STCL Houston Energy Newsletter Vol 1: Spring 2017

ENERGY NEWSLETTER South Texas

Harry L. Reed

College of Law Houston

Institute of Oil & Gas

Oil & Gas Law Society’s Update Developing Trainings, Events, and Energy Students “You have power over your mind, not outside events. Realize this and you will find strength.”

Marcus Aurelius’ statement seems more relevant to the law student than ever, struggling to find balance while maintaining persistence and patience in developing themselves into future attorneys. The price of oil hasn’t done the oil and gas student any favors, forcing companies to restrict education funding, internships, and training. However, this organization, thanks in no small part to Professor Kulander, Professor Festa, and all the student representatives of the Oil & Gas Law Society, has fought hard to build and develop an organization to help train us all in anticipation of better days ahead.

The result of this hard work is the development of an avenue for students, alumni, and attorneys in the oil and gas industry to be able to engage in dialogue and discuss relevant legal issues in the oil and gas industry through this newsletter.

The Oil & Gas Law Society with the help of the Association of International Petroleum Negotiators, hosted at South Texas College of Law Houston the first in a series of events last Fall with the explicit purpose in mind of developing a forum for educating and updating the Houston community on the developments in regions around the world. The International Energy

Series: Latin America event in Fall 2016 hosted an incredible array of speakers from the AIPN, Anadarko, Platts, and attorneys from Latin America to talk about events in Columbia, Venezuela, Brazil, Mexico, and others and give our students along with dozens of AIPN members the opportunity to learn from some of the most significant players in the region.

“You have power over your mind, not outside events.

Realize this and you will find strength.”

Spring 2017 has seen an incredible start with students attending the Institute for Energy Law’s 68th Annual Oil & Gas Law Conference thanks to the Jeff Steen Fund for Oil & Gas Law Education through the Harry Reed Institute of Oil & Gas. The Institute has also started its first every Training Certificate led by Tim Brown and Ken Rice from Anadarko Petroleum, which is free to the Oil & Gas Law Society’s student members. Our Institute and associated Oil & Gas Law Society students at South Texas College of Law Houston are immensely grateful to all students, Energy Alumni, academia, law firms, and companies who helped make this Energy Newsletter a reality.

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Spring 2017 Edition

Contents •••

Oil & Gas Law Society’s Update .................................. 1 Letter from the Editor ........ 2 Texas Energy Law Predictions for 2017 and Forecasting Energy Policy in a Trump Presidency....... 3 Model Contract Differences Between Drafting for Global and American Operations: An AAPL and AIPN Comparison Introduction .. 5 Denbury Green II: No Naked Assertions Enable Eminent Domain............... 10 An Introduction to Decommissioning Risks and Challenges.................. 15 EPA Fracking Report: In So Many Words, No New Revelations! ....................... 19

Letter from the Editor Editorial Board

Dear Reader,

•••

On behalf of the Editorial Board and the Members of the ENERGY NEWSLETTER, we are pleased to present you Edition 1, Volume 1. 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 first-ever ENERGY NEWSLETTER or publication through South Texas College of Law Houston dealing with the energy industry. Having such a center stage in downtown Houston, the newsletter team looks forward to bringing exciting articles co-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 Christopher Kulander’s snapshot looking forward to 2017 and the challenges and risks that the industry faces both at home and abroad. Next, Sean Berwald discusses with PO&G Resources’ General Counsel, George Oggero, an introduction to the complexities of model contract differences in the AIPN and AAPL Joint Operating Agreements as they pertain to both global and domestic companies. We then present a case assessment by Chris Robertson and Jeffus Law Office, Of Counsel, Michael Vargo, on the Denbury Green Pipeline-Texas, LLC v. Texas Rice Land Partners, Ltd that came out in 2016. After that, we have Nadine Sheta’s introduction to the risks and challenges of Decommissioning. Lastly, we have Andre Stanojcic’s assessment of the December 2016 EPA Fracking Report.

On behalf of the Editorial Board and the 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,

Director SEAN BERWALD Editor-in-Chief VESTA “VESTITA” KUNTZ Managing Editor ROBERT SMALLWOOD Articles/Note Editors KATILYN HAYNES RACHEL SCHILLER DAVID FRAZER Creative Design RHONNIE EMBRES NADINE SHETA

Authors in Practice ••• CHRISTOPHER KULANDER GEORGE OGGERO MICHAEL VARGO ANDRIJA “ANDRE” STANOJCIC

Student Authors ••• NADINE SHETA SEAN BERWALD CHRISTOPHER ROBERTSON

Vesta Kuntz Editor-In-Chief

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increase in oil prices has helped, but this tentative rise could be squelched at OPEC’s meeting on November 30. Forty-six upstream bankruptcies have been filed in Texas, representing approximately $29.7 billion in cumulative secured and unsecured debt. Hopefully, 2017 will see a turnaround.

Texas Energy Law Predictions for 2017 [1] and Forecasting Energy Policy in a Trump Presidency [2] By: Christopher Kulander, J.D. Haynes and Boone, Of Counsel, Director of the Harry Reed Institute for Oil & Gas, and Professor at STCLH

Forecasting Energy Policy in a… Trump Presidency (Q&A with Texas Lawyer in 2016)

Texas Energy Law Predictions for 2017 The first two things that come to mind when I think of oil and gas/energy law in Texas in 2016 is (1) the long-awaited release of the new form joint operating agreement by the American Association of Petroleum Landmen (AAPL) and (2) the continuing downward surge of bankruptcies and reorganizations in the upstream sectors of the oil and gas industry.

Whenever multiple parties own oil and gas properties and would like to development them as a group, an agreement should be reached on a variety of matters including initial drilling, payment of expenses, the operation of the well(s), the division of production, and further development of the property. The joint operating agreement (JOA) serves this function.

In 1956, the AAPL published the first form JOA. It was later updated in 1977, 1982, and 1989. After over 25 years, however, the form was seen as unresponsive to horizontal operations and other changes in technology, accounting procedures, and the multitude of case law that has poured forth over the last couple of decades. The AAPL formed a task force in 2011 to update the form and in December 2015, the AAPL’s governing Board of Directors adopted the new form produced by the task force -- “Form 6102015 JOA.” On the drearier side, 2016 produced a long slog of bankruptcies and reorganizations due to the persisting slump in commodity prices. Since the beginning of 2015, 105 North American oil and gas producers have filed for bankruptcy. All told, these bankruptcies involve approximately $67.9 billion in cumulative secured and unsecured debt. As of October 19, 2016, Haynes and Boone, LLP reports that 61 producers have filed bankruptcy, so far, in 2016, representing approximately $50.6 billion in cumulative secured and unsecured debt. A slow and steady

1. How would you describe the energy policy position of U.S. presidential candidate Donald Trump regarding the U.S. oil and gas industry?

So much of what Mr. Trump says comes out extemporaneously that it can be difficult to derive a concise statement of his positions. Actions speak louder than words, however, and his recent visit to North Dakota—not exactly a battleground state, but the second largest producer of oil—plus the drill-baby-drill extortions he made while there suggests a hydrocarbon-first agenda. This is reflective—perhaps inadvertently—of the reality that well over 80% of energy use is generated by fossil fuels and will remain to be so for the foreseeable future.

Some of Mr. Trump’s optimism about the future of oil and gas appears to come from his belief that climate change (read: global warming) is not occurring and is therefore not an issue to be considered when establishing an energy portfolio.

He has decried U.S. participation in the Paris climate accords, an agreement wherein a country pledges to limit emissions believed to contribute to global warming. He supports the construction of the Keystone XL pipeline.

2. What do you forecast the political climate for energy policy-making in the United States during the next four years will be if Donald Trump is elected to be the next U.S. president?

In four words: fewer subsidies for renewables.

Certainly, renewable programs that do not show promise of standing on their own financial feet— they all get fired. That would bode ill for a significant portion of renewables in that many portions of that market are dependent on taxpayer support. I would guess Trump would work to 3

remove barriers to the exportation of LNG and crude. I also believe that agency appointments would temper recent action seen as detrimental to the oil and gas industry, such as methane emission control or aggregation of sources for attainment standards.

world. If the price of natural gas increases, the use of American LNG in Europe as an alternative to coal and Russian natural gas provides not only a customer base for American producers and shippers but also a means curtails future coal use and contribute to lowering CO2 emissions while curtailing the reach of Putin’s Russia. A 2012 DoE-commissioned study concluded that LNG exports would provide an overall net economic boost across the U.S. economy. [1] The fate of pending and future applications to export LNG, as well as the larger debate over government’s role in such exports, hangs in the balance of this election.

“The fate of pending and future applications to export LNG, as well as the larger debate over government’s role in such exports, hangs in the balance of this election.”

3. What do you predict the new president might be able to accomplish on the domestic front in the oil and gas sector during the next four years given the likely political and economic contexts?

5. How will the next president respond to Mexico’s energy reforms?

It will be interesting if the U.S. government will promote U.S. business activities in Mexico.

Oil and gas prices are starting to rise again and the next round of bidding for rights to develop in Mexican waters is approaching.

Not surprisingly, if a Democratic administration instead of a Republican one succeeds Obama, I expect less of a course change at the executive agencies that affect energy. Importantly, the oil and gas industry has donated much more money to Clinton than Trump. This suggests the industry believes she would be more pragmatic than her predecessor with regards to the paramount position fossil fuels play in the transportation and electricity generation sectors. The industry has been unhappy with agency action over the last eight years related to several issues, such as required measures to prevent methane dispersal during drilling and production, limitations on drilling locations imposed by the Endangered Species Act, and a perceived reluctance to facilitate LNG and crude exports.

6. Do you have any other comments that you would like to make about this presidential election’s potential impact on the U.S. oil and gas sector?

Historically, American energy policy has primarily been reactionary. Each administration comes in with certain plans and then gets hit with events few can predict. Therefore, forecasting what energy policy will be over a four-year or eight-year span is akin to predicting how a rodeo cowboy will ride a bull: I’m pretty sure he’ll try to hang on. Past that, it’s unclear.

4. What do you predict the new president might be able to accomplish related to oil and gas issues in the international arena during the next four years given the likely political and economic contexts?

[1] Portions of the above reprinted with permission from the January 23, 2017, online edition of Texas Lawyer. © 2017 ALM Media Properties, LLC. All rights reserved.

Further duplication without permission is prohibited.

[2] Portions of the above reprinted with permission from the October 28, 2016, online edition of Texas Lawyer. © 2017 ALM Media Properties, LLC. All rights reserved.

Further duplication without permission is prohibited.

I believe great strides can be made to enhance the strategic position of the United States in the

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Generally, the global structure of a production agreement trends towards the host government giving the right of access to an oil or gas basin to a group of companies. Once that process is completed, the group of companies contract their specific rights and obligations amongst each other using a JOA. [3] However, the oil and gas industry is plagued by enormous costs, increasing hostility toward business, and complex political environments. Balancing the technical, financial, and political risks is a full-time task that requires that companies work together to mitigate these risks. Risk mitigation is the central purpose of the JOA, as it seeks to lower costs and allow more efficient production. [4] The JOA allocates risk into three categories: 1) the relationship between the contracting companies (or if international, the contracting companies and the host government), 2) maintaining efficiency while managing project costs, and 3) providing mechanisms for overcoming potential obstacles. Each category presents different issues and evolves with industry changes. Since projects can span decades, the JOA needs to be able to easily adapt to a variety of circumstances and parties. This, in turn, requires petroleum contractors to evolve with the progression of the AAPL and AIPN Model Contracts.

Model Contract Differences Between Drafting for Global and American Operations: An AIPN and AAPL Comparison Introduction By: Sean Berwald and George Oggero, J.D. PO&G Resources, LP., General Counsel, COO, and Land Manager

Intent of Joint Operating Agreement Contract Makers The United States (US), as well as international companies in the upstream petroleum industry, are inherently looking to streamline their projects by using joint ventures (JVs), which allow different parties to work together to mitigate risk. JVs have grown over the decades into increasingly complex operations.

These operations often result from a need for negotiators to find more efficient means of making the final deal. Frequently, the basis of oil and gas operations will use a Joint Operating Agreement (JOA) to govern the project.

The purpose of this article series is to aid energy companies in understanding their expected contractual obligations as they translate between the various model JOAs used. Model contracts in the oil and gas industry allow contracting parties to streamline project operations. The need for Model Contracts in the JOA space has evolved from two main JOAs: the American Association of Professional Landmen (AAPL) and the Association of International Petroleum Negotiators (AIPN). [1] The most widely used JOA in the United States is the 610 Model Form from the AAPL, however globally the most widely used Model Operating Agreement comes from the AIPN. [2] The dynamics of US and global environments vary greatly, requiring flexible drafting styles to maintain efficiency and mitigate risk. The AAPL and AIPN JOAs will be the basis for this Model Contract study.

The core of a JOA is a contract that can be molded and shaped by any company with any provisions desired. The JOA is the agreement that governs the parties involved in the actual operation of developing an oil or gas asset.

“Risk mitigation is the central purpose of the JOA, as it seeks to lower costs and allow more efficient production.�

The most important starting point in understanding the JOA risks is its history and evolution. Each Model Contract has a different lens of history and experience that has guided its construction.

Before the first model form JOA, every petroleum company used their own contracts.

However, the industry, being plagued by increased costs and risks, needed to make its contracting process more efficient and uniform.

The AAPL model form was the first to do this.

The form had its start in 1956, with its first onshore operations Model Operating Agreement, known as Form 610. [5] The AAPL was loosely 5

operating as a governing body for model contracts from this time until the official creation of the AAPL in 1978. This model form was used both in the United States and across the globe as American companies developed hydrocarbon resources abroad. It was first revised in 1977, the year before the official creation of the AAPL. Form 610 was most significantly revised in 1982, 1989, and 2015. These last three revisions of the model form will be the focus of this analysis as they are the most widely used AAPL 610 forms in contracts.

The AAPL model form effectively served all companies globally until the 1970’s nationalization craze. During this period, host governments’ newly formed National Oil Companies (NOCs) required the operating experience of US and European companies. The US industry lost access and autonomy abroad, and international projects became more complex and expensive, thus requiring uniformity in contracting. Complementary to the AAPL 610 Model Form is the AIPN’s JOA Model Contract.

The AIPN JOA was introduced in 1990 and addressed the challenges of the 1982 and 1989 AAPL Model Form. Specifically, the AIPN offered the global industry a more collaborative and flexible model contract than the AAPL’s model form. The AIPN JOA was subsequently revised in 1995, 2002, and 2012.

fundamentals of the JOA, it is only logical that one starts with the most significant JOA to the development of the contract in conjunction with its most far-reaching clause, the Compliance with Laws and Regulations Clause.

“The politicization of the industry in recent years has influenced the decisions of regulators and courts to take a sterner approach to many of the petroleum industry’s practices.”

The AAPL JOA’s relationship between the companies and the government is governed by the applicable law and regulations, monitored by the United States’ governmental authorities. The industry’s ground zero is Houston, Texas. Much of the risks related to the common law legal system are assumed in practice but can be challenging for other international companies coming to do business in the US. The politicization of the industry in recent years has influenced the decisions of regulators and courts to take a sterner approach to many of the petroleum industry’s practices. However, the real challenge for international companies doing business in the US comes from a lack of experience with a common-law legal system. The AAPL has, over time, progressed toward a more inclusive model JOA, because of domestic industry pressures, not as a response to more international investment by the global industry.

The AAPL’s Article XIV, Compliance with Laws and Regulations, from 1956 to 1982, included three categories: (i) Laws, Regulations, and Orders; (ii) Governing Law; and (iii) Regulatory Agencies. [8]

AAPL’s Article XIV: Compliance with Laws and Regulations The AAPL’s Article XIV: Compliance with Laws and Regulations clause and the AIPN’s respective clause relating to this topic are the backdrop of the JOA, as all clauses will be governed by laws and regulations in a country.

Analysts and negotiators “have termed choice of law with respect to contracts… one of the most confusing fields in the fields of conflicts of laws.”

[6] Generally, a contractor will prioritize, in order, the country’s constitution, hydrocarbon laws, related regulations, and provisions of the contract when determining how to draft a JOA. [7] The AAPL is the oldest Model JOA in history and is still so widely used in the industry because it is the historical foundation on which JOA contract development rests. To get down to the

Through the life of the 1982, 1989, and 2015 Model Forms, the first two clauses have stayed the same.[9] The Regulatory Agencies clause has changed with the times and expanded to include “any governmental agencies having jurisdiction” over the Contract Area and to include protections for the Operator from “liability above and beyond its proportionate share,” which reflects the movement towards more protection of the Operator in the contract.[10] Historically this was 6

a challenge in the contract, as the Operator was often on the hook for everything related to operating the oil field, thereby not finding the other parties to the JOA were responsible because they were not the actors who acted improperly.

However, this has since changed to reflect the challenges between the Operator-friendly 1982 Model Form and the Non-Operator-friendly 1989 Model Form. The 1982 model form’s problem was that it “appeared the Operator would share in none of the loss occasioned by such a misinterpretation [of the contract].” [11] Operators’ consistent use of the 1982 clause, even after the 1989 form was released, led to a need to clarify the scope of the Operator’s related duties and obligations. [12] The task force put together to create the 2015 AAPL Model Form wanted to clarify that the Operator was not excused from willful misconduct or gross negligence simply because it was not expressly stated within this clause. [13] Ambiguity on these points led to varied case law and the desire to more specifically outline the Operator’s duties.

[14] The trend for the AAPL’s Laws and Regulations Clause is to a broader, more inclusive, and more exact Article XIV that allows for Operators and Non-Operators to be responsible to each other while limiting each other’s liability and giving general jurisdictional governance to any relevant agency.

the governing law be that of a country with a well-developed petroleum regime. [16] The Applicable Law Clause of the AIPN JOA is intimately connected to how companies manage other clauses in the contract, like their arbitration and dispute resolution clauses. Another example of this issue is when using English Law to govern a JOA, UK bribery law will also be applicable.

[17] The Article 18.1, Applicable Law Clause of the 1990 AIPN JOA, states that the agreement will be in accordance with the law of the country to which it applies, but “excluding any choice of law rules which would refer the matter to the laws of another jurisdiction.” [18] However, every AIPN JOA form issued since 1990 has allowed for two alternatives: the first allowing for the 1990 Applicable Law Clause, and an alternative that the laws of a country will govern “to the extent consistent with international law… [but if] not consistent with international law, then international law shall prevail.” [19] The 2002 and 2012 Article 18.1 Applicable Law Clauses are almost identical to that of 1990, which reflects the need for globally integrated oil companies to protect themselves from an operations conflict between the host government law under which they operate and governing law over the company from the United Nations, the Foreign Corrupt Practices Act, bi-lateral treaties, or other forms of international law. This is a challenge not reflected in the AAPL Model Form because the underlying assumption of the American contract is that American companies are the ones producing oil in the United States.

However, with the constant increase in reserves finding and the continuing changes at the regulatory level, many countries' NOCs are looking to enter the United States market to increase revenue, diversify risk, and learn from the practices of American experts in order to bring that knowledge back to their countries and expand production. These NOCs might also have their own version of the Foreign Corrupt Practices Act that they must abide by, requiring them to have a similar provision in the JOA to operate in the United States. The AIPN’s Laws and Regulations Clause gives the parties to the JOA flexibility governed by a respect for the

AIPN’s Laws and Regulations Clause in Contrast The AIPN’s comparative clauses to the AAPL’s Laws and Regulations Clause are similar in substance. The main difference between the two model contracts is the AIPN is a more flexible document, giving the user alternatives in the Laws and Regulations Clause. The AIPN JOA is “the only model form that allows the parties to negotiate governing law…” which can give an international energy company some room to breathe in the negotiation. [15] International energy companies desire to use sophisticated petroleum jurisdictions, like New York or English Law, to govern. The tug-of-war between international companies and host governments’ desire to have their law govern is often a sticking point in negotiations. It is recommended to have 7

challenges of NOCs while still allow the international energy companies to mitigate risks.

Expectations of National Coming to the United States

Oil

the nation to change and be enforced on the project. For large projects that are highly technical and complicated, a change in the law can be catastrophic and make a project financially infeasible.

The United States contracting risk is similar to Cyprus because regulatory bodies are able to amend rules oil companies must abide by them to continue operations. However, the difference lies in the fact that NOCs are often the most significant voice in their governments or regulatory bodies. In the United States, those NOCs have little say in changes in the regulatory process. NOCs see the inability to direct regulatory changes as a risk of doing business in the United States but accept it because of the prospects of lucrative hydrocarbon projects. It is possible this kind of issue may never arise in a negotiation with a NOC trying to do business in the US, but this overarching concern constantly lurks in the background.

Companies

The main challenge for many NOCs trying to engage the US upstream market is being comfortable playing a role in their own country, which is completely independent of regulators.

NOCs are often heavily integrated into the creation of hydrocarbon law in their respective countries. As part of the government, their experts consult in developing hydrocarbon laws and regulations. Coming into a country like the United States, where that sort of process is very different because the companies have no real control, can be challenging for non-US based companies.

The risks associated with NOCs investing in the US differ between Operator or Non-Operator.

Companies looking to become Operators often buyout experienced domestic companies to have a team in the country that knows the industry and the style of negotiation of that country, who understands the risks more easily than an international company that tries to do that process from scratch. Future Operators in similar contract structures have limited risk relating to this governing law clause because their experts effectively manage the issues and are almost all US native English speakers. The real challenge comes when a Non-Operator, looking to purchase oil and gas assets as an investment for a government portfolio abroad, tries to take part in the US upstream process and does not have an experienced team to assess the JOA. The mindset of a NOC engaging with the AAPL Model Form is based on its own Governing Law provision in the Production Sharing Agreement in their own country. For instance, the Cyprus Model Exploration and Production Sharing Contract states in its governing law clause that “This Contract and all Hydrocarbons Operations carried out under this Contract shall be governed by the legislation in force at any time in the Republic.” [20] This type of statement creates risk for a company because it does not specify a time frame of law associated with the contract, allowing for the regulations of

AAPL and AIPN JOAs Looking Forward American companies operating abroad continually apply risk assessments to project host countries. A top priority is understanding the Governing Law of the contract in either the AAPL or AIPN JOAs. The clause itself needs only be one or two sentences, but there is a host of challenges that can result in the Governing Law’s application. Just as American companies assess the risk of applying a Governing Law Clause in their global projects, a NOC will do a similar assessment in the United States.

The contract itself takes precedence in nearly every scenario, but the governing law in a jurisdiction will be the final word on how the contract is implemented. A JOA with a NOC will likely be longer than the standard AAPL Model Form because stipulating aspects of the contract in detail is preferred over exposing oneself to the common law legal system the United States.

However, a NOC that has operated globally for years may be familiar with English or New York law, given their basis is the English language.

This is “[b]ecause outcomes can be predicted with greater certainty due to the guidance that the substantial bodies of case law and statute law… provide…” [21] This can provide comfort to a 8

company operating in the United States and is one of the reasons New York law is often the first choice of law for sophisticated energy companies, despite Texas law being more favorable to petroleum companies in the United States. The US system recognizes a variety of relevant doctrines to the JOA process, “such as separate legal personality, sophisticated security interest, trust and fiduciary duties.” [22] Assessing the risks and challenges of JOAs is increasingly challenging as the complexity of projects, laws, and parties continue to make the perfect model contract elusive. The AAPL and AIPN are by far the best model contracts available, despite their differences, and present sophisticated approaches to the challenges faced by the petroleum industry. Despite the recommendation for companies to draft their own contract by many academics, this industry is too complex to start from scratch each time a new project emerges. Creating a governing law provision will be the least challenging clause to create because of the clause’s textual simplicity.

However, a governing law provision is essential due to its integration within the contract.

This instrumental Governing Law Clause will continue to direct the framework of the JOA. It is essential to start at the most common denominator clause when preparing a document that governs hundreds of millions of dollars.

Finding common ground and comparing cultural understandings to gauge the background of your partners could be the difference between a successful venture and a calamity. The AAPL and AIPN provide excellent frameworks for developing a JOA that fits each company's needs.

The AIPN focuses more on flexibility of options while giving the parties to the contract a thorough assessment of the voluminous issues that come up in other clauses in the JOA, which will be discussed in future articles. The AAPL 610 Model Form operates from a domestic perspective, allowing the contract to operate within a host of case law and not requiring many of the clauses of the AIPN to be explicit in the

contract. The difference in the two forms is reflected in the complexity of US petroleum law and the possible lack of petroleum law in another country where the AIPN contract will operate. In the future, common ground in contracting will become more essential as the world develops sophisticated global hydrocarbon law and highly integrated NOCs continue to expand their own horizons into the US market.

[1] Unless otherwise specified, the AIPN 2012 JOA Model Form and the AAPL 2015 JOA Model Form are the edition of discussion.

[2] Peter Roberts, Joint Operating Agreements: A Practical Guide, 3rd Edition, pg. 20-22.

[3] Id. at 21.

[4] Id. at 20.

[5] Macdonald, Frederick, Roach, Dorsey, “The A.A.P.L. Form 610-2015 Joint Operating Agreement-Commentary of the Form 610 Revision Task Force, Joint Operations and the New AAPL Form 610-2015 Model Form Operating Agreement, Paper 1, Page No. 1 (Rocky Mt. Min. L. Fdn./AIPN/COPAS 2016. (Herein noted as “Macdonald Commentary”).

[6] Detlev Vagts, Transitional Business Problems, 466.

[7] Tim Brown and Ken Rice, International Petroleum Transactions: Multidisciplinary Fundamentals, Module II, Slide 11.

[8] AAPL Model Form 610 610, Art XIV.C. 1956-1982.

[9] AAPL Model Form 610 Art. XIV. 1989, Redline Comparison to the 610-2015 Model Form.

[10] AAPL Model Form 610 Art. XIV.C. 2015.

[11] Macdonald Commentary, Page No. 17.

[12] Id. [13] Id. at 16–17.

[14] Stine v. Marathon Oil Co., 976 F.2d 254 (5th Cir. 1992).

[15] Dr. Anna Ovcharova and Eduardo G Pereira, Joint Operating Agreements: A Comparison Between the IOC and NOC Perspectives, 279.

[16] Andrew B. Derman, Model Form International Operating Agreement: An Analysis and Interpretation of the 1995 Form, 131.

[17] Ovcharova and Pereira, 280.

[18] AIPN, Model Form International Operating Agreement, Barrows Company Inc., 1990, Art XVIII.1.

[19] AIPN, MFIOA, 1995, Art XVII.1.Alt.2.

[20] Cyprus, Model Exploration and Production Sharing Contract, 35.1, Nicosia, 2012.

[21] Roberts, at 268.

[22] Id.

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2007, one property owner, Texas Rice, refused to allow the survey of two tracts in Jefferson County, Texas. [8]

Denbury Green II: No Naked Assertions Enable Eminent Domain By: Christopher Robertson and Michael Vargo, J.D.

“When compared to the requirements that

Jeffus Law Office, Of Counsel & Independent Practice

existed before Denbury Green I… the more

Introduction

recent opinion benefits Texas landowners by forcing pipeline companies to substantiate their

On January 6, 2017, the Supreme Court of Texas issued its much-anticipated Denbury Green Pipeline-Texas L.L.C. v. Texas Rice Land Partners Ltd., et al. opinion (“Denbury Green II”).

[1] The case clarified issues regarding condemnation powers of pipeline builders and built upon the Court’s 2012 decision involving the same parties (“Denbury Green I”). [2] Perhaps to the disappointment of private property advocates, the court’s threshold for common carrier status and eminent domain authority does not impose a considerable burden on entities that wish to condemn land for pipeline projects.[3] However, both opinions provide protections for landowners by requiring companies such as Denbury Green to support the assertion that their pipelines will be used for the public’s benefit.[4] When compared to the requirements that existed before Denbury Green I, which allowed companies nearly unfettered authority to assert common carrier status, the more recent opinion benefits Texas landowners by forcing pipeline companies to substantiate their claims.

This Article will analyze the Denbury Green II decision in the context of Denbury Green I. It will also detail industry reactions to the opinions, as well as the rulings’ effects on CO2 pipeline companies. Further, this Article will briefly discuss possible action the Texas Legislature may take regarding eminent domain authority.

Background Denbury Green was formed to construct and operate the “Green Line” pipeline across parts of Texas and other states. [5] The Green Line was intended to transport carbon dioxide to nearby refineries, plants, and other facilities. [6] Before beginning construction, Denbury Green sought permission from landowners to survey property the company could utilize for this project. [7] In

claims.”

In early 2008, Denbury Green filed a T-4 Permit application with the Texas Railroad Commission.[9] This permit allows “common carriers” (companies who act for the public benefit) to condemn private property via eminent domain.[10] Among other things, T-4 Permit applicants were required to claim that they were a common carrier, which was a simple process akin to checking a box on the application form.[11] Around the same time, Denbury Green filed a lawsuit against Texas Rice seeking an injunction to allow access to its property.[12] While the suit was still pending, the Railroad Commission approved Denbury Green’s T-4 Permit, allowing the company to take possession of Texas Rice’s property, pending the result of the lawsuit.[13] Thereafter, the Green Line was constructed.[14] Denbury Green I In response to a motion for summary judgment, the trial court found that Denbury Green was a common carrier, which vested the company with private condemnation authority.

[15] On appeal, the Ninth Court of Appeals in Beaumont affirmed the decision. [16] However, the Supreme Court of Texas reversed the appellate court, finding that the method for gaining common carrier status, as set forth in the T-4 Permit application, insufficiently protected Texas landowners’ rights. [17] Eminent domain requires proof of public benefit from the condemnation. [18] The Denbury Green I Court reasoned that aside from the T-4’s assertion that Denbury Green was a common carrier, there was a lack of substantial evidence showing public benefit. [19] Denbury Green had 10

not contracted with the other company to transport carbon dioxide over the line. [20] Instead, the project’s website suggested Denbury Green would be the sole user of the line. [21] To limit future occurrences of this issue, the Texas Supreme Court established jurisprudence which required T-4 Permit applicants such as Denbury Green to show a “reasonable probability” that at some point after construction, another entity would use the proposed pipeline. [22] The court remanded the case to the trial court to evaluate Denbury Green’s status, using the new test. [23]

“for a person intending to build a CO2 pipeline to qualify as a common carrier under Section 111.002(6) [of the Natural Resources Code], a reasonable probability must exist that the pipeline will at some point after construction serve the public by transporting gas for one or more customers who will either retain ownership of their gas or sell it to parties other than the carrier.” [35]

Denbury Green II It also noted that a “reasonable probability is one that is more likely than not.” [36] To satisfy this requirement, Denbury Green provided proof of contracts with other firms (entered into post-construction), as well as the Green Line’s proximity to other businesses, to support the reasonable probability that the pipeline would serve the public. [37] The Supreme Court of Texas Court identified that the court of appeals incorrectly interpreted the Denbury Green I test by discounting such evidence. [38] The Denbury Green II Court first rejected the lower court’s application of the prefatory phrase “for a person intending to build,” in order to establish common carrier status as a matter of law.[39] The court of appeals heavily emphasized Denbury Green’s intent to exclusively use the pipeline, at the time the Green Line was constructed .[40] However, the Texas Supreme Court explained that the phrase was not meant to describe the intent of a pipeline company at the time a pipeline is contemplated.[41] Rather, the phrase merely identified the party that must prove common carrier status.[42] By shifting analysis focus to intent, the lower court ignored pertinent information supporting Denbury Green’s claim of common carrier status.[43] The court clarified that evidence of postconstruction contracts and use is relevant to common carrier analysis. [44] For instance, Denbury Green’s agreement with Airgas Carbonic, as well as the fact that the Green Line’s proximity to other carbon dioxide shippers could support future public use, established a reasonable probability that at some point after

On remand, Denbury Green produced evidence of various transportation agreements that demonstrated that other entities were currently using, and intended to later use, the Green Line.[24] One company, Airgas Carbonic, began receiving carbon dioxide from the Green Line in 2013.[25] Another entity, Air Products, demonstrated an intent to ship about 51.5 million cubic feet of carbon dioxide per day over the Green Line.[26] Though the agreements were executed after the pipeline was constructed, the trial court still found that Denbury Green established itself as a common carrier and granted its motion for summary judgment.[27] Conversely, the Ninth Court of Appeals reversed the trial court’s decision. [28] It noted that “reasonable minds could differ regarding whether, at the time Denbury Green intended to build the Green Line, a reasonable probability existed that the Green Line would serve the public.” [29] The court also held that the Green Line did not serve a “substantial public interest.”

[30] The Supreme Court of Texas subsequently granted review of the case and reversed the appellate court’s decision. In doing so, the court clarified the proper application of the rule passed down in Denbury Green I. [31] The Denbury Green II Court explained its prior ruling within the context of eminent domain. [32] For a company to seize private property, the appropriate project must 1) serve the public and 2) not exclusively benefit the applicant. [33] Thus, Denbury Green had to qualify as a common carrier which acts “for the public for hire.” [34] The court explained that: 11

construction the Green Line would be used by other entities. [45] Moreover, the appellate court incorrectly required that the Green Line serve a “substantial public interest.” [46] In this regard, Denbury Green produced evidence that the Green Line would benefit small interest owners in nearby gas fields. [47] The Ninth Court of Appeals held that because Denbury Onshore owned controlling interests in such fields, a fact issue was raised as to whether this use was substantial. On similar grounds, it also dismissed evidence such as the Air Products contract, whereby Denbury Green would receive ownership of gas to sequester it according to an agreement with the federal government. [48] However, the Texas Supreme Court declared the application of this standard erroneous under Denbury Green I.[49] Citing Coastal States Gas Producing Co. v. Pate, the Court clarified that in connection with eminent domain, a public benefit must not necessarily be “direct, tangible, or substantial.”[50] Rather, to serve a public interest, the Green Line need only transport gas for one or more customers.[51] Therefore, because Denbury Green’s evidence showed a reasonable probability that the pipeline will, at some point after construction, serve even just one customer unaffiliated with the company, the Green Line’s public use was substantially proved.[52]

McFarland claimed it was “difficult … to understand how this additional summary judgment evidence establishes as a matter of law that Denbury was a common carrier.”[57] He further noted that the decision “significantly erodes the precedential value of [Denbury Green I] and the ability of landowners to challenge the common-carrier status of companies asserting the right to condemn easements across their land.”[58]

Reaction to Denbury Green II

Effects of Denbury Green II

After the decision was issued, the energy and legal communities expressed mixed reactions. As expected, oil and gas proponents supported the ruling. James Mann, an attorney for the Texas Pipeline Association, claimed the decision “clears up a great deal of confusion.” [53] He felt the opinion gave “a fairly clear requirement” for energy companies seeking to condemn land for certain operations. [54] Conversely, property rights advocates denounced Denbury Green II. Austin attorney John McFarland of Graves, Dougherty, Hearon & Moody, the firm that represented Texas Rice Partners, discussed the opinion in his blog.[55] He criticized that Texas Rice Partners was denied a jury trial based on Denbury Green’s limited new evidence of common-carrier intent.[56]

By requiring applicants to produce objective proof of public benefit, the Supreme Court of Texas struck a balance between private property rights and eminent domain, providing clearer guidance for Texas pipeline operators. With this objective requirement, pipeline companies should perform certain actions before applying for a T-4 Permit. A pipeline company cannot make a “naked assertion” that it will someday sell to an unaffiliated customer. [61] Rather, it must provide some evidence, such as a contract with a carbon monoxide carrier that would transport purchased carbon monoxide to a party other than the common carrier, to establish common carrier status. Marie Yeates, a partner at Vinson & Elkins in Houston who aided in the representation of Denbury Green, noted that pipeline companies

“Denbury Green’s evidence showed a reasonable probability that the pipeline will, at some point after construction, serve even just one customer unaffiliated with the company, the Green Line’s public use was substantially proved.”

Other criticisms of Denbury Green II revolve around unanswered questions. Tiffany Dowell of the Texas Agriculture Law Blog claimed the opinion was unclear as to whether the common carrier analytical framework will apply beyond CO2 pipelines, to matters involving natural gas or crude oil pipelines. [59] She noted that these issues could soon be resolved in the Texas Legislature’s current session. [60]

12

could enter into shipping agreements or other third-party contracts to be labeled a common carrier under the recent decision. [62] Similarly, attorneys from Thompson & Knight agreed that the “threshold is not high” for companies to receive a T-4 Permit.[63] They explained that “minimal contracts with unrelated entities for future transport and lists of potential nearby customers” will likely establish common carrier status, and allow eminent domain going forward.[64] However, the attorneys recognized that the Supreme Court of Texas has not specified whether a contract between an alleged common carrier and an affiliated entity to transport gas owned by the affiliated entity would be sufficient to demonstrate common carrier activity.[65] The application of Denbury Green II’s common carrier test may also apply to other energy operations under the Texas Natural Resources Code. If so, the Texas Supreme Court’s clarification of the law will likely benefit Texas energy production by allowing future construction to occur largely undisturbed by judicial intervention.

It is important to note that the Texas Legislature, which is currently in its 2017 session, could alter eminent domain by statute. For instance, Senator Lois W. Kolkhorst introduced a measure to add safeguards for landowners subject to public takings.[66] Further, state lawmakers have been working with the Texans for Property Rights coalition, which shares members with groups such as the Texas Wildlife Association, Texas Forestry Association, Texas Poultry Association, Independent Cattlemen’s Association, and Texas Land & Mineral Owners Association.[67] Together, the parties hope to provide more power to landowners in eminent domain purchase offers and seek to increase the transparency of the condemnation process. [68] [69] Although pending legislation has yet to disrupt the Denbury Green II holding, new laws may significantly impact how energy companies condemn private land for public use.

eminent domain must establish a reasonable probability that, at some point after construction, their line will serve the public by transporting production for one or more customers, who will either retain ownership of their product or sell it to parties other than the carrier. If a company fails to produce reasonable evidence to meet this relatively low burden, it will likely fail to secure a T-4 Permit.

Texas landowners understandably seek robust protection from property takings. However, in its balancing of private and public rights, the Supreme Court of Texas rejected the notion that condemnation can be based upon a company’s naked assertion that it will serve the public.

Although legislative action may result, for now Denbury Green II appears to provide a workable standard for common carriers in the Texas oil and gas industry. ________________________________________ [1] Denbury Green Pipeline-Texas, LLC v. Texas Rice Land Partners, Ltd., No. 15-0225, 2017 WL 65470, at *1 (Tex. Jan. 6, 2017) (Petition for Rehearing Filed Feb. 6, 2017) [hereinafter, Denbury Green II].

[2] See Tex. Rice Land Partners, Ltd. v. Denbury Green Pipeline-Tex., LLC, 363 S.W.3d 192 (Tex. 2012) [hereinafter, Denbury Green I].

[3] Denbury Green II, 2017 WL 65470, at *1.

[4] Id. [5] Id. at *2.

[6] Id. [7] Id. at *3.

[8] Id. [9] Id. [10] Tex. Nat. Res. Code § 111.019(a).

[11] Denbury Green I, 363 S.W.3d at 195.

[12] Denbury Green II, 2017 WL 65470, at *3.

[13] Tex. Prop. Code § 21.021(a).

[14] Denbury Green II, 2017 WL 65470, at *3.

[15] Denbury Green I, 363 S.W.3d at 196.

[16] Id. [17] Id. at 195.

[18] Id. [19] Id. at 203.

[20] Id. [21] Id. [22] Id. at 202.

[23] Id. at 204.

[24] Denbury Green II, 2017 WL 65470, at *4.

[25] Id. at *5.

[26] Id. at *6.

[27] Id. at *3.

[28] Id. at *6.

[29] Id (emphasis added).

[30] Id, at *13.

[31] Id. at *6–9.

Conclusion Denbury Green II established a ruling with an objective standard for establishing common carrier status. Pipeline companies seeking 13

[32] Id. at 5.

[33] Id. [34] See id; Tex. Nat. Res. Code ยง 111.002(6).

[35] Id. at *5 (citing Denbury Green I, 363 S.W.2d at 202).

[36] Id. [37] Denbury Green II, 2017 WL 65470, at *1.

[38] Id. at *9.

[39] Id. [40] Id. [41] Id. [42] Id. [43] Id. [44] Id. at *11.

[45] Id. [46] Id. at *13.

[47] Id. [48] Id. [49] Id. at *13.

[50] Id. (citing Coastal States Gas Producing Co. v. Pate, 309 S.W.2d 828 (Tex. 1958)).

[51] Id. [52] Id. at *14.

[53] Jeff Mosier, Latest Ruling on Eminent Domain Eases Fears of Texas Pipeline Builders, Dallas Morning News (January 11, 2017), http://www.dallasnews.com/business/energy/2017/01/11/lat est-ruling-eminent-domain-eases-fears-texas-pipelinebuilders.

[54] Id. [55] John McFarland, Landowners Lose in Denbury v.

Texas Rice Land Partners, Oil and Gas Lawyer Blog (January 9, 2017), http://www.oilandgaslawyerblog.com/2017/01/landownerslose-denbury-v-texas-rice-land-partners.html.

[56] Id. [57] Id. [58] Id. [59] Tiffany Dowell, Texas Supreme Court Issues Ruling in Denbury Green, Texas Agriculture Law Blog (January 10, 2017), http://agrilife.org/texasaglaw/2017/01/10/texassupreme-court-issues-ruling-denbury-green.

[60] Id. [61] Id. [62] Id. [63] Michael E. Schonberg, et al., Texas Rice Land Partners Revisited: Texas Supreme Court Sets Bar Low for Pipeline Common Carriers, Thompson & Knight Impact (January 17, 2017), http://www.tklaw.com/files/Publication/25163059-67e7478e-b804ac28ab73226e/Presentation/PublicationAttachment/d66064f 4-f6d4-48f2-b207-293657ea2da8/Client%20Alert%20%20Texas%20Rice%20Land%20Partners%20Revisited.pdf [64] Id. [65] Id. [66] Senator Kolkhorst Introduces Legislative Package to Protect Private Property Rights, The Sealy News (February 16, 2017), http://www.sealynews.com/features/article_a5a6d122-f3c011e6-9d5f-b32671b62d7c.html.

[67] S. Laney Griffo, Texas Landowners Work with Legislators to Create Eminent Domain Laws, SE Texas Record (February 1, 2017), http://setexasrecord.com/stories/511077977-texaslandowners-work-with-legislators-to-create-eminentdomain-laws.

[68] Id. [69] Id.

14

with miles of risers tied back to a mega-platform.

[6] In addition, distant sites mean higher exposure to erratic weather, making an already-short dismantling season more challenging. [7] This creates unanticipated and complex financial, legal, and environmental removal challenges. The dismantlement of larger, distant, and more complex sites all led to increasing anticipated costs from their original budgets. Additionally, difficulty estimating returns from reserves, exploration costs, market sales, and improved techniques for recovery from mature fields contributed to putting decommissioning on the backburner. [8] Although decommissioning cost varies by size and location, operators and governments around the world are uniformly concerned with the increasing risks.

An Introduction to Decommissioning Risks and Challenges By: Nadine Sheta Introduction This article addresses the emerging challenges facing host governments and operators decommissioning off-shore sites and how different regulatory regimes address the new challenges.

The decommissioning (or abandonment) stage in an oil and gas project is the industry’s “clean up after the party is over.” It is a distinct operational phase after the exploration and production period. It references all work done with respect to abandonment of a site, including but not limited to plugging wells, disposal, demolition, removal, and clean-up of facilities necessary to remediate and restore a site to a pre-leased state. [1]

Decommissioning Liabilities An examination of liability apportionment based on applicable law is required to determine who ends up with the high costs.

Decommissioning liabilities differ based on jurisdictional constraints. [9] Factors for each company’s cost analysis include governing laws, ownership of infrastructure, and insolvency. [10] International host country and operator obligations are subject to several international, regional, and local laws in conjunction with the agreement itself. [11] The host government may also be subject to certain regional, bilateral, and international treaties and conventions delignating obligations and standards. [12] For example, the Convention for the Protection of Marine Environment of the NorthEast Atlantic Decision 98/3 provides a framework for sixteen European governments’ cooperation on dumping, a process of leaving waste or machinery in the location of the drill site without monitoring the waste after leaving. [13] The International Maritime Organization 1989 guidelines give host governments discretion to decide whether entire or partial removal is necessary by factoring into the assessment the enormous costs and unacceptable risks to personnel, marine environment, or lack of technological feasibility. [14] In the United States, the Bureau of Ocean and Energy Management (BOEM) issued new

“An increase in abandonment project spending is expected to rise from $2.4 billion in 2015 to $13 billion-per-year by 2040.”

Although abandonment terms are a fixed component of any project, the extent and scope of obligations related to abandoning offshore sites are only now coming to view. In the North Sea and the Gulf of Mexico (GoM), older facilities are nearing the end of their economic production life. [2] An increase in abandonment project spending is expected to rise from $2.4 billion to $13 billion-per-year between 2015 and 2040. [3] With two thousand global offshore projects entering their decommissioning phase between 2021 and 2040, anticipated removal expenditures from 2010 through 2040 will total $210 billion.

[4] This has the industry perking its ears looking to mitigate risk and capitalize on this development.

These high numbers can be attributed to a few factors. Technological advances led to a growth in deep-water offshore drilling, increasing both facility size and distance from the shore. [5] Some sites now comprise of hundreds of wells 15

financing guidelines to assist preventing clean-up cost falling on the taxpayer. [15] Therefore, host governments and operators likely are subject to the requirements of multiple international agreements in each aspect of the abandonment phase.

These overlapping requirements can make it increasingly difficult for a company to operate within the law of a host government.

with a specific project. [21] However, the host country may not elect to keep the assets, in which case the facility operator will be obligated to perform the decommissioning. [22] In making that decision, host countries will calculate the benefit of keeping the infrastructure based on its age and value versus potential taxpayer liability for future removal.

“Even if liability is portioned pursuant to

Applicable Law Challenges

jurisdictional requirements or infrastructure

Navigating the host of applicable laws and guidelines can be challenging, especially if laws conflict. For example, the 1958 United Nations Geneva Convention on the Continental Shelf Article 5(5) stated that offshore installations must be “entirely removed,” while the 1982 United Nations Convention on Law of the Sea (LOS Convention) Article 60(3) called for “removal” of offshore installations. [16] The exclusion of the term “entirely” changed the obligations of the removing parties.

[17] Project-influencing factors such as budgeting, environmental standards, and marine ecology are affected by whether a party partially or entirely removes their offshore installation.

These terminology shifts can be attributed to an increased understanding of how complete removal may lead to disrupting marine ecosystems that develop around the facilities. [18] This disruption could in turn economically impact fishermen benefitting from those ecosystems.

Therefore, the removal criteria for one region may not be ideal for another. Commonly, when ambiguity is present, the adoption of “best practices” prevails. [19] To streamline the parties’ understanding of their obligations, most host countries either incorporate treaty requirements in their concession agreements or reference “applicable law” in relevant clauses.

Obligations for decommissioning may also depend on infrastructure ownership, which depends on the utilized agreement type. [20] Under a production sharing or royalty tax regime, infrastructure typically reverts to the host government because costs attributed to infrastructure are likely deducted as cost recovery, which is the process by which an energy company recovers its costs associated

ownership, the buck stops with insolvency.”

Under a licensing regime, infrastructure likely belongs to the host country because it will bear the costs and risks associated with the infrastructure development. [23] A licensing regime gives a company the rights to produce oil and gas without giving them unending ownership of those minerals.

Economic benefit, environmental regulations, and regime all factor into whether infrastructure ownership is advantageous to the future owner.

The goal of a company is to make money on a project. If the regime and regulations are not able to adequately allow a return on investment for the company, the company will look elsewhere for other more favorable projects and opportunities.

Insolvency Even if liability is portioned pursuant to jurisdictional requirements or infrastructure ownership, the buck stops with insolvency. As infrastructure ages, a common trend is to transfer decommissioning assets from larger companies to smaller ones. [24] Because smaller companies are at a greater risk for insolvency, higher demand is placed on smaller companies to secure their assets. [25] The higher demand restricts the smaller companies’ asset flows and hinders their cash flow towards new investments. [26] This creates an environment where newer, smaller market entrants make marginal returns on their investment and lock them in a cycle where they are at risk of the insolvency sought to be prevented.

16

Critics of the increased criteria point to another potential side-effect: early abandonment.

Because a project terminates when production is no longer economically feasible, the combination of increased cost and liability may lead operators to terminate a project sooner than expected. The risk of insolvency often forces operators to commence decommissioning operations sooner in hopes of reducing costs. At the end of the day, insolvency is what drives the decommissioning phase from a well-managed, efficient, and safe process into a risky, financially strenuous mess.

This leads to a series of different disasters for the company but this also can have a grave impact on the host government.

operators was no longer adequate. This resulted in amending the Petroleum Act with the UK Energy Act of 2008. [33] The new law gave the state the option to require additional collateral support to the party’s prospective decommissioning liability costs with the country as the intended beneficiary.

This helped accomplish two objectives: the government was more capable of avoiding a Tuscan Energy scenario by ensuring defaults were covered through a collateral support cushion and the participating parties were assured that their liabilities were limited to their respective participating interests. [34]

“A host government’s worst-case scenario is

Host Government Risks

that taxpayers end up picking up the

A host government’s worst case scenario is that taxpayers end up picking up the decommissioning costs when an operator becomes insolvent. Governments have developed different methods to mitigate the risk of financial failure. Under a typical Joint Operating Agreement (JOA) license regime, federal regulations could require asset sellers to be jointly and severally liable in perpetuity. [27] Additional financial security methods include surety bonds, keeping a certain amount of proceeds in escrow, or acquiring insurance policies covering future exposure. [28] Under a Production Sharing Contract (PSC), host governments dictate their criteria based on their preferences. [29] A common method used is the establishment of a trust where different operators or licensees contribute to the abandonment cost throughout the project life. [30] Regardless of which riskmitigation technique is applied, host governments are increasingly guarded against potential insolvent asset holders in the face of rising decommissioning costs.

A recent example of this issue was when United Kingdom taxpayers footed the bill for decommissioning when Tuscan Energy, an operator in the UK Continental Shelf (UKCS), went insolvent in 2005. [31] Although the cost was relatively modest, the scenario illuminated a potentially large flaw in liability apportionment under the UK Petroleum Act of 1998. [32] Joint and several liability for all past and present

decommissioning costs when an operator becomes insolvent.”

Similarly, recent bankruptcy trends in the Gulf of Mexico led BOEM to issue new regulations with updated criteria for determining a lessee’s ability to self-insure. [35] This was done by forming a tailored plan for lessees to ensure they meet their decommissioning financial obligations. Each plan will include working on a solution to meet both the government’s and each company’s needs. [36] Higher flexibility is given to lessees by increasing the forms of financial assurance for consideration. [37] These and other new requirements all aim to decrease the risk of insolvency and offer the lessees more financial security and flexibility to meet their decommissioning obligations.

In important regions around the world many offshore facilities are approaching the end of their economic production. Although governments and operators in the UKCS and Gulf of Mexico are the current focal points of decommissioning activities. Global actors will be looking at past challenges and future risks in those lucrative regions for fashioning their decommissioning risk-mitigation strategies in upcoming years.

Decommissioning will continue to play a larger and more complex role in the development of the 17

[12] Roberts, at 195.

[13] Felipe Alice, Eduardo Pereira, Decommissioning Issues, AIPN Presentations: International Oil and Gas Law, Contracts and Negotiations (10/5/2016) [14] Id. [15] Nick Snow, BOEM Notifies Offshore Leaseholders of Decommissioning Rule Changes, Oil and Gas Journal (7/14/2016) [16] Alice at 14.

[17] Id. [18] Id. [19] King and Spalding Decommissioning Workshop, Energy law and Policy from a Global Perspective [20] Ovcharova, at 225.

[21] Id. [22] Id. [23] Id. [24] Mathonnier, at 5.

[25] Id. [26] Id. [27] Roberts, at 194, 195.

[28] King and Spalding Decommissioning Workshop [29] Id. [30] Id. [31] Roberts, at 198.

[32] Id. [33] Id. [34] Id. [35] Snow [36] Id. [37] Id.

industry.

Reputational, economic, fiscal, environmental, and regulatory risks all contribute to increasing decommissioning’s role in any project in the oil and gas industry. A keen eye to the developments of this issue can save a company billions over the lifetime of a project.

The significance of this industry topic cannot be understated, but is an excellent opportunity for companies to shine in expertise and foresight of future project concerns. The more a company can develop its decommissioning strategy, the safer all parties will be as this industry continues to expand into the 21st century. ________________________________________ [1] Peter Roberts, Joint Operating Agreements: A Practical Guide, 3 Edition, pg. 193-205.

[2] Melissa Manning, Decommissioning of Aging Offshore Oil and Gas Facilities Increasing Significantly, with Annual Spending Rising to $13 Billion by 2040, IHS Markit Says, IHS Markit (11/29/2016) [3] Id. [4] Id. [5] Julien Mathonnier, Decommissioning: Striking the Right Balance, Oilprice.com (6/24/2014).

[6] Id. [7] Manning, at 2.

[8] Roberts, at 194.

[9] Anna Ovcharova, Eduardo Pereira, Joint Operations Agreements: A Comparison Between the IOC and NOC perspectives, pg. 224.

[10] Id. [11] Id. rd

18

The latest EPA study of fracking stated the purpose of assessing the potential impact of fracking to water quality and water quantity in surrounding areas. In conducting the study, the EPA drew on various sources, but in great part relied upon self-reported data provided by E&P companies through the FracFocus 1.0 database.

The report focused on impacts to both water quality and water quantity at each of the five stages of the fracking process. The report set out the five stages as follows: water acquisition, chemical mixing, well injection, produced water handling, and wastewater disposal and reuse. I will give a short summary of the conclusions reached by the EPA about the potential impact to water resources at each of the aforementioned stages of the process, and then provide my insight as to the overall conclusion to be drawn from the report.

EPA Fracking Report: In So Many Words, No New Revelations!

By: Andrija “Andre” Stanojcic, J.D. Independent Consultant

Introduction The Environmental Protection Agency (“EPA”) is the Federal agency created in 1970 during the Nixon administration and tasked with enforcing Federal environmental laws generally pertaining to land, air, and water quality protections. [1] The agency has a wide latitude in drafting, promulgating, and enforcing regulatory rules to ensure compliance with Federal environmental laws, such as the Clean Air Act, Clean Water Act, Resource Conservation, and Recovery Act.

Water Acquisition

“The EPA report concluded that although fracking operations consume large amounts of

The EPA report concluded that although fracking operations consume large amounts of water, the impact of most completed operations on the quantity of total available water was negligible. [6] The report considered all kinds of water use categories, including those used for public supply, domestic, industrial, irrigation, and mining. [7] In comparing the amounts of water used in specific fracking jobs, as reported in FracFocus by operators, to the total annual water use amounts for the counties where those jobs were located, the report concluded that in most counties the fracking jobs completed represented less than 1% of total water use. [8] Stating the obvious, the report also found that in more remote, less populated, and more arid counties, the impact on water quantity by fracking operations was greater. [9] The report does not expand on what “greater” means in the present case but fracking generally does not use a large amount of water on relatively smaller operations.

However, the impact of water used has the potential to be magnified in areas with low water availability and high fracking water withdrawals.

In conclusion, the EPA highlights that water management strategies can reduce the severity of impacts on drinking water resources from hydraulic fracturing withdrawals. [10]

water, the impact of most completed operations on the quantity of total available water was negligible.”

The EPA, as part of its mandate to monitor and guard against threats to water, air, and soil quality, has an internal research office devoted to scientific study of such current and potential threats. [2] In 2012, the EPA signed a memorandum of understanding with the Department of Energy and the Department of Interior to undertake a joint effort in researching the best ways to move forward with securing the United States’ energy independence through fracking, while at the same time minimizing the impact on the environment. [3] Water and soil quality being the EPA’s prerogative, its research office was tasked with conducting a study of the potential impacts of hydraulic fracturing (Fracking) operations to aboveground and underground water sources. [4] EPA released a progress report in December 2012, a final draft assessment report for peer review and comment in June 2015, and the final report in December 2016. [5] 19

Chemical Mixing

fracturing fluids through the well and into the targeted rock formation. [19] The report focuses on the potential for fracking fluids to migrate into a nearby underground drinking water source, either from a lack of mechanical integrity in a well or from the fractures created in the targeted rock formation.

First, the report outlines several ways in which fracking fluids can migrate from a well with poor mechanical integrity into surrounding formations, and potentially into underground drinking water sources. It notes that poor mechanical integrity can arise from a variety of issues, from poor well design to degradation of well integrity over time. Several individual cases are noted, but no empirical study or data is provided to testify that such wells are the rule and not the exception. [20] Second, the report finds that based on previous computer modeling studies, the farther the vertical separation between the targeted rock formation and underground drinking water resource, the less frequency and severity of impacts there will be on such water resources. [21] In conclusion, the report finds that—somewhat anticlimactically—the presence of multiple layers of cement casing in the well, and thousands of feet of rock between a targeted rock formation and water sources, reduces the frequency and impact of migrating fracking fluid affecting drinking water. [22]

The report looks at some of the various chemicals and additives used to assist in the fracking process. Using the FracFocus reports, the study lays out what were the most frequently used chemicals and additives by the percentage of reported fracking jobs they were encountered in.

[11] The report then describes the incidents of actual spills of hydraulic fracturing fluids or additives. [12] Most of the data garnered in the report comes from several prior studies of statemanaged spill databases. [13] This data leads to the conclusion that the main culprits in chemicals and additives spills are overwhelmingly equipment failures and human error. [14] Additionally, almost a third of the recorded spills were from fluid storage units. [15] “Although most in the industry certainly expect a generally less hostile approach to the industry from the new Administration, it is not exactly clear to what extent this relationship will change.”

The report goes on to concede that although impacts on water surface resources have been documented, there are no site-specific studies that EPA could call upon to determine the overall impact and severity of spills. In the absence of such data, the report relies on “fundamental scientific principles” to reach the conclusion that the impact of a spill on groundwater quality depends on an array of factors. [16] These factors include but are not limited to the distance between spill and water sources, the volume of fluids spilled, the concentration of chemicals in spilled fluids, and permeability of the subsurface soil and rock. [17] Finally, the report highlights the importance of spill prevention practices and spill response activities, to reduce the impact of any potential spills. [18]

Produced Water Handling The produced water handling stage of the fracking process concerns the on-site collection and handling of water returned to the surface after use in the fracking job, and the subsequent handling and transportation of such water for disposal or reuse. [23] The report first outlines the process and mentions the various chemicals and naturally occurring compounds that have often been found in produced water. [24] Some of these chemicals and naturally occurring compounds are harmful to humans, while others are much more benign. [25] The report finds that based on previous EPA and state studies, about 13-18% of all reported spills reach water sources. [26] In most cases, the most serious aspect of such a spill entailed the increase in salinity of groundwater/surface water resources. [27] The

Well Injection

the

The well injection stage of the process covers injection and movement of hydraulic 20

report concludes that spill prevention and response activities can prevent spilled fluids from reaching both groundwater and surface water resources, and help minimize impacts from spilled fluids. [28]

regulated by states and such regulations have limited the impact on water resources. [36] A Prospective Outlook What the EPA did not do was clarify its position on fracking or how it views fracking’s alleged impacts. With the inauguration of a new presidential administration and forthcoming appointment of seemingly pro-energy individuals, such as Ryan Zinke and Scott Pruitt to Secretary of Interior and Administrator of the EPA, respectively, the EPA’s future approach to fracking is uncertain. Both nominees have somewhat distanced themselves from President Trump’s less nuanced repudiation of the global warming question. Although most in the industry certainly expect a generally less hostile approach to the industry from the new Administration, it is not exactly clear to what extent the relationship will change. Between the new President and his appointees will reflect on the opening of unconventional domestic plays, and specifically, on the need to harness the industry's fracking technology to develop those resources. If the President and his appointees work closely on following through with the President’s “one-in, two-out” executive order on regulations and his overarching promise of securing America’s energy independence, then we can certainly expect the industry’s entrepreneurial spirit to be fully revived and continue working toward providing America with efficient, clean and affordable domestic energy. Whether this will be the case remains to be seen. As of this writing, President Trump’s anti-regulatory scheme was challenged in court by the Natural Resources Defense Council, and Scott Pruitt is still awaiting confirmation as the Administrator of the EPA.

Wastewater Disposal and Reuse The wastewater disposal and reuse stage of the process concerns the practices related to disposal and reuse of hydraulic fracturing wastewater. [29] The report highlights the concern that inadequate disposal and reuse of produced wastewater can result in the release of potentially hazardous fracking fluids into surface water and groundwater resources. [30] It goes on to outline that the vast majority of produced wastewater is managed through injection into Class II wells. The report claims this was indicative of nationwide management practices for hydraulic fracturing wastewater. [31] This kind of disposal practice, the report goes on to note, is regulated under the Safe Drinking Water Act and has been shown to be cost-effective. [32] “The report showed that through self-imposed industry standards and existing federal and state law regulations, incidences affecting water resources occur in a minority of fracking operations.”

On the other hand, the aboveground storage and reuse of wastewater is practiced to a much lesser extent. [33] It is above ground disposal of wastewater treatment that is one of the highest concerns to the EPA, as it has the greatest potential for migration or release to drinking water sources. [34] Nevertheless, the report concedes that in many areas (e.g. Marcellus Shale) reuse of produced wastewater in other fracking operations is very common—up to 90%.

[35] Federal and state regulations control above ground disposal options, and reuse is often allowed only where produced wastewater meets minimum quality standards for various specific uses. The use of percolating water pits and unlined above ground disposal pits has been

Conclusion The EPA concedes that because of “significant data gaps and uncertainties in available data,” it was not possible, in this report, to fully characterize the severity of impacts, nor was it possible to calculate or estimate the national frequency of impacts on drinking water resources from activities in the hydraulic fracturing water cycle.” [37] In other words, the 21

[5] Natural Gas Extraction - Hydraulic Fracturing, supra note 1.

[6] Environmental Protection Agency, EPA-600-R-16236ES, Hydraulic Fracturing for Oil and Gas: Impacts from The Hydraulic Fracturing Water Cycle on Drinking Water Resources in The United States, Executive Summary 14 (2016).

[7] Id. [8] Id. [9] Id. at 15.

[10] Id. [11] Id. at 18.

[12] Id. at 20.

[13] Id. [14] Id. [15] Id. [16] Id. [17] Id. at 22.

[18] Id. [19] Id. at 23 [20] Id. at 24–25.

[21] Id. at 29.

[22] Id. [23] Id. [24] Id. [25] Id. [26] Id. at 31.

[27] Id. [28] Id. at 33.

[29] Id. at 34.

[30] Id. [31] Id. [32] Id. at 34–35.

[33] Id. at 34.

[34] Id. at 36.

[35] Id. at 34.

[36] Id. at 37.

[37] Id. at 41.

EPA was able to, based on data largely garnered from industry self-reporting, draw conclusions about how the fracking process could at various stages potentially affect water resources.

However, the EPA was not able to conclude that fracking actually affected drinking water resources in such ways a majority of the time. On the contrary, the report showed that through selfimposed industry standards and existing federal and state laws and regulations, incidences affecting water resources occur in a minority of fracking operations. In conclusion, the EPA report stated many things that are well known within both the energy industry and the regulatory sphere, but few new facts or conclusions pointing to the imminent need for further regulations, which would deteriorate America’s newfound energy independence.

[1] The Guardian, Origins of the EPA, Environmental Protection Agency, https://archive.epa.gov/epa/aboutepa/guardian-originsepa.html (last visited Mar. 10, 2017).

[2] About the Office of Research and Development, Environmental Protection Agency, https://www.epa.gov/aboutepa/about-office-research-anddevelopment-ord (last visited Mar. 10, 2017).

[3] Natural Gas Extraction - Hydraulic Fracturing, Environmental Protection Agency, https://www.epa.gov/hydraulicfracturing (last visited Mar. 10, 2017).

[4] Memorandum of Understanding, Arun Majumdar, US Department of Energy, et al., Multi-Agency Collaboration on Unconventional Oil and Gas Research (Apr. 13, 2012), https://unconventional.energy.gov/pdf/oil_and_gas_researc h_mou.pdf.

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The ENERGY NEWSLETTER is sponsored by the Harry Reed Institute for Oil & Gas at South Texas College of Law Houston

How to Help Support the Oil & Gas Law Institute at South Texas College of Law Houston

South Texas College of Law Houston’s ability to make strategic investments in initiatives such as the Oil & Gas Law Institute hinges on the amount of annual support at its disposal, and the size and strength of our endowment. Last year, the College directed a portion of its annual operating budget to fund the formation of the Institute. This budget has been supplemented by early philanthropic investments in the Institute made by generous friends of the College.

To sustain the Oil & Gas Law Institute for the future and expand its reach through partnerships with industry and other academic thought leaders, new CLE courses, public lectures, and symposia, the ENERGY NEWSLETTER, and additional faculty and staff, the College is seeking to enlist the help of the oil and gas community, its alumni, other corporate and foundation partners and the community at large.

The evolution of oil and gas law — and of the legal education and scholarship behind it — challenges all of us to be more nimble and purposeful. It requires us to innovate, reimagine, and adapt. So too do we understand the growing role philanthropy must play in the life of any educational institution that wishes to lead.

South Texas College of Law Houston would greatly appreciate a philanthropic investment in the Oil & Gas Law Institute. Together, we can ensure the Institute’s place as Houston’s premiere legal teaching and learning resource serving the oil and gas industry.

To make a tax-deductible donation, go to the link below. https://www.stcl.edu/academics/oil-gas-institute/support-us/

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