergenerational costs and benefits: “It may not be appropriate for society to demonstrate [time] preference when deciding between the well-being of current and future generations.”18 As a result, the guidance states that it would be appropriate to “consider a further sensitivity analysis using a lower but positive discount rate” between 1% and 3%.19 Given the well-documented long-lasting effects of present emissions, the vast majority of agency rulemaking has intergenerational implications. Prior and subsequent to Circular A-4’s publication, there have been a number of attempts 35

at modeling an accurate and appropriate discount rate for emissions damages. The most noteworthy publications and integrated assessment models (IAMs) include the Stern Review,20 the DICE model,21 the FUND model22, and the PAGE model.23 All of these IAMs approach the climate damage modeling framework differently, but all generally assume an appropriate discount rate of approximately 2.5% to 6%. Only Stern calls for immediate action to reduce future environmental damage based on the assumption of exceptionally low discount rates (from 0.1% to 2%), arguing that while agents may discount the future during their lifetimes, they have an ethical obligation to care about future generations and thus discount them less. Stern’s theory has been criticized by notable climate economists including Martin Weitzman and William Nordhaus, who both argue that discount rates should strictly reflect markets’ private return to capital. In a separate report on very longrun discount rates, several economists provided direct empirical evidence comparing long-run climate discount rates and long-run real property discount rates and found comparable real property discount rates to be a viable proxy for climate modeling, with a suggested discount rate around 2.6%.24 The academic evidence and literature have steadily begun converging around the lower-bound discount rate, and several states, such as New York and Washington have begun to adopt discount rates as low as 2%.25 Given the latest economic growth predictions, the past rationale for using a previously low rate of 2.5% is not as valid as it was previously thought to be, as modeling has been able to better address uncertainty. In February 2021, the Interagency Working Group (IWG) on the SC-GHG announced that “the range of...SCGHG estimates...likely underestimate societal damages from GHG emissions.”26 Their report acknowledged that long-term forecasts for real rates of return on 10-year Treasury securities will likely average 1.2% over the next 30 years, suggesting that “the appropriate consumption discount rate should be at most 2%.”27 In querying hundreds of academics and economists on this lower estimate, surveys revealed a “surprising degree of consensus among experts, with more than threequarters finding the median risk-free social discount rate of 2% acceptable.”28

Even with the science at a point where experts are able to converge on a focal point between 2% and 4%, policymakers remain unconvinced. While haggling over such minute percentage differences may seem superfluous, the variability even between these numbers is astounding in terms of a dollar amount discounted into the long-term. As Figure 229 and Figure 330 reveal, looking only at the mean numerical outputs, a 2% difference in constant discounting can yield a $62 difference per ton of CO2, and a mere 1% difference in stochastic discounting can yield a $115 difference per ton of CO2 – a substantial number in this context. Given that climate science deals with a variety of unknown and indeterminate variables, it is unlikely that present scientific capacity will enable a more precise determination that can be universally accepted and applied towards an indefinite future timespan. Therefore, this paper proposes that ARPA-C should continuously maintain a state-of-the-art IAM that accurately reflects the latest understanding of a climate change-based discount rate. A good baseline for the IWG to propose to ARPA-C would be the climate prediction model proposed by the National Academies of Sciences, Engineering, and Medicine, which proposed a model based on four core modules: 1) socioeconomics (covering probabilistic projections of population, gross domestic product, and emissions over multiple centuries; 2) climate (entailing an improved model of Earth’s climate system and climate change); 3) damages (assessing the economic consequences of climate change, based on recent studies), and; 4) discounting (applying aggregated present-value marginal damages and stochastic discount factors that correctly reflect the uncertain socioeconomic drivers).31

Figure 2. Discounted future damages from one ton of CO2 emitted in 2020 dollars at specified discount rates. In 2020 dollars the average SCC is $14 using a 5% discount rate, $51 using a 3% rate and $76 using a 2.5% rate. The fourth value of 3% (95th percentile) represents higher-than-expected economic impacts from climate change further out in the tails of the SCC distribution.29

III.

Figure 3. Discounted future damages from one ton of CO2 emitted in 2020 dollars using stochastic discounting. In 2020 dollars the average SCC is $56 using a 3% rate and $171 using a 2% rate.30

the IWG SC-GHG estimates were contrary to the law in that they directed agencies to consider factors not authorized by Congress and granted an injunction against the federal government. However, the injunction was stayed on appeal to the Fifth Circuit.34 As a result, the Biden administration is currently able to employ the SC-GHG estimates while the underlying litigation pertaining to the merits of the estimates is unresolved. With no controlling final agency action in place, agency analysis remains in limbo, and a global analysis is no more necessary than a domestic analysis, at whatever discount rate the agency reasonably chooses to employ. The IWG has mounted a strong case for a global approach, one that should be adhered to by final agency action and ARPA-C. The IWG stated that the A-4’s guidance in regard to focusing on impacts to U.S. citizens and residents “is different than recommending that analysis be limited to the impacts that occur within the borders of the U.S.”35 Addressing the diverse ways in which U.S. interests, businesses, and residents may be impacted by climate change beyond U.S. borders, the IWG noted “the global nature of GHGs means that U.S. interests, and therefore the benefits to the U.S. population of GHG mitigation, cannot be defined solely by the climate impacts that occur within U.S. borders... [otherwise] estimates would underestimate the benefits of GHG mitigation accruing to U.S. citizens and residents.”36 The obvious extension of American interests worldwide and the diffuse nature of earth’s atmosphere mean that the effects of domestic GHG emissions affect American interests worldwide, and therefore to consider only

TOWARDS A LASTING & COMPREHENSIVE SOLUTION

While there is consensus that a 2% or slightly lower discount rate should prevail, what remains unclear is the extent to which governmental agencies must consider domestic versus global costs and benefits of agency action, the government authority under which this rate should be housed and enforced by, and the extent to which the global community should rely on this model framework. Under Circular A-4, agencies were directed to consider only the domestic effects of actions to be the basis of agency analysis. Compliance with Circular A-4 wasn’t required by any statute or regulation and remains without any binding effect on any agency, causing this lens of analysis to vacillate under presidential administrations and their politics, leading to a predictable degree of uncertainty. In several recent cases, federal courts have directed federal agencies to exclusively consider domestic, rather than global, costs and benefits when weighing new agency regulations, citing a risk of a finding of arbitrary and capricious agency action when global effects are considered.32 In the latest challenge to the SCGHGs, the plaintiff states claimed the IWG’s interim estimates would lead to increased regulatory burdens when agencies conduct cost-benefit analyses, and therefore brought several challenges to the interim estimates pursuant to the Administrative Procedures Act.33 The District Court held that 37

domestic effects would be to grossly understate long-term effects of agency action. With no firm, inter-presidential agency guidance framework in place37, the partisan nature by which the American public and its elected government see changing climate patterns affecting their livelihood and government action means that the discounted present value of future agency action remains economically uncertain. This uncertainty is a disservice not only to present society, but to future generations that will increasingly suffer the consequences of a changing climate without a financial safety net due in part to inadequate foresight and governmental action. Congress should establish ARPA-C as soon as reasonably possible and should delegate to it and the Department of Treasury the responsibility for continuously maintaining a state-of-the-art IAM that accurately reflects the latest understanding of a climate change-based discount rate. This IAM should take into account both domestic and global considerations and should employ a discounting rule that relates the discount rate to economic growth rates in a method that consistently represents their joint uncertainty. The ARPA-C and the Department of Treasury should thereafter jointly publish an annually updated discount rate to be applied across all federal agency rulemaking and cost-benefit analyses in that respective year, based on the latest IAM data. All U.S. federal agencies should then issue annually updated

regulations concerning the discount factor employed on all cost-benefit analyses in line with ARPA-C’s model. The question we need to ask ourselves now is not whether or not agencies ought to factor in the SC-GHGs, but rather, as economist William Nordhaus suggests, “how much and how fast should we react to the threat of global warming?”38 Given the Security and Exchange Commission’s March guidance for publicly traded companies to begin incorporating climate impact and GHG emissions into their public disclosures, the need for accurate modeling and discounting is stronger than ever. The compounding effect of the damages combined with the time value of money means that that as days continue to pass without adequately accounting for damages of present GHG emissions, the long-term consequences become increasingly more dire. The sooner that the United States can construct more accurate cost-benefit analyses using a transparent, science-based, standardized approach to discounting, the sooner the world can follow. “The only way to achieve an efficient allocation of resources for emissions reduction on a global basis is for all countries to base their policies on global estimates of damages.”39 Recognizing this, it is imperative that Congress authorize ARPA-C and begin planning for the future based on complete picture of the present.

standardized way of measuring and reporting the benefits and costs of Federal regulatory actions. A-4’s fundamental tenets called for 3% and 7% discount rates, and for the domestic effects of actions to be the basis of agency analysis. In 2009, President Obama convened an Interagency Working Group (IWG) to establish estimates of the social cost of carbon (SCC) that all agencies were to use in their regulatory cost/benefit analyses. In 2010, the IWG presented final SCC estimates using Circular A-4 as its starting point but rejected the proposed discount rates of 3% and 7%, and analysis of only the domestic effects. The IWG agreed on a SCC of $52/ton in 2020 dollars, and in 2016, they issued estimates for the Social Cost of Methane ("SCM") and the Social Cost of Nitrous Oxide ("SCN"). In 2017 President Trump disbanded the IWG under EO 13783, and thereafter EPA changed assumptions in calculating the SCC – including only domestic damage (rather than global damage) and using a higher discount rate to convert future damages to present value. As a consequence, under the EPA’s new calculation the SCC dropped to between $1 and $7/ton. In 2021: President Biden reinstated the IWG through EO 13990, directing federal agencies to "capture the full costs

Michael Greenstone (Professor in Economics & Director of the Becker Friedman Institute and the Energy Policy Institute at the University of Chicago; Previously, Greenstone was the Chief Economist for President Obama’s Council of Economic Advisers where he co-led the development of the US Government’s efforts to determine the social cost of carbon). 2 DAVID PERKINS AND MAEVE CAREY, CONG. RESEARCH SERV. R44813, COST-BENEFIT ANALYSIS AND FINANCIAL REGULATOR RULEMAKING (2017). 3 A brief synopsis of this evolution since EO 12291 is as follows: In 1993, President Clinton signed EO 12866, requiring agencies, “to the extent permitted by law and where applicable...to assess both the costs and the benefits of the intended regulation and, recognizing that some costs and benefits are difficult to quantify, propose or adopt a regulation only upon a reasoned determination that the benefits of the intended regulation justify its costs.” In 2003, the Office of Management and Budget (OMB) issued Circular A-4 as guidance to Federal agencies on the development of regulatory analysis as required under Section 6(a)(3)(c) of Executive Order 12866 to implement and ensure agencies use a

OFFICE OF MGMT. & BUDGET, EXEC. OFFICE OF THE PRESIDENT, OMB CIRCULAR A-4, REGULATORY ANALYSIS (2003), 31. 14 Id. 15 Id. at 32. 16 See generally: NAT’L ACAD. OF SCI., ENG’G, & MED. VALUING CLIMATE DAMAGES: UPDATING ESTIMATION OF THE SOCIAL COST OF CARBON DIOXIDE (2017). 17 Id. at 35. 18 Id. 19 Id. at 36. 20 NICHOLAS STERN, THE ECONOMICS OF CLIMATE CHANGE: THE STERN REVIEW (2007). 21 WILLIAM NORDHAUS & PAUL SZTORC, DYNAMIC INTEGRATED CLIMATE-ECONOMY (DICE MODEL) 2013R: INTRODUCTION AND USER’S MANUAL (2013). 22 First presented as: Richard Tol, The Climate Framework for Uncertainty, Negotiation and Distribution (FUND Model), in AN INSTITUTE ON THE ECONOMICS OF THE CLIMATE RESOURCE, (K. Miller & R. Parkin eds., 1996), 471– 496. (Subsequent versions are attributed to multiple contributors). 23 First presented as: Erica Plambeck, Chris Hope & John Anderson, The Policy Analysis of the Greenhouse Effect (PAGE) 95 Model: Integrating the science and economics of global warming, in ENERGY ECONOMICS 19 (1997), 77– 101. (Subsequent versions are attributed to multiple contributors). 24 STEFANO GIGLIO, MATTEO MAGGIORI, JOHANNES STROEBEL, VERY LONG-RUN DISCOUNT RATES, FED. RESERVE BANK OF DALLAS – GLOBALIZATION AND MONETARY POL’Y INST. WORKING PAPER NO. 182 (MAY 2014) 4. 25 In December 2020, New York issued guidance recommending state agencies use SC-GHG estimates of 2% in central scenarios ($125/mtCO2 for 2020 emissions (2020 dollars), along with sensitivity analysis at 1% and 3%. Similarly, Washington state in 2019 began requiring utilities to use estimates based on the IWG methodology with a 2.5% discount rate when developing “lowest-cost analyses” for its integrated resource planning and clean energy plans. (See: KEVIN RENNERT, BRIAN PREST, WILLIAM PIZER, ET AL. “THE SOCIAL COST OF CARBON: ADVANCES IN LONG-TERM PROBABILISTIC PROJECTIONS OF POPULATION, GDP, EMISSIONS, AND DISCOUNT RATES,” BPEA CONFERENCE DRAFTS, (SEPT. 2021) 35). 26 Technical Support Document: Social Cost of Carbon, Methane, & Nitrous Oxide Interim Estimates under Executive Order 13990, Interagency Working Group on Social Cost of Greenhouse Gases (Feb. 2021) 4. 27 Id. at 20. 28 Moritz Drupp, Mark Freeman, Ben Groom, & Frikk Nesje, “Discounting Disentangled,” 10 AM. ECON. J.: ECON. POL’Y 4 (2018) 109-134. 29 Technical Support Document: Social Cost of Carbon, Methane, & Nitrous Oxide Interim Estimates under Executive Order 13990, Interagency Working Group on Social Cost of Greenhouse Gases (Feb. 2021) 7. 30 KEVIN RENNERT, BRIAN PREST, WILLIAM PIZER, ET AL. “THE SOCIAL COST OF CARBON: ADVANCES IN LONG-TERM PROBABILISTIC PROJECTIONS OF POPULATION, GDP,

of greenhouse gas emissions as accurately as possible, including by taking global damages into account." This mandate was subsequently challenged in federal courts, but in March 2022 the U.S. Court of Appeals for the 5th Circuit unanimously stayed a lower court’s order blocking the federal government from calculating the SCC and incorporating it into agency cost-benefit analyses. As of May 12, 2022, agencies are actively employing the 2010-2016 IWG estimates, and the latest IWG report is pending publication. 4 The U.S. Supreme Court ruled in Mass. v. EPA, 549 U.S. 497 (2007), that carbon dioxide and GHG emissions from motor vehicles are air pollutants under the Clean Air Act because “they may reasonably be anticipated to endanger public health or welfare,” and therefore must be regulated by the EPA; The 9th Circuit Court of Appeals in Ctr. for Biological Diversity v. Nat'l Highway Traffic Safety Admin., 538 F.3d 1172 (2008) remanded a fuel economy rule to DOT for failing to monetize CO2 emission reductions, stating that “while the record shows that there is a range of values, the value of carbon emissions reduction is certainly not zero.” 5 The SC-GHG encompasses three GHG’s: the social cost of carbon (SC-CO2), the social cost of methane (SC-CH4), and the social cost of nitrous oxide (SC-N2O), each of which has a different atmospheric residence time, ranging from decades to centuries, hence the need for long-term probabilistic climate damage modeling. 6 Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order 13990, Interagency Working Group on Social Cost of Greenhouse Gases, (Feb. 2021) 2. 7 Ecosystem services refers to the various outputs, conditions, or processes of natural systems that directly or indirectly benefit humans or enhance social welfare. 8 The calculation of the present value of future expected damages looks something like this: E(SC-GHG) = E[∑! "#$∗ SDFt ∗ MDt], such that the expected present value (E) of the social cost of a particular GHG is equal to the expected value of the present sum (to infinity) times a determinate discount factor or a stochastic (random) discount factor times the marginal damages from an incremental ton of emissions at present. 9 Martin Weitzman, A Review of The Stern Review on the Economics of Climate Change, XLV J. ECON. LITERATURE (2007) 703-724, 705. 10 A stochastic discount factor is a time-dependent random variable, allowing economists to input a "state of the world" and a time period and obtain from a mathematical formula the appropriate discount rate. 11 OFFICE OF MGMT. & BUDGET, EXEC. OFFICE OF THE PRESIDENT, OMB CIRCULAR A-4, REGULATORY ANALYSIS (2003), 33. 12 This was determined by analyzing historical yields on 10year Treasury notes (which averaged 8.1% from 1973 to 2003) and subtracting from that the average annual rate of change in the consumer price index (CPI) over the same period (which was 5.0%) to obtain a real 10-year growth rate of 3.1%.

EMISSIONS, AND DISCOUNT RATES,” BPEA CONFERENCE DRAFTS, (SEPTEMBER 2021) 40. 31 See: NAT’L ACAD. OF SCI., ENG’G, AND MED. VALUING CLIMATE DAMAGES: UPDATING ESTIMATION OF THE SOCIAL COST OF CARBON DIOXIDE (2017). 32 See: State v. United States DOI, 493 F. Supp. 3d 1046, 1080 (D. Wyo. 2020) (citing OMB Circular A-4, which “directs an agency to focus its analysis "on benefits and costs that accrue to citizens and residents of the United States;" and where an agency chooses to evaluate a regulation that is "likely to have effects beyond the borders of the United States, these effects should be reported separately."). See also: States v. Bureau of Land Mgmt., 286 F.Supp.3d 1054, 1069 (N.D. Cal. 2018) ("While Plaintiff argue that the same Circular directs BLM to encompass 'all the important benefits and costs likely to result from the rule,' including 'any important ancillary benefits,' it does not specifically mandate that agencies consider global impacts."). 33 Louisiana v. Biden, No. 2:21-CV-01074, 2022 U.S. Dist. LEXIS 25496, at *30-31 (W.D. La. Feb. 11, 2022). (The Plaintiff States asserted three claims under the APA: “First, they claim that the defendants violated the APA by failing to comply with the notice-and-comment procedures required by 5 U.S.C. § 553. Second, they claim that the Defendants failed to engage in reasoned decision making rendering the SC-GHG Estimates arbitrary and capricious under 5 U.S.C. § 706(2)(A). Third, they claim that the SCGHG Estimates contravene the Energy Policy and Conservation Act ("EPCA"), Clean Air Act ("CAA"), National Environmental Policy Act ("NEPA"), Mineral Leasing Act ("MLA"), and Outer Continental Shelf Lands Act ("OCSLA") by directing agencies to consider the global effects of greenhouse gas emissions.”). 34 State v. Biden, No. 22-30087, 2022 U.S. App. LEXIS 7589 (5th Cir. Mar. 16, 2022). (The Fifth Circuit Court of Appeals granted the Government Defendants' motion to stay the preliminary injunction pending appeal after finding that that the Plaintiff States lacked standing, their claims were not ripe, and that the interim estimates were not final agency action under the APA.) 35 Technical Support Document: Social Cost of Carbon, Methane, & Nitrous Oxide Interim Estimates under Executive Order 13990, Interagency Working Group on Social Cost of Greenhouse Gases (Feb. 2021) 15. 36 Id. 37 As of this writing, May 12, 2022. The current IWG was set to release revised guidelines in the Spring of 2022, but has not yet done so. 38 William, Nordhaus, A Review of the Stern Review on the Economics of Climate Change, 45 J. OF ECON. LITERATURE, 3 (2007) 686-702, 686. 39 Technical Support Document: Social Cost of Carbon, Methane, & Nitrous Oxide Interim Estimates under Executive Order 13990, Interagency Working Group on Social Cost of Greenhouse Gases (Feb. 2021) 16.

strongly favored small tracts.1 In 1961, the Texas Supreme Court decided Atlantic Ref. Co. v. Railroad Comm’n2 (known as the Normanna decision). The Court invalidated the Commission’s proration formula, stating that it was unreasonable and did not give the field producers their fair share of the gas.3 In the Normanna decision, the Commission’s proration formula allocated production by onethird per well and two-thirds for the total acreage the owner had.4 Additionally, Halbouty v. Railroad Comm’n5 (known as the Port Acres decision) was decided a year later. In Port Acres, the Texas Supreme Court came to the same conclusion as in Normanna, that the Commission’s one-third and two-thirds proration formula was invalid because it did not allow all of the tract owners to produce their fair share.6 Further, in Railroad Com. of Texas v. Shell Oil Co. the Court invalidated the Commission’s oil production formula set on the basis of fifty percent per well and fifty percent on the land designated to the well.7 Its decision was based on the principles established in the Normanna case.8 Essentially, the Court’s reasoning in these cases was that letting one tract owner within a common reservoir produce more oil and gas than is beneath their tract of land strips another owner’s fair chance to produce what is below their tract.9 Voluntary pooling could have helped to negate the issue of large-tract owners’ oil and gas being overly drained by adjacent small-tract owners. Though, prior to 1961, there was not any enticement for small-tract owners to pool with larger adjacent tracts. Under Rule 37 exceptions, smalltract owners were allowed to drill their own wells and granted production allocation that far exceeded the amount of oil and gas under their land.10 Voluntary pooling agreements would not have benefited small-tract owners as largely as drilling their own wells. Hence, before the Normanna and Port Acres decisions, small-tract owners were not in support of a compulsory pooling statute in Texas.11 However, after those decisions, smalltract owners offered unwavering support to the MIPA.12 The change in position of small-tract owners is easily reconciled consideringthe effect of the Normanna and Port Acres decisions. Before the MIPA’s enactment, small-tract owners had two options. One, they could persuade adjacent landowners to enter into a pooling agreement, or two, the small-tract owner could allow his oil and gas to

The Texas Mineral Interest Pooling Act: An Analysis of Its Recent Application in District Eight of the Railroad Commission and the Future Implications of the Commission’s Orders By: Nolan Wleczyk, J.D. South Texas College of Law Houston Introduction In 1965, the Mineral Interest Pooling Act (“MIPA”) was enacted and works as Texas’ compulsory pooling statute. While the statute gave the Railroad Commission of Texas (“RRC”) authority to compulsory pool, it does not operate how a person may expect. It gave limited authority for the Commission to force pool neighboring tract owners. The MIPA was enacted indirect response to Texas Supreme Court decisions affecting smalltract owners in the early 1960’s that greatly changed oil and gas law. Additionally, the Act was established for the purpose of encouraging mineral interest owners to voluntarily pool with each other. Initially, this paper addresses what influenced MIPA, how the MIPA interacts with mineral interest owners, the Commission’s authority, and the goals of the statute. Next, it covers the statutory requirements for eligiblility for a compulsory pooling order. Including the basic requirements created by the statute, requirements established by court decisions, and limitations on the Commission. Specifically, it discusses the requirement of mineral interest owners that made the MIPA different from other compulsory pooling statutes – to have made a fair and reasonable offer to voluntarily pool. Further, it explores how the MIPA has been used in horizontal and hydraulic fractional drilling, and how the statute has been applied under such circumstances. Finally, it discusses issues presented in recent MIPA applications and the potential impact those decisions will have in future use of the MIPA. II. Background – The Creation of the Texas Mineral Interest Pooling Act The Texas Legislature enacted the MIPA in 1965 as a response to case decisions that invalidated Commission allocation formulas that 41

be drained by the adjacent larger tracts.13 Thus, the Texas Legislature quickly responded with the enactment of the MIPA to protect small-tracts from the wake of these decisions.14 Under the MIPA, the Commission may force pool adjacent tracts of land if the requirements are met.15 However, the MIPA is viewed more as an Act meant to encourage voluntary pooling.16 There is a required voluntary pooling offer, discussed in Part III(A), that applicants must satisfy before the Commission can make a pooling order.17 Satisfying that requirement sets the MIPA apart from similar statutes and characterizes the Act as “an Act to encourage voluntary pooling . . . .”18 As discussed later, the statutory requirements push applicants to reach an agreement without the Commission’s influence. Furthermore, the purpose of MIPA goes beyond encouraging voluntary pooling; that is, the Act should be read to heavily favor small-tract owners and lessees.19 IV.

create a pooled unit, an applicant must have made a voluntary pooling offer, and the offer must have also been valid under the statutory requirements. The statutory requirements for a valid offer is discussed below. The requirements in section 102.01126 must be satisfied to create a MIPA unit. There must be “two or more separately owned tracts of land” within a common oil or gas reservoir.27 The Commission must have established the proration units by permanent or temporary field rules.28 Additionaly, the separately owned interests in the existing or proposed proration unit must have not agreed to voluntary pool, and at least one owner needs to have drilled or proposed to drill within the proration unit.29 If all the requirements are satisfied, the Commission must grant the compulsory pooling order.30 A. Applicant Requirements

Application for a pooling order is limited to certain mineral interest owners. These interest owners are: 1) owners of any interest in oil and gas within an existing proration unit or with respect to a proposed unit; 2) owners of any working interest; or 3) any owner of an unleased tract other than a royalty owner.31 Further, applicants are required to make voluntary pooling offers to the owners of the tracts with which they wish to pool. This requirement makes Texas’ compulsory pooling statute unique. The MIPA is often considered to encourage voluntary pooling instead of compulsory pooling.32 Section 102.013 of the Texas Natural Resource Code encourages voluntary pooling in two respects. First, applicants are required to “set forth in detail the nature of voluntary pooling offers made to the owners of the other interest in the proposed unit.”33 Second, the Commission is required to “dismiss the application if it finds that a fair and reasonable offer to pool voluntarily has not been made by the applicant.”34 Unfortunately, there is a lack of statutory direction on what is considered to be a fair and reasonable offer. An applicant can find a short, non-exhaustive list of provisions that if included in an offer to pool, would make the offer prima facie not fair and reasonable. The last subsection of section 102.013 informs applicants of what could make their offer fair and

MIPA Requirements

There is one precursor that must have been met before the satisfaction of any other requirements need to be considered. The reservoir below the applicant’s tract of land must have been discovered and produced after March 8, 1961.20 Thus, reservoirs discovered and produced before the Normanna decision are exempt from compulsory pooling under the MIPA.21 However, the phrase “discovered and produced” is slightly ambiguous. Professor Smith explored the issues that might arise in interpretating the phrase.22 Nonetheless, it appears that for a reservoir to be exempt from a compulsory pooling order there must be actual oil production. The Waco Court of Appeals interpreted the phrase to require both discovery and production from a reservoir for it to be exempt.23 Additionally, the Commission is limited in its ability to pool tracts of land. Unlike other state agencies, the Commission cannot independently elect to pool mineral interest owners under the MIPA. The Commission only has authority to force pool mineral interest owners when the “owners [did] not agreed to pool their interests.”24 If an applicant’s offer was invalid, the Commission cannot consider the application and must dismiss for lack of jurisdiction.25 Before the Commission can 42

reasonable. It states that “[a]n offer by an owner of a royalty or any other interest in oil or gas within an existing proration unit to share on the same yardstick basis as the other owners within the existing proration unit are then sharing shall be considered a fair and reasonable offer.”35 As discussed below, this is not the only method for an applicant’s offer to be considered valid by the Commission.

subsection (c) was to allow small-tract owners to “muscle in” to larger tracks by simply offering to share on the same yardstick basis.48 If an offer to share on the same basis was all that was needed for it to be fair and reasonable, the Texas Legislature would have amended section 102.013(a).49 Thus, an interest owner, who is not a small-tract owner, must do more than make an offer to share on the same yardstick basis.

1. What Makes an Offer Fair and Reasonable?

Whether an offer is fair and reasonable has been the subject of several lawsuits because the decision is ultimately with the Commission.50 Interpreting the phrase is left to the Commission’s discretion since the MIPA does not define it.51 Thus, interest owners who have made offers should consider all relevant facts a reasonable interest owner would consider important.52 While there is not a definitive list of elements the Commission and courts consider, there is some authority on the issue. Additionally, considering the tracts and the type of mineral ownerships will help applicants determine what makes an offer fair and reasonable.53

Applicants of a compulsory pooling order must first seek to voluntary pool with the owner or owners of the adjacent tracts.36 Upon application, applicants must provide a detailed overview regarding their pooling offer to other interest owners.37 The statute deems a generic offer for all owners within the proration unit to share on the same yardstick fair and reasonable.38 However, ownership interest can vary, and what is considered fair and reasonable to one owner may not be to another.39 For instance, an operator’s offer to a royalty owner is not automatically fair and reasonable because it allowed the royalty owner to share on the same yardstick basis.40 Moreover, the Texas courts and the legislature have avoided defining the phrase.

A mineral interest owner who offers to voluntary pool should consider the financial position with whom he is seeking to pool.54 An offer that was fair and reasonable to one party might be unfeasible to another. The Commission might view the offer unreasonable if an applicant sought to force pool on this alone.55 Further, the Commission is likely to consider a “take it or leave it” offer invalid. In Windsor, the applicant made an offer that required Wilson, a one-third interest owner, to invest $426,660 and take a two-to-one risk factor.56 Wilson did not respond to the offer, and the other party sought a mandatory pooling order.57 The Commission determined that the offer was not fair and reasonable, and the Court of Appeals agreed.58 Additionally, there are situations in which the timing of the offer is factored into the fair and reasonable requirement.59 After a well is drilled and completed on a tract, a pooling offer that adversely affects the tract owner is not considered fair and reasonable.60 If the offer made to the tract owner adversely affected their interest, there is no longer an incentive to join. The well has already been drilled and completed on the tract. Yet, the same offer before the well was drilled would have value because of the uncertainty of the

Mineral interest owners seeking an involuntary pooling order are challenged with determining what makes an offer fair and reasonable. The Texas Natural Resource Code41 provides four provisions that cannot be included in a fair and reasonable offer. First, an operator is not allowed to be given preferential right to purchase mineral interests in the unit.42 Second, there cannot be an option to purchase production from the pooled unit.43 Third, there cannot be operating charges for any district or central office expenses, other than reasonable overhead.44 Lastly, non-operators cannot be prevented from questioning the operation of the unit.45 Despite the lack of a statutory definition, the Texas courts have provided guiding standards. The offer described in section 102.013(c), an offer for an interest owner to share on the same yardstick basis as the other interest owners, is not the only criteria for an offer to be fair and reasonable.46 In Carson v. Railroad Com. of Texas,47 the Court stated that the Legislature’s purpose of adding 43

drilling location. Now, the offer may be considered fair and reasonable. However, considering the Carson decision, one should be note that BTA refused to negotiate any other offers.61 Carson attempted to reach an agreement by having his royalty increased in exchange for the reduction in his interest of the well proceeds.62

Parties who elected not to participate in the drilling and completion costs incur a risk penalty for the drilling of the well.71 However, an offer that stipulated too high of a risk penalty can make the offer unfair or unreasonable. Courts have often found an offer that charged more than the maximum risk penalty the Commission is allowed to place on an owner “may be presumptively unfair.”72 The Commission is not allowed to include a risk penalty that exceeds 100 percent of drilling and completion costs.73 Other factors aside, an offer that set the risk penalty charge at 100 percent would likely be considered fair and reasonable.74 Further, there are circumstances in which a risk factor may not be a necessary element in the offer. If an owner could have participated before the drilling of a well then payment of a risk penalty may be required before they can receive proceeds from the well. However, in Buttes Res. Co. v. R.R. Com. of Tex.,75 the Commission, who the court agreed with, did not require the payment of the costs and risk penalty before the applicant received proceeds from the well.76 The applicant acquired the leases after the well was drilled, nor did he delay joining the pooled unit after he determined the well was a producer.77 Under similar circumstances as Buttes, the same court upheld the Commission’s decision that an offer which lacked a risk penalty was not unfair or unreasonable.78 Conversely, it should be noted that the Commission’s order included a risk penalty of 100 percent.79 Nonetheless, an offer that failed to include a risk penalty can still be considered fair and reasonable.80

Furthermore, counteroffers are a factor considered in the determination of whether an offer was fair and reasonable.63 The MIPA is considered to be an Act that encourages mineral interest owners to voluntary pool, rather than an outright compulsory pooling Act.64 This suggests that before the Commission will issue a compulsory pooling order, the parties were expected to reach a voluntary pooling agreement through negotiations. If an offer was not satisfactory to a party, then some contention should have been made.65 At a minimum, parties should have shown what was considered to be inadequate if no counteroffer was made.66 Per the Commission, the absence of a counteroffer or even an answer kills the purpose of the MIPA.67 Moreover, the MIPA requires applicants seeking to compulsory pool with another tract to have made a good faith effort to voluntary pool.68 The Legislature’s intent was not for a party to have made a half-hearted attempt to voluntary pool, but rather toseriously negotiate to reach a voluntary agreement.69 A good faith effort to make a voluntary pooling agreement is proven through negotiations amongst the parties. 2. The Risk Charge Some interest owners in a pooling agreement may have elected to be a non-working interest owner having their share of the drilling and completion expenses carried. The parties who carried the costs are then subsequently reimbursed through production, until the non-working interest owner’s share is recovered. Such agreements are not uncommon among oil and gas pooling agreements. Even if the party who sought to create a pooled unit did not offer or agree to such terms, the non-participating interest owners are still provided with the option to be carried. The MIPA states that the Commission shall create a provision for such an owner to repay the parties who advanced the costs solely out of production.70

IV. Horizontal Drilling, West Texas Oil & Gas, and Recent MIPA Applications A. Advances in Oil and Gas Production The MIPA cannot be applied to reservoirs in which oil or gas has been discovered and produced before March 8, 1961. Since the enactment of the MIPA, oil and gas production methods have significantly advanced. These advancements have allowed well operators to produce oil and gas from reservoirs not previously accessible.81 Just as they have in recent years, oil and gas recovery methods will continue to advance allowing for previously 44

unreachable minerals to be produced and lead to the discovery of new reservoirs.

viable methods in recovering the oil and gas underlying the tract.92 However, other tracts may not be entirely prevented from producing oil or gas. A pooled unit may be the only opportunity an owner within a shared common reservoir has to recover their fair share of the oil and gas.93 Without a pooled unit, such owners would be denied their opportunity to recover oil and gas, thereby violating their correlative rights and creating waste.94

Oil and gas production in areas that were previously unreachable may give rise to the issue discussed in Part III.82 Are such reservoirs exempt from the MIPA because the statute does not apply to reservoirs “discovered and produced” before March 8, 1961? The textual interpretation of this limitation is that a reservoir discovered but not produced is subject to the statute. Professor Smith discussed the issue this phrase can cause in a situation in which a reservoir was discovered and drilled on, but the well was subsequently shut-in prior to March 8, 1961.83 The answer is clear if shut-in royalties were not provided by the lease.84 Conversely, if shut-in payments were included in the lease, the definition of production must be determined.85

B. MIPA Use in the Barnett Shale Recent MIPA pooling orders have sparked concern thatorders will have the opposite effect of the Act’s goal.95 The MIPA was created to encourage voluntary pooling amongst tract owners.96 Advancements in oil and gas production have increased the use of horizontal and hydraulic fracturing in shale reservoirs. In turn, these drilling methods have caused a rise in oil and gas production around suburban areas.97

It is unlikely that Texas legislators foresaw how the MIPA would intertwine with horizontal drilling.86 Oil and gas companies have begun reentering vertical wells and re-completing them as horizontal wells.87 If the owner of such a well refuse to voluntary pool with interest owners within the reservoir, they can seek a compulsory pooling order from the Commission. Other MIPA requirements notwithstanding, a compulsory pooling order of tracts around such a well would be justified. One purpose of the MIPA is to protect mineral interest owners’ correlative rights.88 Adjacent mineral interest owners should be given the opportunity to produce their fair share of the minerals.89 An order that creats a pooled unit would provide each interest owner their fair share and prevent waste.

In an article published in 2010, Ronnie Blackwell analyzed some of the Commission’s orders within the Barnett Shale reservoir. The reservoir lies under tracts in Wise County, Texas and Tarrant County, Texas. Both counties cover tracts of land in the suburban area around Fort Worth, Texas. One MIPA applicant leased 82.97 acres within a subdivision in Fort Worth, Texas.98 Other parties leased 7.63 acres and 5.7 acres, roughly twenty-eight lots were unleased in the same subdivision.99 The applicant filed an application to force pool the unleased lots after his offers to lease and create a pooled unit of 96.32 acres were declined.100 The Commission granted the application and granted the unleased owners a one-fifth royalty and a four-fifth working interest, proportionately reduced by the pooled unit size.101 In another application the Commission approved the order and granted the unleased owners a one-fourth royalty interest and a three-fourths working interest.102 Further, both orders did not include a risk penalty and allocated the production costs to be paid out of the working interest.103

Additionally, technology advancements in drilling will facilitate use of the MIPA not only in older reservoirs but also in reservoirs discovered in more recent years. An application for an order to compulsory pool tracts within the Eagleville Field, discovered in 2007, was heard by the Railroad Commission Hearing Division in March of 2017.90 Some of the recently discovered fields lie within reservoirs, such as the Eagle Ford Shale reservoir, that cannot be developed and produced without horizontal drilling.91 Moreover, because of a tract’s location and configuration there are not

The concerns about whether or not such orders help facilitate the goal of the MIPA are rationalized when considering these orders. However, the Legislature’s intent was for the protection and 45

benefit of small-tract owners.104 Conversely, it is illogical to think the Legislature intended for MIPA orders to discourage small-tract owners from entering pooling negotiations by granting an overly favorable interest to them.

sections outline some recent MIPA applications made, the Technical Examiners’ reasoning for recommending to grant or deny the applications, and the Commission’s final decisions. 1. Ammonite Oil & Gas, Inc.’s MIPA Application for the Pecos Riverbed Tracts

C. Use of the MIPA in West Texas The greater Permian Basin hashelped make Texas the pinnacle of oil and gas production.105 The greater Permian Basin is responsible for almost forty percent of all oil produced in the United States and approximately fifteen percent of natural gas produced.106 The Permian Basin is roughly 250 miles wide and 300 miles long, and includes both the Delaware and Midland Basins.107 The increased use of modern practices by oil and gas companies made production possible in these areas.108

Ammonite Oil & Gas, Inc. (Ammonite) sought to create two MIPA units by pooling with two well-acreage units owned by Energen Resources Corporation (Energen).113 Ammonite, an agent of the State of Texas, applied to force pool a two-acre tract and a four and four-tenths acre tract on the Pecos River riverbed with Energen.114 This formed pooled units of 152 acres and 324.8 acres.115 Additionally, Ammonite sent Energen two offers to voluntarily pool over one month apart from each other.116 Each offer contained evidencebacked recommendations to share production and working interest costs on a net pro rata share of the surface acreage, a risk penalty, and that Ammonite’s share of costs would be taken from its share of production.117 The Examiners recommended granting the order because the offer was fair and reasonable, and that it was “necessary to avoid the drilling of unnecessary wells and to protect correlative rights.”118

The MIPA has been used to pool tract owners in counties encompassed by the greater Permian Basin. Tract owners in West Texas have filed applications with the Commission to force pool because of the location of the fields, the nature of horizontal and hydraulic drilling, and lack of production capability without pooling.109 Further, a U.S. Geological Survey projected that the Delaware Basin has the capability to produce roughly forty-six billion barrels of oil and 281 trillion cubic feet of natural gas.110 Consequently, there is a substantial probability that MIPA applications from West Texas mineral interest owners will continue to be filed. The next section focuses on the current manner in which the Commission has applied the MIPA in West Texas, specifically around Pecos.

The Examiners found that Ammonite satisfied the necessary requirements for them to file and be granted a compulsory pooling order.119 They stated that an order to compulsory pool can be granted “only if it is necessary” to avoid drilling unnecessary wells, protect correlative rights, or prevent waste.120 They reasoned that the MIPA units were necessary to protect the State’s correlative rights, and that the State would not have had a reasonable opportunity to receive their fair share without the units.121 For these reasons, the Examiners recommended that the order be granted as proposed by Ammonite.122 Ultimately, the Commission approved the order stating that production, revenues, and expenses were to be allocated on an acreage basis, and that the risk charge was fair and reasonable.123

D. MIPA Applications in District 8: Reeves, Loving, Pecos, and Ward County MIPA orders have been relied on to pool tract owners in areas near Pecos, Reeves County, Texas, and the surrounding areas. The counties directly surrounding the town of Pecos – Reeves, Ward, Loving, and Pecos County – and other counties in the area are listed within district eight of the Texas Railroad Commission.111 Tract owners in West Texas have filed applications with the Commission to force pool for many of the reasons described in the section above.112 The following 46

2. Colgate Operating, LLC’s MIPA Application for the Cantaloupe Unit

framework had previously been considered fair and reasonable by the Commission. Lastly, the 100 percent risk charge was considered too high and a 50 percent risk charge was recommended.140

On December 6, 2016, Colgate Operating, LLC (Colgate) filed an uncontested application under the MIPA requesting the Commission create a force pooled unit, the Cantaloupe MIPA unit.124 The hearing for the application was held January 17, 2017.125 Colgate intended to horizontally drill an oil well in the Phantom (Wolfcamp) Field in Reeves County, Texas.126 The proposed MIPA unit was partially within Pecos, Reeves County, Texas and covered 157.49 total acres, comprised of several different tracts.127 Colgate already possessed the mineral interest on multiple tracts that totaled 137.58, or 87 percent, of the total net mineral acres.128 Additionally, there were 65 unleased mineral interest owners in the proposed unit, who collectively owned 19.92, or 13 percent, of the net mineral acreage.129 Accordingly, Colgate sent a voluntary pooling offer to all unleased mineral interest owners within the unit around December 16, 2016.130 Colgate’s offer included three options: 1) to lease their interest to Colgate; 2) to participate as a working interest owner; or 3) a farm-out agreement with the option to convert their overriding royalty interest to a working interest upon reaching well payout.131 Field rules had already been established by the Commission.132

Ultimately, the Commission adopted the Examiners’ recommendation and granted Colgate’s MIPA application to create the Cantaloupe Unit.141 The order pooled all interests in tracts within the area described into the Cantaloupe MIPA Unit, including all unleased mineral interests.142 Additionally, the Commission allocated production to each interest owner on a surface acreage basis, and prevented surface use of unleased tracts without written consent of the unleased owner.143 Further, owners of a mineral interest in unleased tracts were assigned a one-fourth royalty interest and threefourths working interest, proportionately reduced.144 The Commission also assigned a 50 percent risk charge to working interest owners’ share of costs but was payable only out of three-fourths of production, not their entire mineral interest.145 3. Colgate’s MIPA Applications for the Moses, Goliath, King David, and Ramses Units Colgate filed an application with the Commission to create four separate MIPA units of 148.385 acres, 159.005 acres, 154.996 acres, and 151.861 acres.146 If created, Colgate would have held between 75.82 percent and 86.86 percent of the overall acreage in the four units.147 The ownership of the rest of the surface acreage would have been shared by over 200 different unleased owners.148 Colgate intended to drill the wells as horizontal oil wells in the Wolfcamp Field, and the units are at least partly in the city of Pecos, Texas.149 Accordingly, Colgate sent voluntary pooling offers to all the owners of the unleased tracts, and gave three options the interest owners could choose from to join the pooled unit.150 The options were to lease their tract to Colgate, participate in the well as a working-interest owner, or to participate in a farm-out agreement.151 Subsequently, Colgate filed its applications after not receiving responses from the unleased mineral interest owners.152

The Examiners recommended granting the application to form the Cantaloupe Unit.133 They stated that “the Commission may order compulsory pooling only if it is necessary to avoid the drilling of unnecessary wells, protect correlative rights, or prevent waste.”134 They reasoned it was necessary because “the well could not be drilled as proposed without compulsory pooling” due to the unleased tracts’ locations.135 The Examiners relied on the “impracticability of drilling around the unleased tracts” to support their reasoning.136 They noted that the well would trespass or not meet the spacing requirements to 21 unleased tracts.137 Additionally, they concluded that without force pooling, a mineral interest owner in the proposed unit would not have a “reasonable opportunity to recover his fair share of hydrocarbons.”138 Further, the Examiners believed that the voluntary pooling offers were fair and reasonable since they provided the three-tier option.139 Offers providing the same

The Examiners recommended that the applications to create the MIPA units be granted 47

based on the evidence presented by Colgate.153 They stated that an order to compulsory pool may only be issued when “necessary to avoid the drilling of unnecessary wells, protect correlative rights, or prevent waste.”154 The Examiners reasoned that the wells could not have been drilled without compulsory pooling because “of the impracticality of drilling around the unleased tracts.”155 Further, the Examiners stated that the force pooled units would give each owner in the unit the opportunity to receive their fair share.156 They believed that the risk charge and the pooling offers made by Colgate were fair and reasonable.157 Ultimately, the Commission agreed and approved the MIPA units.158 The orders granted the unleased mineral interest owners a one-fourth royalty interest and threefourths working interest, proportionately reduced, and made the expenses, subject to a 100 percent risk penalty, payable from the working interest.159

wells, and the other two wells were expected to qualify.168 Consequently, Colgate asked the Commission that each of the MIPA units be enlarged to the size accepted for gas wells within the field.169 In the examiners’ discussion of the need for MIPA, the examiners pointed towards the amount of money Colgate spent in leasing efforts, Colgate’s effort to obtain as much of the acreage as they could within the units, and the amount of acreage Colgate already had leased within the units.170 Further, Colgate asked for a 100 percent risk charge in the units, except for the Cantaloupe unit which was previously given a 50 percent risk charge.171 In the examiners discussion, they stated that the 100 percent risk charge was appropriate because wells that reached payout also needed to do so for wells that did not achieve it for themselves.172 Ultimately, the examiners approved the application and recommended approving Colgate’s applications.173 The examiners determined that the voluntarily pooling offers were fair and reasonable because they provided the three-tier option of leases that the Commission considered fair and reasonable in previous MIPA applications.174 Further, the examiners asserted that compulsory pooling was necessary because of the “impracticability of drilling around the unleased tracts;” thus, preventing “the waste of hydrocarbons” under the MIPA units.175 Additionally, the examiners recommended a 100 percent risk charge because of the “uncertainty and risk” of a well reaching payout, and the challenges Colgate faced in “urban leasing and drilling.”176

4. Colgate’s MIPA Applications to Amend their Original Units a. Examiners’ Recommendation for Colgate’s Amended MIPA Units In December of 2018 Colgate Operating filed an application to amend the size of their units created by the Commission’s order in 2016.160 Colgate filed this application under the assertion that it was necessary to prevent waste and protect correlative rights.161 The amended units would consist of all the acreage voluntarily pooled into the units and all the unleased acreage within the pooled unit.162 The proposed amended units would be 549.91 acres, 635.31 acres, 554.37 acres, 644.06 acres, and 606.12 acres.163 Colgate proposed to horizontally drill in the Phantom (Wolfcamp) Field and to allocate production on a surface-acreage basis.164 Colgate sent voluntary pooling offers to all owners of the unleased acreage within the proposed units.165 These offers included three options for the unleased tract owners: 1) a lease option; 2) a working-interest participation option; and 3) a farm-out option.166

b. Railroad Commission’s Orders for Colgate’s Amended MIPA Units In the final order concerning Colgate’s Cantaloupe well, the Commission fully adopted the examiners’ findings and conclusions.177 The order pooled all interests within the area described, including unleased mineral interests, into the Cantaloupe MIPA unit.178 Production from any well in the unit was allocated based on the surface area an interest owner has relative to the number of surface areas in the entire unit.179 Additionally, all owners of unleased tracts were pooled as owners of a onefourth royalty interest and a three-fourths working interest proportionately reduced to the surface

These units were originally granted and sized under the assumption that Colgate’s wells would be operating as oil wells.167 After the wells were completed, three out of five qualified as gas 48

acreage owned.180 Further, the Commission granted a 50 percent risk charge on the Cantaloupe 1H well, but a 100 percent risk charge for all subsequent wells.181 However, the risk charge was limited to be payable only from three-fourths of production the unleased tracts were granted, not from the entire mineral interest.182 The surface use of unleased minerals tracts was also limited without the written consent from the owners.183 In the end, the Commission granted the application to amend the MIPA unit.184

Further, Colgate was granted their application to amend the King David MIPA well.198 The Commission fully adopted all findings of fact and conclusions of law made by the examiners.199 All interests within the area described were pooled into the King David MIPA unit.200 In accordance with the statutory requirements, the share of production owned by interest owners was allocated with respect to the amount of surface acres owned.201 The interests of lessors who voluntarily pooled were pooled as royalty interests, lessees were pooled as working interests, and unleased mineral interests owners were given a one-fourth royalty interest and a three-fourths working interest.202 The unleased interest owners were subject to a 100 percent risk charge that was payable from three-fourths of production, and not from the entire interest.203

For the Moses MIPA well, the Commission granted Colgate’s application to amend and pooled all interests in tracts within the proposed unit.185 They allocated production from any wells within the unit to the proportion of surface acres owned to the number of surface acres in the entire unit.186 Voluntarily pooled lessors were pooled as royalty interest owners.187 Conversely, all unleased tracts pooled into the MIPA unit were pooled as owners of a one-fourth royalty interest and three-fourths working interest owners.188 Again, the Commission limited the 100 percent risk charge to be payable from only the three-fourths of production and not from the entire mineral interest.189 Further, the Commission established that no surface usage may come from unleased tracts without written consent from the owner.190

Finally, the application to amend the Ramses MIPA unit was granted by the Commission.204 The Commission pooled all interests, including unleased mineral interests, within the area described for the Ramses unit into the new amended MIPA unit.205 The interests were pooled subject to production being allocated on a surface acreage basis.206 Similar to the other orders granted, voluntary lessors were pooled as royalty interest owners, lessees were pooled as working interest owners, and unleased tracts were pooled as owners of a one-fourth royalty interest and a three-fourths working interest.207 Colgate was granted the 100 risk charge they asked for, but limited to be payable only from three-fourths of production and not the entire mineral interest.208

The application to amend the Goliath MIPA well was granted by the Commission.191 Similar to Colgate’s other amended units, the Commission pooled all interests within the area described into the Goliath MIPA unit.192 Standard for MIPA units, production in the Goliath unit was proportioned on a surface acreage basis.193 Additionally, lessors who voluntarily pooled were pooled as royalty interest owners, and unleased tract owners were pooled as owners of a one-fourth royalty interest and three-fourths working interest owners.194 The interest for owners of unleased tracts were proportionately reduced on a surface acreage basis and subject to a 100 percent risk charge.195 Further, the risk charge was limited to be payable only out of three-fourths of production.196 Colgate could not use the surface of unleased tracts without written consent of the owners.197

V. Examining the Commission’s Orders and Examiners’ Recommendations Under the MIPA Statute and Case Precedent Applying the MIPA statute in circumstances that were unknown at the time the MIPA was drafted has proven to be difficult. The Commission is expected to apply and follow the statutory regulations to situations and drilling methods of drilling that the MIPA drafters had not previouslyenvisiond. The MIPA is needed when small, unleased tract owners are force pooled into MIPA units to protect small-tract owners’ correlative rights. Specifically, when these tracts are in urban areas and 49

instead of adding subsection (c).216 Rather, the intent of subsection (c) was to make small-tract owners’ offers to share on the same yardstick basis a fair and reasonable offer.217 Hence, offers from interest owners who are not small-tract owners are not automatically fair and reasonable because they offered to share on the same yardstick basis. Nonetheless, the decision of whether or not an offer is fair and reasonable falls on the Commission.218

horizontal drilling must be used to extract resources. This section will focus on analyzing the development andusage of the MIPA in units surrounding urban areas that utilize horizontal drilling. This paper does not suggest what interests should be awarded to unleased tracts in the unit or how the Commission should determine those interests. Rather, this section will discuss whether the Commission has abided by the laws and requirements established. Additionally, this section will discuss whether the Commission has remained true to the spirit and purpose of the MIPA. Further, it will consider the application of the MIPA to unleased tracts force pooled into pooled units.

A risk charge is applied to parties who have elected to not participate in the drilling and completion costs.219 When granting a MIPA application, the Commission is not allowed to include a risk penalty that exceeds 100 percent.220 Courts have found offers with risk penalties that exceed 100 percent, the Commission is allowed to hold they “may be presumptively unfair.”221 Moreover, the Texas Court of Appeals for the 14th district held that an applicant was not required to pay a risk penalty because the leases were acquired after a well was drilled and the applicant did not wait to determine if the well would be a producer to join the pooled unit.222

A. Review of Statutory Requirements and Case Law Under the MIPA, the Commission can order mineral interest owners to force pool their property “with other owners’ proposed or existing wells on the same proration unit within a common reservoir.”209 Before any action can be taken, the MIPA applicant must make a fair and reasonable offer to voluntarily pool.210 More importantly, the MIPA requires an applicant seeking a forced pooling order from the Commission to have made a good faith effort to reach a voluntary pooling agreement.211 An applicant may then file an application for forced pooling if the fair and reasonable pooling offer is not accepted.212 The applicant must have met one of three requirements for the Commission to approve the application: that the proposed unit “would (1) avoid the drilling of unnecessary wells, (2) protect correlative rights, or (3) prevent waste.”213

B. Do the Examiners’ Recommendations and the Commission’s Orders Conform to the Statutory Requirements and Case Law? 1. Ammonite Oil & Gas: Pecos Riverbed Tracts Ammonite, as an agent of Texas, sought to force pool a two-acre tract and a four and fourtenths acre tract.223 The pooled units resulted in a 152 acre and 324.8 acre tracts.224 The Examiners found the voluntary pooling offer from Ammonite to Energen was fair and reasonable.225 They reasoned that the pooling offer did not considerably dilute Energen’s royalty owners share of production because the proportionate share of production was determined by a surface acreage basis.226 Further, the Examiners believed that the pooling order was “necessary to avoid the drilling of unnecessary wells and to protect correlative rights.”227 They reasoned that there was not a reasonable opportunity for the State to receive their fair share without the pooled units.228 The Commission granted the application and allocated production, revenue, and expenses on an acreage basis, and stated that the risk charge was fair and reasonable.229

Typically, an offer will be considered fair and reasonable if it proposes owners within the same proration unit share on the same yardstick basis.214 However, what is fair and reasonable to one owner may not be to another because ownership interest varies.215 There is no bright-line rule as to what makes an offer fair and reasonable. If the Texas Legislature’s intent was to make any offer on the same yardstick basis to satisfy a fair and reasonable offer, they would have amended section 102.013(a) of the Texas Natural Resources code 50

is evident that the purpose of a risk charge is to ensure the economic risk assumed in the drilling and completion of a well is reasonably spread amongst the working interest owners.242 Ammonite offered to have the 10 percent risk penalty taken out of their share of production, and the production history of the wells illustrated there was little economic risk in the development of the units.243

Here, Ammonite proved it had jurisdiction to file a MIPA application as an agent of Texas because the State had given them authority under section 102.004;230 land that “the State of Texas has an interest [in] . . . may be pooled under the provisions of this chapter.”231 Additionally, Ammonite presented expert testimony that the Pecos Riverbed tracts fell within the same productive reservoir for the proposed unit, and that these proposed units would protect the State’s correlative rights.232 Evidence showed that it was not possible to drill a well and that the riverbed oil and gas could not be produced without pooling.233 Further, the evidence illustrated that the State would be denied a reasonable opportunity to recover their fair share of the oil and gas in the common reservoir without the proposed units.234 Ammonite also made more than one attempt to voluntary pool the tracts but received no response from Energen.235 Evidence was presented that described the offers, and established Energen’s royalty owners would not have their shares considerably diluted.236 Lastly, the low risk charge was justified by the production history of the wells in the proposed unit and the proposal to have the penalty taken out of Ammonite’s share of production.237

For the above reasons, I believe the decision to grant Ammonite’s MIPA application is justified and follows the spirit of the Act. This application of the Act was for the exact purpose the Texas Legislature enacted the MIPA.244 It prevented the small-tract lessee from being denied a reasonable opportunity to recover their fair share of oil and gas in the common reservoir; it protected their correlative rights. Moreover, the Texas Legislature added section 102.013(c) for these circumstances.245 Despite that the Examiners and Commission failed to discuss subsection (c), the purpose is to allow small-tract interest owners to “muscle in” to larger tracks by offering to share on the same yardstick basis.246 While the Commission does not have limitless authority to force pool mineral interest whenever a MIPA application is filed, this order is clearly within the bounds of their authority.

The Commission adhered to the MIPA’s purpose and rules when this application was granted. Ammonite satisfied all of the requirements under section 102.011 with the evidence presented. The Commission agreed with the Examiners’ conclusion that the proposed units were necessary to protect the State’s correlative rights.238 Additionally, Ammonite established that voluntary pooling offers were made and that the offers were fair and reasonable. A lack of negotiations to voluntarily pool tracts of land supported the Commission’s decision to grant the application.239 A good faith effort to reach a voluntary pooling agreement is demonstrated through negotiations. The Legislature’s intent in creating MIPA was for parties to have serious discussions to reach a voluntary agreement.240 Consequently, the Commission has determined that an absence of a counteroffer, or lack of an answer, kills the purpose of MIPA.241 Further, the risk penalty of 10 percent owed from Ammonite’s share of production was reasonable. When considering the MIPA statute, it

2. Colgate Operating: Cantaloupe MIPA Unit Colgate qualified as an owner authorized to apply for pooling because they satisfied the requirements established in section 102.012 of the Texas Natural Resource Code.247 Additionally, this application fell within the authority of the Commission because: i) Colgate’s application involved a common reservoir with established field rules; ii) there were separately owned interests and the owners did not agree to pool; and iii) an owner with the right to drill proposed to drill a well.248 Evidence was presented that established a common reservoir throughout the proposed unit.249 However, the evidence illustrated there was not a path for the planned drilling that would avoid an unleased interest.250 It was not established that there was an impossibility of drilling a well that could produce oil and gas, but rather that the well could not be drilled as proposed.251 51

Legislature’s intent and rules established by the Texas Supreme Court. Thus, the lack of counteroffers or answers is irrelevant when considering whether or not the application should be granted. It is almost certain Colgate would have refused to discuss the offers even if the unleased interest owners did respond. It was made obvious that Colgate never intended to enter negotiations when they filed an application before sending their offers. The Examiners never needed to consider whether or not Colgate’s offers were fair and reasonable. It is unnecessary to inquire further into an offer, or MIPA application, if the applicant did not make a good faith effort to voluntarily pool. Therefore, the Commission should have denied Colgate’s application because they failed to make a good faith effort to reach voluntary pooling agreements.

There was an impracticability of drilling around unleased tracts created by the proposed wellbore path. Nonetheless, the Examiners relied on this evidence to support the need for forced pooling to protect correlative rights and provide a reasonable opportunity for mineral interest owners to recover their fair share.252 Further, the voluntary pooling offer was considered fair and reasonable because it provided a three-option framework.253 Colgate showed in detail the pooling offers made to mineral owners of the unleased tracts.254 Conversely, it was not considered whether there was a good faith effort by Colgate to voluntarily pool tracts. The Texas Supreme Court has stated that applicants are required to have made a good faith effort to voluntary pool tracts.255 Lastly, a risk charge of 50 percent was appropriate because evidence showed significant variability in the estimated recovery of nearby wells.256

3. Colgate Operating: Original and Amended Applications for the Cantaloupe, Moses, Goliath, King David, and Ramses MIPA Wells a. Colgate’s Original MIPA Applications

The Commission should have denied Colgate’s Cantaloupe MIPA well application. Colgate met the statutory requirements for what is within the Commission’s authority, who can file a MIPA application, and an appropriate risk charge.257 Additionally, Colgate did set forth in detail the offers made to other interest owners, and the Examiners believed the three-tier option previously approved by the Commission was fair and reasonable.258 However, the Examiners should have found that Colgate did not make a good faith effort to voluntary pool with other mineral interest owners. Precedent has established that a lack of counteroffers or answers defeats the purpose of the MIPA, and the intent of the Legislature was to have serious attempts to reach voluntary agreements.259 The facts in the Examiners’ report do not indicate that the unleased mineral interest owners made any counteroffers or raised any objections. Conversely, applicants asking the Commission to force pool their tract with another are required by the MIPA to have made a good faith effort to voluntarily pool.260 Colgate filed an application with the Commission on December 6, 2016.261 Yet, the Examiners stated that voluntary pooling offers were sent “[o]n or about December 16, 2016.”262 Consequently, Colgate already filed an application to force pool these tracts before sending an offer to voluntarily pool. Such action clearly violates the

In Colgate’s original applications, they met the requirement under section 102.012, which established who is authorized to apply for a pooling order. Colgate owned leases on several tracts in the proposed unit which granted them an interest in the oil and gas under those tracts.263 Additionally, the report and recommendation indicated that the requirements to prove the Commission’s authority under section 102.011 were satisfied. Colgate presented evidence that established a common reservoir was present throughout the proposed unit.264 It is clear that a voluntary pooling agreement was not reached because the applications to force pool were filed. Also, the proposed units met the size limitations for oil wells, and the Commission had established field rules.265 Further, the Examiners agreed with Colgate’s contention that the evidence demonstrated a MIPA unit was needed to protect correlative rights and prevent waste.266 But, this necessity was based on the impracticability of drilling the well as proposed.267 The Examiners reasoned that “each mineral interest owner within these proposed units” would not have a “reasonable opportunity to recover [their] fair share of hydrocarbons” because of such impracticability.268 Moreover, Colgate provided the details of the 52

three-option offers which included a lease option, a working interest owner option, and a farm out option.269 The Examiners concluded that the offers complied with section 102.013 because the Commission had previously approved the three-option framework as fair and reasonable.270 However, it appears the Examiners did not look at all the necessary considerations in deciding whether an offer was fair and reasonable. Lastly, the applied 100 percent risk charge did not violate section 102.052. The Commission fully adopted the Examiners’ finding and conclusions, and granted all of the MIPA applications.271

Legislature’s intent and the rules established by the Texas Supreme Court. It tends to prove that Colgate never seriously intended to enter into voluntary pooling agreements or negotiations. But, it should be noted that the Examiners referenced an exhibit for the offers that I did not have access to, and there may have been an error in recording the respective dates. Still, the biggest error falls on the Examiners. They found the voluntary pooling requirement to be satisfied because Colgate sent three-option offers. There is no indication that they considered any of the guidelines established by the Texas courts discussed in the previous parts of this paper. Thus, the Commission should have denied these applications since there was no evidence suggesting Colgate made a good faith effort to reach voluntary pooling agreements.276

In my opinion, the Commission should have denied these MIPA applications. It is clear that Colgate established that they met the requirements to file an application, and that the risk charge was appropriate. The Commission’s authority to order compulsory pooling in these applications was satisfied, but I believe this requirement was met for different reasons than stated by the Examiners. However, these MIPA applications should have been denied because Colgate did not meet the requirements for the required voluntary pooling offers. Similar to the Cantaloupe Unit application, the facts in the examiners’ report and recommendation indicate that Colgate did make a good faith effort to voluntary pool with the unleased interest owners. We know the Texas Legislature intended parties to make serious attempts in reaching voluntary pooling agreements. A lack of counteroffers or answers contradicts that intent and undermines the purpose of the MIPA. Nonetheless, MIPA applicants are required to have made a good faith effort to reach voluntary pooling agreements.272 The Examiners stated in their findings of fact that Colgate sent voluntary pooling offers “[o]n or about June 8, 2017.”273 Conversely, the procedural history in the report indicates that Colgate filed their applications on May 12, 18, and 22, 2017.274 Moreover, the Examiners stated that Colgate sent voluntary pooling offers before filing applications with the Commission.275 Despite that, the dates of the pooling offers and the filed applications clearly contradict the Examiners. While language such as “on or about” gives some leeway to the exact date, it does not account for a three week discrepancy. Parallel to Colgate’s application for the Cantaloupe MIPA Unit, this action violates the

b. Colgate’s Amended MIPA Applications I believe the Commission should have denied these amended applications for reasons similar to the ones explained in the discussion of Colgate’s original applications. Similar to the original applications, the record was completely void of any evidence to suggest there was a good faith effort on Colgate’s part to reach voluntary pooling agreements. Here, Colgate sent voluntary pooling offers on January 7, 2019.277 Conversely, the amended applications were filed on December 4, 2018.278 Moreover, the Hearing Division of the Commission sent out notices for the hearing of the applications on January 4, 2019.279 Not only did Colgate file their MIPA applications before they sent voluntary pooling offers to unleased mineral interest owners, but the Hearing Division also sent notices before these unleased owners received the voluntary pooling offers. The facts in the Examiners’ report demonstrated inadequate adherence to the process established in the MIPA and developed by Texas courts, regardless whether any recipients of the offers responded to Colgate. The lack of response from the unleased owners supported granting the application, but it should not be considered until the applicant established a good faith effort on their part. Moreover, the fair and reasonable requirement should require more investigation than what the Examiners’ provided. A determination that the offers were fair and reasonable simply because they provided the three-option framework 53

pool.285 Lastly, neither the Examiners nor the Commission should have taken the facts presented and applied them retroactively. In many of the applications discussed above, a lack of negotiations was shown through the absence of counteroffers or answers. The Commission has determined such actions to defeat the very purpose of the MIPA. However, this analysis was completely missing in the Examiners’ recommendations. Further, this consideration should not be relevant until the applicant demonstrated they met the requirement placed on them by the Court, to have made a good faith effort to reach a voluntary agreement.

the Commission concluded to be fair and reasonable in other applications is inadequate. This has historically been the subject in large amount of the litigation surrounding the MIPA and could have been the source of more if the applications were not uncontested. Conversely, Colgate seemed to satisfy the other requirements. Evidence was provided that established different owners of tracts of land with mineral interest in a common reservoir, and the field rules were established.280 It also showed that Colgate proposed to drill and had the right to drill a well in the proposed units.281 Further, there would have been a waste of hydrocarbons because of the impracticability of drilling around the unleased tracts, thus, forced pooling was needed.282 The proposed units also served to protect correlative rights because the horizontal wells would extend the length of the MIPA units and provide “a reasonable opportunity” for all tract owners to receive “their fair share of the hydrocarbons to be produced.”283 Nonetheless, the Commission and Examiners’ should not pick and choose which requirements they want to sufficiently evaluate. Therefore, the applications should have been denied, until Colgate demonstrates a good faith effort to reach voluntary agreements.

Voluntary pooling offers have been the issue in the majority of the litigation surrounding the MIPA. This alone should be enough for Examiners to fully explore all the circumstances around the offers made by applicants. The Examiners’ repeated reliance on the three-option framework was not enough to determine whether an offer was fair and reasonable. As discussed previously, every recipient of a voluntary pooling offer has differing circumstances and the offers should be evaluated accordingly. Thus, a determination that an offer was fair and reasonable based on the framework the Commission approved in previous applications was invalid. I believe the applications discussed here should have been denied, and the Commission should have required the applicants to file new applications that showed a good faith effort to reach a voluntary agreement. If the unleased mineral interest owners had representatives to contest the applications, it is likely that the Commission would have denied the applications. Additionally, I do not believe it is unreasonable to imagine the possibility for ensuing litigation existed if the representatives adversely contested the applications and compulsory pooling was granted. The reason neither denial nor subsequent litigation occurred was because the majority of the applications were completely uncontested.

C. Issues with the Recent MIPA Applications in District 8 and the Future Implications of the Decisions on the MIPA 1. The Good Faith Effort Requirement The need to have made a good faith effort to reach a voluntary pooling agreement may seem trivial when the entire method of approving MIPA applications is considered, but there is good reason to consider such failings. First, insincere attempts to voluntary pool wholly go against the intent of the Legislature. The MIPA has repeatedly been regarded as an Act that encourages voluntary pooling and not a compulsory pooling Act.284 The goals of this paper did not involve flushing out the reasoning behind such characterization, but I believe the high regard in which the State of Texas and its Legislature holds personal property rights played a vital part. Second, as far back as 1984 the Texas Supreme Court has acknowledged that applicants seeking to compulsory pool another tract are required to make a good faith effort to voluntary

It is possible that the Examiners overlooked or ignored applicants’ good faith effort requirement because it is not specifically stated within the MIPA statute. However, the need for it to be considered is not alleviated by an absence in the statutes. The Court has determined that the Commission has discretion in concluding what 54

constitutes a fair and reasonable offer, but their discretion does not encompass what requirements are needed to make an application. This requirement needs to be re-visited so that it is fully brought into the determination of when an offer was fair and reasonable. Unfortunately, the Texas Supreme Court is limited in providing some insight until a MIPA application is litigated over the issue. The Texas Legislature holds the best position to provide immediate authority. Whether the requirement is placed on all parties to the voluntary pooling agreements, the applicant alone, or entirely rejected, clarification will provide the Examiners’ and Commission with more guidance.

does not negate the importance of the MIPA being a tool to protect small-tract owners. Next, I would like to discuss a major concern raised with recent MIPA orders. The concern is that the Commission has awarded excessively beneficial interest to unleased, small-tract interests owners who did not respond to voluntary offers. Thus, the purpose of the MIPA to encourage voluntary pooling is defeated by the Commission’s own actions. I believe this concern is unfounded. The interest awarded to unleased, small-tract owners is likely more advantageous than operators would ideally want them to have. However, is that enough to limit the Commission’s authority in assigning interests to unleased owners?

2. Uncontested MIPA Applications and the Interests Awarded to Unleased Tracts

Compulsory pooling is granted to protect correlative rights, prevent waste, and to avoid drilling unnecessary wells. Additionally, the orders are to be on fair and reasonable terms, and provide owners an opportunity to receive their fair share. It is reasonable to believe that the Commission has discretion, within certain bounds, to determine what are fair and reasonable terms, similar to its discretion in considering offers. Further, when the enactment of the MIPA, the commentary regarding the Act, and the precedent established by Texas courts are considered, it is clear the MIPA does more than encourage voluntary pooling. It protects small-tract interest owners. Moreover, if the Commission was limited to assigning interests that were not beneficial for these owners it would fail on two accounts. First, it would discourage voluntary pooling. Applicants would have no incentive to seek voluntary pooling agreements, let alone make a good faith effort to reach an agreement. There would be no purpose to have negotiated with unleased owners if the Commission assigned interests that were detrimental to them. Second, the Commission would have failed to ensure that the MIPA is a tool to protect small-tract owners. As it was stated previously, the MIPA was enacted in a direct response to the devastating impact the Normanna and Port Acres decisions had on small-tract owners. There is no stronger evidence that the MIPA was enacted not only to encourage voluntary pooling, but also to protect small-tract owners.

Should uncontested MIPA applications be reviewed under a different light than applications that have a knowledgeable and competent party to contest it? A complete and final answer to this question is not offered in this section, but this paper was not written for that purpose. Recently, the MIPA seems to have evolved into a tool used by large tract mineral interest owners rather than its originally intended use. The Texas Legislature enacted the MIPA to protect small-tract mineral interest owners from the effect of the Normanna and Port Acres decisions.286 This is why the Court stated that the purpose of the MIPA goes beyond encouraging voluntary pooling and the Act should be read to strongly benefit small-tract owners.287 Additionally, the Legislature’s intent in adding section 102.013(c) was for the benefit of smalltract owners.288 From the enactment of the MIPA to the language inside of the statute, it is clear that it was meant to protect the interest of small-tract owners. However, it is improbable that the Legislature anticipated the methods used today to recover oil and gas. The nature of horizontal drilling close to urban cities and the purpose in which the Commission is supposed to exercise its authority—to prevent the drilling of unnecessary wells, protect correlative rights, and prevent waste—has presented complicated circumstances. I believe the Commission has correctly determined that the MIPA could be applied in situations involving small, unleased mineral interest owners. But, it 55

Additionally, there is also a common sense argument to be made. In most business circumstances, there are always parties that had leverage over another. It is not the Commission’s role to have balanced the scales between operators and unleased, small-tract owners. The counsel of unleased owners were expected to advocate for the best outcome to their client. Any reasonable person would use leverage they had to put themselves in the most beneficial position possible. Assume an unleased owner negotiated for something similar to a one-fourth royalty and three-fourths working interest, proportionately reduced and included an appropriate risk charge. Then, an operator filed an application for compulsory pooling and alleged that the offer was not fair and reasonable. Next, assume the Commission granted the application, ordered compulsory pooling, and assigned the interests. If we follow the established pattern of awarded interests to unleased owners, we end up where we started.

amount of hydrocarbons below a tract, and if the unleased owner refused to enter into any negotiations. Further, there is not a rigid limitation placed on the Commission when assigning interests in a proposed unit. Less favorable interests should be awarded to small-tract owners whose tracts fell within less productive areas of the proposed unit. Particularly, less advantageous interests should be awarded if the applicant proved a good faith effort to reach a voluntary agreement, and the unleased owner refused to negotiate. Conversely, the Commission should have considered the flip-side. Did the applicant refuse the counteroffers? If so, why, and what were the terms of the counteroffer? Small-tract owners are entitled to strongly advocate for the most beneficial results. An application made after one counteroffer and no further negotiations, undermines an owner’s attempt to reach a voluntary agreement. A prudent attorney, who performed their due diligence, might have known if their client was in a good position to take a tough position in negotiations. It must also be remembered that it was the applicants own fault that the Commission became involved. The Commission is only involved after an application for compulsory pooling is filed. Now, not only are the unleased tracts that prevented drilling the well awarded beneficial interests, but also all unleased tracts in the proposed unit.

The fear that the Commission’s actions have discouraged unleased, small-tract owners from entering into voluntary agreements is rationale, but it can be easily dispersed. The owners with the most leverage were those whose tracts fell directly on the planned wellbore path or close enough that the well violated spacing rules. Considering the MIPA applications discussed here, a fair portion of the unleased tracts fell substantially close or directly on the planned wellbore path. Unleased, small-tract owners and their attorneys are not aware of the position their tracts had in relation to the planned drilling path. The planned path would be unknown until it was presented to the Examiners and the Commission. At that point, the discretion that the assigned terms were fair and reasonable fell with the Commission. Additionally, all of the above analyzed orders proportionately reduced the owners’ interest on a surface acreage basis. Moreover, every application is faced with different situations. The Examiners’ recommendations and the Commission’s orders should be based on all the circumstances. In the MIPA applications above, it was difficult to distinguish what facts were considered, outside of those directly stated, when each owners’ interests were established. The Commission and its Examiners’ should have considered the tract location, the

Lastly, while this is not an exhaustive list of all the alternatives available to operators and similar applicants, there may be a few possibilities to avoid Commission involvement. The first, and maybe most obvious, is to offer the owner whose tract prevented the well a more beneficial interest in the voluntary pooling agreement. At a minimum, this would prevent the Commission from giving all unleased interest owners an overly favorable interest in the established unit. Next, determine if a shortened well length would be adequate. Once the well is operational, any unleased owners who subsequently decided to pool their tracts will be in a worse position to negotiate. Most likely, they will be forced to use section 102.013(c) and their interest will be shared on the same yardstick basis as other non-working interest owners. Once the unleased tracts are pooled, it will 56

also open the opportunity for the operator to re-enter the well and extend its length. Finally, operators and lessees could have considered pursuing a lease that does not have a pooling clause. According to one of Professor Ernest E. Smith’s recent articles, it is legally permitted to horizontally drill across leased tracts, regardless of the presence of a pooling clause.

The Commission and its Examiners need to make a more diligent inquiry into whether an applicant has made the required good faith effort.

The Commission has been given discretion in its determination of a fair and reasonable offer. However, an applicant must have met the required prerequisites before the Commission has jurisdiction. The Commission should require MIPA applicants to present evidence that sufficiently establishes that a good faith effort was made. It is likely the confusion has resulted because the Texas Supreme Court first acknowledged the requirement in 1984. I recommended that the Legislature address the issue. They are in the best position to clarify whether the requirement must be considered before moving further into a MIPA application. Whether the Legislature incorporates the requirement into the statute or determines it is needless, clarification is needed for the Commission to properly apply it. I further discussed the recent concern that the interests granted by the Commission to unleased interest owners served to undermine the Act itself. I suggested that the concern was unwarranted. The Commission’s role does not involve providing perfectly balance interest in a proposed MIPA unit. Rather, its orders must contain terms that fair and reasonable. The MIPA does not only serve as an Act to encourage voluntary pooling. It is also the tool the Legislature provided for the protection of small-tract owners. Commission orders granting beneficial interests to small-tract owners does not go beyond the purpose of the statute. I provided some solutions that operators and other oil and gas developers might be able to use as creative solutions to the overly beneficial grants.

VI. Conclusion Even though the MIPA was enacted for the protection of small-tract owners and to encourage mineral interest owners to reach voluntary agreements, its recent use has been within the Act’s purpose. Previously, a large portion of the litigation around the MIPA involved the determination of what constituted a fair and reasonable offer. Although the statute has recognized that voluntary pooling offers must have been fair and reasonable, a bright line rule has yet to be established. This issued has persisted to the recent usage of the MIPA. More than anything, the rules Texas courts have created as guidelines in the determination have not been followed. Applicants are required to have made a good faith effort to reach voluntary pooling agreements before the Commission has authority to order compulsory pooling.

See John S. Lowe, et. al. Oil and Gas Law 7th ed. (2018); see also Railroad Com. of Texas v. Pend Oreille Oil & Gas Co., 817 S.W.2d 49–50 (Tex. 1991) (J. Mauzy, concurring); Ernest E. Smith, The Texas Compulsory Pooling Act (part 1) 1004–06. 2 162 Tex. 274, 346 S.W.2d 801 (Tex. 1961). 3 Id. at 811 (1961) (“[W]e think the 1/3-2/3 proration formula is an unreasonable basis upon which to prorate the gas production from this reservoir. It does not . . . afford each producer in the field an opportunity to produce his fair share of the gas from the reservoir.”). 4 See id. at 802. 5 163 Tex. 417, 357 S.W.2d 364 (Tex. 1962). 6 Id. at 376. 7 380 S.W.2d 558–60 (Tex. 1964) (“We do say that the 5050 formula results in the uncompensated drainage of an unreasonable amount of oil from beneath respondents’ tracts, thus preventing them from a fair chance to recover their proportionate share in the reservoir.”). 8 Id. at 559–60.

Halbouty v. Railroad Comm’n 163 Tex. 417, 357 S.W.2d 357, 374 (Tex. 1962); see also Atlantic Ref. Co. v. Railroad Comm’n 162 Tex. 274, 346 S.W.2d 801, 811 (Tex. 1961) (“neither does it afford each producer in the field an opportunity to produce his fair share of the gas from the reservoir”); Railroad Com. of Texas v. Shell Oil Co., 380 S.W.2d 558, 560 (Tex. 1964) (“The test in that case is whether he has an opportunity to produce his fair share of the gas in the reservoir.”); and Ernest E. Smith, The Texas Compulsory Pooling Act (part 1) 1006. 10 See e.g., Atlantic Ref. Co. v. Railroad Comm’n, 162 Tex. 274, 346 S.W.2d 801 (1961) (discussing . . . ); Railroad Comm’n v. Humble Oil & Ref. Co., 193 S.W.2d 824 (Tex. Civ. App. — Austin 1946, writ ref’d n.r.e.) (stating that . . . ); and Halbouty v. Railroad Comm’n, 163 Tex. 417, 357 S.W.2d 364 (1962) (discussing . . . ). 11 See Railroad Com. of Texas v. Pend Oreille Oil & Gas Co., 817 S.W.2d 36, 49 (Tex. 1991) (J. Mauzy, concurring) (“independent producers and small-tract owners saw no need for forced pooling”).

R.R.Comm’n. of Tex. v. Pend Oreille Oil & Gas Co., 817 S.W.2d 36, 41 (Tex. 1991) (citing Carson v.R.R. Comm’n. of Tex., 669 S.W.2d 315, 316 (Tex. 1984). 47 669 S.W.2d 315 (Tex. 1984). 48 Id. at 317. 49 Id. 50 R.R.Comm’n. of Tex. v. Pend Oreille Oil & Gas Co., 817 S.W.2d 36, 40 (Tex. 1991). 51 Id. 52 Id. (citing Carson v. R.R.Comm’n. of Tex., 669 S.W.2d 315, 318 (Tex. 1984). 53 See Windsor Gas Corp. v. R.R.Comm’n. of Tex., 529 S.W.2d 834, 837 (Tex. App. — Austin 1975, cause dismissed); see also Ernest E. Smith, The Texas Compulsory Pooling Act, 44 TEXAS L. REV. 387, 388 (1966). 54 Ernest E. Smith, The Texas Compulsory Pooling Act, 44 TEXAS L. REV. 387, 388–89 (1966). 55 See supra note 47–49 and accompanying sentences. 56 Windsor Gas Corp. v. Railroad Com. of Texas, 529 S.W.2d 834, 835 (Tex. App. — Austin 1975, cause dismissed*). 57 Windsor Gas Corp., 529 S.W.2d at 836–37 (Tex. App. — Austin 1975, cause dismissed*). 58 Windsor Gas Corp., 529 S.W.2d at 837 (Tex. App. — Austin 1975, cause dismissed*). 59 Carson v. Railroad Com. of Texas, 669 S.W.2d 315, 318 (Tex. 1984). 60 See id. 61 Id. at 318. 62 Id. 63 Railroad Com. of Texas v. Pend Oreille Oil & Gas Co., 817 S.W.2d 36, 43 (Tex. 1991) (citing American Operating Co. v. Railroad Com. of Texas, 744 S.W.2d 149, 154 (Tex. App. — Houston [14th Dist.] 1987, writ denied).

Ernest E. Smith, The Texas Compulsory Pooling Act (part 1) 1007. 13 Ernest E. Smith, The Texas Compulsory Pooling Act (part 1) 1007, citing Sealy, The Effect of Conservation Laws and Practices Upon the Express Provisions of Oil and Gas Leases, SEVENTH ANNUAL ROCKY MOUNTAIN MINERAL LAW INSTITUTE 1, 32–33 (1962). 14 Pend Oreille Oil & Gas Co., at 50 (J. Mauzy, concurring). 15 Infra Part . . . 16 See Railroad Com. of Texas v. Pend Oreille Oil & Gas Co., 817 S.W.2d 36, 40 (Tex. 1991) (“The obvious intent of the legislature is to encourage voluntary pooling.”). 17 See infra Part III (A). 18 Pend Oreille Oil & Gas Co., 817 S.W.2d at 40 (citations omitted). 19 See id. at 50 (J. Mauzy, concurring) (citing 3 Smith & Weaver, Texas Law of Oil and Gas § 12.1, at 7, § 12.3, at 33-1). 20 Tex. Nat. Res. Code § 102.003 (Lexis). 21 See supra note 2 (indicating the date of the Normanna decision). 22 See Ernest E. Smith, The Texas Compulsory Pooling Act (part 1) 1003, 1010. 23 See Hitzelberger v. Samedan Oil Corp., 948 S.W.2d 497, 509 (Tex. App. — Waco 1997, pet. denied) f.n. 7. 24 Railroad Com. of Texas v. Pend Oreille Oil & Gas Co., 817 S.W.2d 36, 40 (Tex. 1991) (citing Tex. Nat. Res. Code § 102.011). 25 Id. 26 Tex. Nat. Res. Code § 102.011. 27 Id. 28 Id. 29 Id. 30 See id. 31 Tex. Nat. Res. Code § 102.012. 32 See supra Part II, notes 16–18. 33 Tex. Nat. Res. Code § 102.013(a). 34 Id. at subsection (b). 35 Id at subsection (c). 36 See supra Part III (A), n.31. 37 Tex. Nat. Res. Code § 102.013(a). 38 Id. at subsection (c). 39 See e.g., Am. Operating Co. v. R.R.Comm’n. of Tex., 744 S.W.2d 149, 152 (Tex. App.—Houston [14th Dist.] 1987, writ denied) (stating that an offer must consider all pertinent facts that are important to a reasonable person) (citation omitted); Windsor Gas Corp. v. R.R. Comm’n. of Tex., 529 S.W.2d 834, 837 (Tex. App.—Austin 1975, writ granted); R.R. Comm’n. of Tex. v. Pend Oreille Oil & Gas Co., 817 S.W.2d 36, 43 (Tex. 1991); and Ernest E. Smith, The Texas Compulsory Pooling Act (Part 2) 387, 389 (1966). 40 Carson v. R.R. Comm’n. of Tex. 669 S.W.2d 315, 317 (Tex. 1984). 41 Tex. Nat. Res. Code § 102.015. 42 Id. 43 Id. 44 Id. 45 Id.

See supra Part II, notes 16–18 and accompanying text. American Operating Co. v. Railroad Com. of Texas, 744 S.W.2d 149, 154 (Tex. App. — Houston [14th Dist.] 1987, writ denied) 66 Pend Oreille Oil & Gas Co., S.W.2d at 43. 67 Id. 68 Carson v. Railroad Com. of Tex., 669 S.W.2d 315, 317 (Tex. 1984) (citation omitted). 69 HOUSE COMM. ON OIL, GAS, & MINING, BILL ANALYSIS, TEX. S.B. 359, 62D LEG. (1971). 70 Tex. Nat. Res. Code § 102.052(a). 71 Id. 72 Windsor Gas Corp. v. R.R. Comm’n of Tex., 529 S.W.2d 834, 837 (Tex. App.—Austin 1975, writ granted) (citation omitted). 73 Tex. Nat. Res. Code § 102.052(a). 74 See R.R. Comm’n of Tex. v. Pend Oreille Oil & Gas Co., 817 S.W.2d 36, 42–43 (Tex. 1991). 75 732 S.W.2d 675 (Tex. App.—Houston [14th Dist.] 1987, writ ref’d n.r.e.). 76 Id. at 678. 77 Id. 65

Moses MIPA Unit, Well No. 1H, the Goliath MIPA Unit, Well No. 1H, the King David MIPA Unit, Well No. 1H, and the Ramses MIPA Unit, Well No. 1H, Phantom (Wolfcamp) Field, Reeves County, Texas, Oil & Gas Docket No. 080304960 at 1–5 (Hearings Div. Examiners’ Report and Recommendation July 7, 2017) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/41287/08-0304960-et-al-cogate-pfd.pdf; and Tex. R.R. Comm’n, The Application of Colgate Operating, LLC., Pursuant to the Mineral Interest Pooling Act for the Formation of a Pooled Unit for the Cantaloupe MIPA Unit, Well No. 1H, Phantom (Wolfcamp) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0302755 at 1–5 (Hearings Div. Examiners’ Report and Recommendation January 17, 2017) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/39458/08-0302755-colgate-operating-llcexaminers-report.pdf. 110 Tex. R.R. Comm’n, Permian Basin, https://www.rrc.state.tx.us/oil-and-gas/major-oil-and-gasformations/permian-basin/. 111 See Oil & Gas Counties & Associated Districts, Texas Railroad Commission. https://www.rrc.state.tx.us/aboutus/locations/oil-gas-counties-districts/. 112 See note 111 and accompanying text. 113 Tex. R.R. Comm’n, Application of Ammonite Oil and Gas, Inc., Pursuant to the Mineral Interest Pooling Act for the Energen Elmer 33-67 Well, Two Georges (Bone Spring) Field, Ward County, Texas and the Energen Kath “A” 3-11 Well, Two Georges (Bone Spring) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0282996 at 2 (Hearings Div. March 25, 2015) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/33280/08-0282996-mipa-pfd-rml.pdf. 114 Id. at 2–3. 115 Id. at 2. 116 Id. at 3. 117 Id. at 3–4. 118 Application of Ammonite Oil and Gas, Inc., Oil & Gas Docket No. 08-0282996 at 7. 119 See id. at 7–11. 120 Id. at 10 (citation omitted). 121 Id. 122 Id. at 12. 123 See Tex. R.R. Comm’n, Application of Ammonite Oil and Gas, Inc., Pursuant to the Mineral Interest Pooling Act for the Energen Elmer 33-67 Well, Two Georges (Bone Spring) Field, Ward County, Texas and the Energen Kath “A” 3-11 Well, Two Georges (Bone Spring) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0282996 at 2 (Hearings Div., Final Order March 29, 2016). https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/33279/08-0282996-ammonite-final-order.pdf. 124 Tex. R.R. Comm’n, The Application of Colgate Operating, LLC, Pursuant to the Mineral Interest Pooling Act for the Formation of a Pooled Unit for the Cantaloupe MIPA Unit, Well No. 1H, Phantom (Wolfcamp) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0302755 at 1–2 (Hearings Div., Examiners’ Report and Recommendation January 17, 2017)

Am. Operating Co. v. R.R. Comm’n of Tex., 744 S.W.2d 149, 152-53 (Tex. App.—Houston [14th Dist.] 1987, writ denied) (citation omitted). 79 Id. 80 Id. 81 See Browning Oil Co. v. Luecke, 38 S.W.3d 625, 635 (Tex. App.—Austin 2000, pet. denied) (discussing technology allowing recovery of oil and gas in areas it was not thought possible). 82 See supra notes 21–24 and accompanying text. 83 See Ernest E. Smith, The Texas Compulsory Pooling Act, 43 TEXAS L. REV. 1003, 1010 (1965). 84 Id. 85 See id. at 1010–1011. 86 See Ronnie Blackwell, Forced Pooling Within The Barnett Shale: How Should The Texas Mineral Interest Pooling Act Apply To Units With Horizontal Wells?, 17 TEX. WESLEYAN L. REV. 1, 2 (2010). 87 See, e.g., Tex. R.R. Comm’n, Application of WCS Oil & Gas Corporation to Consider Approval of Overlapping Proration Units for the 276.87 Acres Unit WOLZ Lease, Well No. 1H, Giddings (Austin Chalk-3) and Giddings (Austin Chalk, Gas) Fields, Lee County, Texas, Docket No. 03-0275290 at 3–4 (Oil & Gas Div. April 17, 2012) (hearing of application). 88 Tex. Nat. Res. Code § 102.011 (“for the purpose of avoiding the drilling of unnecessary wells, protecting correlative rights, or preventing waste”). 89 See, e.g., Browning Oil Co. v. Luecke, 38 S.W.3d 625, 633 (Tex. App.—Austin 2000, pet. Denied). 90 See Oil & Gas Docket No. 02697416 (Railroad Commission of Texas Hearing Division). 91 See id. at 8. 92 See id. at 9. 93 See id. at 9. 94 See id. at 9. 95 See Oil and Gas Law casebook at page 781. 96 See supra Part II notes 15–17 and accompanying text. 97 See Oil and Gas Law casebook at page 780. 98 Ronnie Blackwell, Forced Pooling Within The Barnett Shale: How Should The Texas Mineral Interest Pooling Act Apply To Units With Horizontal Wells?, 17 TEX. WESLEYAN L. REV. 1, 10 (2010). 99 Id. 100 Id. 101 Id. at 11. 102 Id. at 12. 103 Id. at 11–12. 104 See supra Part II; see also Railroad Com. of Texas v. Pend Oreille Oil & Gas Co., 817 S.W.2d 36, 50 (Tex. 1991) (J. Mauzy, concurring). 105 See Texas Railroad Commission, Permian Basin, https://www.rrc.state.tx.us/oil-and-gas/major-oil-and-gasformations/permian-basin/. 106 Id. 107 Id. 108 Id. 109 See e.g., Tex. R.R. Comm’n, The Applications of Colgate Operating, LLC., Pursuant to the Mineral Interest Pooling Act for the Formation of Pooled Units for the

County, Texas, Oil & Gas Docket No. 08-0304960 (Hearings Div., Final Order, August 1, 2017) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/41286/08-0304960-colgate-ord.pdf. 159 Id. at 2 160 See Tex. R.R. Comm’n, Application of Colgate Operating, LLC, Pursuant to the Mineral Interest Pooling Act to Amend the Pooled Unit for the Cantaloupe MIPA Well No. 1H, the Moses MIPA Well No. 1H, the Goliath MIPA Well No. 1H, the King David MIPA Well No. 1H, and the Ramses MIPA Well No. 1H, Phantom (Wolfcamp) Field, Reeves County, Texas, Oil & Gas Docket Nos. 08-0316736, 080316738, 08-0316750, 08-0316751, and 08-0316752 at 1 (Hearings Div., Examiner’s Report and Recommendation April 9, 2019). https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/51375/08-0316736-colgate-mipa-final-order.pdf. 161 Id. at 4. 162 Id. at 6. 163 Id. 164 Id. at 6–7. 165 Id. at 7. 166 Id. 167 Id. at 8. 168 Id. 169 See id. at 9. 170 See id. at 8. 171 Id. at 9. 172 Id. 173 Id. at 15. 174 Id. at 11. 175 Id. 176 Id. 177 Tex. R.R. Comm’n, Application of Colgate Operating, LLC Pursuant to the Mineral Interest Pooling Act to Amend the Pooled Unit for the Cantaloupe MIPA Well No. 1H, Phantom (Wolfcamp) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0316736 at 1 (Hearings Div., Final Order, April 9, 2019) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/51375/08-0316736-colgate-mipa-final-order.pdf. 178 Id. at 1. 179 Id. at 2. 180 Id. 181 Id. 182 Id. 183 Id. 184 Id. at 1. 185 Tex. R.R. Comm’n, Application of Colgate Operating, LLC Pursuant to the Mineral Interest Pooling Act to Amend the Pooled Unit for the Moses MIPA Well No. 1H, Phantom (Wolfcamp) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0316738 at 1 (Hearings Div., Final Order, April 9, 2019) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/51546/08-0316738-colgate-mipa-final-order.pdf. 186 Id. at 2. 187 Id. 188 Id. 189 Id.

https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/39458/08-0302755-colgate-operating-llc-examiners-report.pdf. 125 Id. at 1. 126 Id. at 2. 127 Id. 128 Id. 129 Id. 130 Id. at 3. 131 Id. at 3–4. 132 Id. at 3. 133 Oil & Gas Docket No. 08-0302755, at 11. 134 Id. at 6. 135 Id. 136 Id. 137 Id. 138 Id. 139 Oil & Gas Docket No. 08-0302755, at 7. 140 Id. 141 Tex. R.R. Comm’n, The Application of Colgate Operating, LLC, Pursuant to the Mineral Interest Pooling Act for the Formation of a Pooled Unit for the Cantaloupe MIPA Unit, Well No. 1H, Phantom (Wolfcamp) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0302755 at 1 (Hearings Div., Final Order April 25, 2017) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/39459/08-0302755-colgate-operating-llc-ord.pdf. 142

Id. at 2. Id. 144 Id. 145 See id. 146 Tex. R.R. Comm’n, The Applications of Colgate Operating, LLC, Pursuant to the Mineral Interest Pooling Act for the Formation of Pooled Units for the Moses MIPA Unit, Well No. 1H, the Goliath MIPA Unit, Well No. 1H, the King David MIPA Unit, Well No. 1H, and the Ramses MIPA Unit, Well No. 1H, Phantom (Wolfcamp) Field, Reeves County, Texas, Oil & Gas Docket Nos. 08-0304960, 080304985, 08-0305022, and 08-0305026 at 2 (Hearings Div., Examiner’s Reportand Recommendation July 7, 2017) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/41287/08-0304960-et-al-cogate-pfd.pdf. 147 Id. 148 Id. 149 Id. at 1–2. 150 Id. at 3. 151 Id. 152 See id. 153 See The Applications of Colgate Operating, LLC, Tex. R.R. Comm’n, Oil & Gas Docket Nos. 08-0304960, 080304985, 08-0305022, and 08-0305026 at 6–10. 154 Id. at 6. 155 Id. 156 Id. 157 Id. at 6–7. 158 E.g., Tex. R.R Comm’n, The Applications of Colgate Operating, LLC, Pursuant to the Mineral Interest Pooling Act for the Formation of Pooled Units for the Moses MIPA Unit, Well No. 1H, Phantom (Wolfcamp) Field, Reeves 143

221

Windsor Gas Corp. v. R.R. Com. of Texas, 529 S.W.2d 834, 837 (Tex. App. — Austin 1975, cause dismissed*) (citation omitted). 222 See Buttes Resources Co. v. R.R. Com. of Texas, 732 S.W.2d 675 (Tex. App. — Houston [14th Dist.] 1987, writ denied). 223 Tex. R.R. Comm’n, Application of Ammonite Oil and Gas, Inc., Pursuant to the Mineral Interest Pooling Act for the Energen Elmer 33-67 Well, Two Georges (Bone Spring) Field, Ward County, Texas and the Energen Kath “A” 3-11 Well, Two Georges (Bone Spring) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0282996 at 2–3 (Hearings Div. March 25, 2015) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/33280/08-0282996-mipa-pfd-rml.pdf. 224 Id. at 2. 225 Id. at 9. 226 See id. 227 Id. at 7. 228 See id. at 10. 229 See Tex. R.R. Comm’n, Application of Ammonite Oil and Gas, Inc., Pursuant to the Mineral Interest Pooling Act for the Energen Elmer 33-67 Well, Two Georges (Bone Spring) Field, Ward County, Texas and the Energen Kath “A” 3-11 Well, Two Georges (Bone Spring) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0282996 at 1–2 (Hearings Div., Final Order March 29, 2016). 230 Tex. R.R. Comm’n, Application of Ammonite Oil and Gas, Inc., Pursuant to the Mineral Interest Pooling Act for the Energen Elmer 33-67 Well, Two Georges (Bone Spring) Field, Ward County, Texas and the Energen Kath “A” 3-11 Well, Two Georges (Bone Spring) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0282996 at 7 (Hearings Div., Proposal for Decision March 25, 2015). 231 Tex. Nat. Res. Code § 102.004(d). 232 Application of Ammonite Oil and Gas, Inc., Oil & Gas Docket No. 08-0282996 at 4–5, 10 (Proposal for Decision). 233 Id. at 10. 234 Id. 235 Id. at 8. 236 Id. 237 Id. at 5, 9. 238 See Tex. R.R. Comm’n, Application of Ammonite Oil and Gas, Inc., Pursuant to the Mineral Interest Pooling Act for the Energen Elmer 33-67 Well, Two Georges (Bone Spring) Field, Ward County, Texas and the Energen Kath “A” 3-11 Well, Two Georges (Bone Spring) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0282996 at 1 (Hearings Div., Final Order March 29, 2016). 239 See R.R.Comm’n. of Tex. v. Pend Oreille Oil & Gas Co., 817 S.W.2d 36, 43 (Tex. 1991); see also Windsor Gas Corp. v. R.R.Com. of Texas, 529 S.W.2d 834 (Tex. App. — Austin 1975, cause dismissed). 240 HOUSE COMM. ON OIL, GAS, & MINING, BILL ANALYSIS, TEX. S.B. 359, 62D LEG. (1971). 241 Pend Oreille Oil & Gas Co., at 43. 242 See Tex. Nat. Res. Code § 102.052. 243 Oil & Gas Docket No. 08-0282996, at 9–10. 244 See supra Part II. 245 See supra Part II.

190

Id. 191 Tex. R.R. Comm’n, Application of Colgate Operating, LLC Pursuant to the Mineral Interest Pooling Act to Amend the Pooled Unit for the Goliath MIPA Well No. 1H, Phantom (Wolfcamp) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0316750 at 1 (Hearings Div., Final Order, April 9, 2019) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/51548/08-0316750-colgate-mipa-final-order.pdf. 192 Id. at 1. 193 Id. at 2. 194 Id. 195 Id. 196 Id. 197 Id. 198 Tex. R.R. Comm’n, Application of Colgate Operating, LLC Pursuant to the Mineral Interest Pooling Act to Amend the Pooled Unit for the King David MIPA Well No. 1H, Phantom (Wolfcamp) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0316751 at 1 (Hearings Div., Final Order, April 9, 2019) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/51550/08-0316751-colgate-mipa-final-order.pdf. 199 Id. at 1. 200 Id. 201 Id. at 2. 202 Id. 203 Id. 204 Tex. R.R. Comm’n, Application of Colgate Operating, LLC Pursuant to the Mineral Interest Pooling Act to Amend the Pooled Unit for the Ramses MIPA Well No. 1H, Phantom (Wolfcamp) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0316752 at 1 (Hearings Div., Final Order, April 9, 2019) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/51553/08-0316752-colgate-mipa-final-order.pdf. 205 Id. 206 Id. at 2. 207 Id. 208 Id. 209 Ammonite Oil & Gas Corp. v. R.R. Comm’n of Tex., No. 04-20-00465-CV LEXIS NEXIS 8649 *1, *8 (Tex. App. — San Antonio 2021, no pet.) (citation omitted). 210 Id. (citation omitted). 211 Carson v. Railroad Com. of Tex., 669 S.W.2d 315, 317 (Tex. 1984) (citation omitted). 212 Id. (citation omitted). 213 Id. (citation omitted). 214 See Tex. Nat. Res. Code § 102.013(c). 215 See Railroad Com. of Texas v. Pend Oreille Oil & Gas Co., 817 S.W.2d 36, 43 (Tex. 1991). 216 See Carson v. Railroad Com. of Texas, 669 S.W.2d 315, 317 (Tex. 1984). 217 Id. 218 R.R. Com. of Texas v. Pend Oreille Oil & Gas Co., 817 S.W.2d 36, 40 (Tex. 1991). 219 Tex. Nat. Res. Code § 102.052(a). 220 Id.

275

Id. at 3. See supra Part V(B.2) for the discussion concerning Colgate’s original Cantaloupe MIPA Unit. 277 Tex. R.R. Comm’n, The Applications of Colgate Operating, LLC, Pursuant to the Mineral Interest Pooling Act to Amend the Pooled Units for the Cantaloupe MIPA Well No. 1H, the Moses MIPA Well No. 1H, the Goliath MIPA Well No. 1H, the King David MIPA Well No. 1H, and the Ramses MIPA Well No. 1H, Phantom (Wolfcamp) Field, Reeves County, Texas, Oil & Gas Docket Nos. 08-0316736, 080316738, 08-0316750, 08-0316751, and 08-0316752 at 2 (Hearings Div., Examiner’s Report and Recommendation February 4, 2019) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/51374/colgate-pfd.pdf. 278 Id. at 1. 279 Id. at 12. 280 See id. at 10. 281 Id. 282 Id. at 11. 283 Id. 284 See supra Part III(A.1). 285 See supra Part III(A.1). 286 See supra Part II. 287 See supra Part II. 288 See supra Part III(A.1) note 49 and accompanying text. 276

246

See Carson v. R.R.Comm’n. of Tex., 669 S.W.2d 315, 317 (Tex. 1984). 247 Tex. R.R. Comm’n, The Application of Colgate Operating, LLC, Pursuant to the Mineral Interest Pooling Act for the Formation of a Pooled Unit for the Cantaloupe MIPA Unit, Well No. 1H, Phantom (Wolfcamp) Field, Reeves County, Texas, Oil & Gas Docket No. 08-0302755 at 1–2 (Hearings Div., Examiners’ Report and Recommendation January 17, 2017) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/39458/08-0302755-colgate-operating-llc-examiners-report.pdf. 248 See id. at 1–3. 249 See id. at 4–5. 250 Id. at 5. 251 See id. at 5–6. 252 Id. at 6. 253 Id. at 7. 254 See id. at 3. 255 Carson v. R.R. Comm’n of Tex., 669 S.W.2d 315, 317 (Tex. 1984) (citation omitted). 256 Id. at 6. 257 See id. 258 See id. at 3, 7. 259 See supra Part III(A.1). 260 Carson v. R.R. Comm’n . of Tex., 669 S.W.2d 315, 317 (Tex. 1984) (citation omitted) (emphasis added). 261 Oil & Gas Docket No. 08-0302755 at 1. 262 Id. at 3. 263 See Tex. R.R. Comm’n, The Applications of Colgate Operating, LLC, Pursuant to the Mineral Interest Pooling Act for the Formation of Pooled Units for the Moses MIPA Unit, Well No. 1H, the Goliath MIPA Unit, Well No. 1H, the King David MIPA Unit, Well No. 1H, and the Ramses MIPA Unit, Well No. 1H, Phantom (Wolfcamp) Field, Reeves County, Texas, Oil & Gas Docket Nos. 08-0304960, 08-0304985, 08-0305022, and 08-0305026 at 2 (Hearings Div., Examiner’s Report and Recommendation July 7, 2017) https://portalvhdskzlfb8q9lqr9.blob.core.windows.net/media/41287/08-0304960-et-al-cogate-pfd.pdf. 264 Id. at 4. 265 Id. at 1, 3. 266 Id. at 6. 267 Id. 268 Id. at 6. 269 See id. at 3. 270 See id. at 6. 271 See supra Part IV(D.3). 272 Carson v. R.R. Com. of Tex., 669 S.W.2d 315, 317 (Tex. 1984) (citation omitted). 273 Oil & Gas Docket Nos. 08-0304960, 08-0304985, 080305022, and 08-0305026 at 7. 274 Id. at 1.

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