STCL Houston Energy Newsletter Spring 2019 by South Texas College of Law Houston

ENERGY NEWSLETTER South Texas College of Law Houston

Harry L. Reed Oil & Gas Law Institute

Oil & Gas Law Society’s Update Developing Trainings, Events, and Energy Students Exploration. Growth. If you’ve been following the Oil and Gas Industry in recent years, these words come to mind. From West Texas to Saudi Arabia, the old players and the new have been heavily engaged in a season of change amongst a whirlwind of economic, social, and political pressures. The new frontier of Liquified Natural Gas (LNG) is rapidly expanding, Saudi Aramco is poised to go public, the supply boom birthed in the Permian Basin is showing signs of slowing, and the public outcry for “clean” energy has never been so loudly voiced. In this time of industry uncertainty, the need for knowledgeable and skilled practitioners in Oil and Gas Law is at an all-time high. Over the past year, the SOUTH TEXAS OIL AND GAS LAW SOCIETY has seen its membership double in size, officially making it the largest Student Organization on South Texas College of Law Houston’s (STCLH) campus. This newfound outpouring of interest from new members has cultivated an atmosphere of enthusiasm and excitement throughout the society, with all signs pointing toward another historic year. Since the last publication in the Spring of 2018, activity has been marked by increased involvement with the Young Professionals in Energy, Association of International Petroleum Negotiators, and Houston Bar Association. Most notably, the OIL AND GAS LAW SOCIETY hosted its first annual CAREER EXPO for young energy professionals in April 2019, bringing over 75 students and practitioners together on STCL’s campus for an exclusive networking opportunity. For the 2019-2020 school year, the OIL AND GAS LAW SOCIETY’s focus will be on the planning and implementation of educational and career building initiatives for its members, capitalizing on the recent strides that the society has taken in those areas. With primary focuses on the increasingly important areas of Title Due Diligence, Environmental and Political factors, Bankruptcy, LNG, and emerging trends in Oil and Gas finance, the OIL AND GAS LAW SOCIETY strives to push the standard of Oil and Gas legal education in order to ensure the longevity of Houston’s place as the mecca of Oil and Gas law.

Spring 2019 Edition

Contents ••• Oil & Gas Law Society’s Update .................................. 1 Letter from the Editor ........ 2 The History of the U.S Permian Basin ..................... 3 The BIG XII: 12 Recent Appalachian Basin Legal Developments.................... 17 The Influx of Private Equity into the Oil & Gas Industry ...................... 27 United States Energy Friends & Foes ................... 42 Mitigating Political Risk for 21st Century Energy Projects…………………....61

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 3. The ENERGY NEWSLETTER is a student-run scholarly newsletter committed to bringing timely and unique perspectives to the global energy community. South Texas College of Law Houston has an extensive student network, 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 third volume of our ENERGY NEWSLETTER published through South Texas College of Law Houston. Having such a center stage in downtown Houston, the newsletter team is excited to bring topical 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 a look at the history of the U.S. Permian Basin. Next, is a survey of recent applicable case law from states in the Appalachian Basin region. We then turn to how the influx of private equity has impacted the oil & gas industry. Our fourth article discusses recent political developments affecting U.S energy independence. Finally, the newsletter ends with an overview of political risk insurance and its application to the energy industry. On behalf of the Editorial Board and the Harry L. Reed Oil & Gas Law Institute, 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,

Editor-in-Chief RYAN HOEFFNER Managing Editors JULISSA ESQUIVEL CLAYTON HART Executive Editor ASHLEY MASKUS Senior Articles/Note Editors ELENA BOLONINA ALEX BRADEN MATT DELGADO RUBEN PRECIADO Article/Note Editors KATY ANDRADE HAROLD JACKSON JOYCE MUSUKU JULIE McCLINTOCK

Student Authors

••• SEAN BERWALD MATTHEW GIBSON G. BRAXTON SMITH

Energy Alumni Advisory Council

••• TRACE HOLMES FORD PETERS GEORGE A. OGGERO MICHAEL VARGO

Ryan Hoeffner 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.

The History of the U.S Permian Basin: A Miracle of Technological Innovation By: Joseph R. Dancy Southern Methodist University Maguire Energy Institute

EXECUTIVE SUMMARY The Permian Basin is the largest petroleumproducing basin in the United States. Located in West Texas and in the southeastern portion of New Mexico, this legendary geologic region has provided a platform from which fortunes have been made and lost. The prolific hydrocarbon bounty of the area results from one of the thickest known deposits of Permian-aged rocks in the world formed from ancient and biologic-rich seas. Surprisingly, the Permian Basin was originally considered a â&#x20AC;&#x2DC;graveyardâ&#x20AC;&#x2122; by oil and gas developers. Using cable tool drilling technology common in the early days of oil and gas exploration a number of dry holes and marginal wells were drilled prior to 1922 which did little to change the perception of investors. That perception only changed with the drilling and completion of the Santa Rita #1 discovery well in 1923. Technology has always played a major role in the discovery and identification of viable mineral deposits. It has also played a central role in the discovery and development of the Texas Permian Basin. The area was extensively explored and developed for decades by dozens of promoters after the 1923 discovery. Over the last decade the value of the oil and gas properties in this historic Basin have increased in value by hundreds of millions of dollars as a result of recent advances in horizontal drilling and hydraulic fracturing technology. This article examines the historical origins of oil and gas development in the Permian Basin focusing on those technologies which served as catalysts for development. It also examines how these technologies have evolved over the last century, making the Permian Basin one of the premier energy exploration frontiers on the face of the earth.

INTRODUCTION Technology has always played a dynamic role in the development of North American oil and gas resources.1 This is especially true for the West Texas Permian Basin due to the nature of the geology and petroleum resource. Technological advances have taken an aging 94-year-old oilfield, one that had been extensively explored and developed, and transformed it into one of the most economically attractive exploration provinces on the face of the earth. Permian Basin production rates and reserve values have increased by hundreds of millions of dollars over the last decade due to advances in technology.2 The history of the Permian Basin is a story of how technology has enhanced the economics of existing hydrocarbon exploration and development, addressing a major global problem (peak oil), for the benefit of society.3 PERMIAN BASIN GEOLOGY The U.S. Permian Basin is named for the Permian geological age, an era that existed roughly 250 to 300 million years ago.4 An oil and gas producing Permian Basin also exists in Europe, named after the same geological era.5 The U.S. Permian Basin is composed of two sub-basins. The Midland Sub-Basin is on the eastern edge of the Permian Basin. It is located entirely within the state of Texas. The Delaware Sub-Basin is located on the western edge of the Permian Basin and a portion is located in New Mexico. Both the Midland and Delaware SubBasins were ancient seas during the Permian age.6

Between the ancient Midland and Delaware seas there was a shallower area of hills or an underwater uplift that separated these two bodies of water. Today this area is referred to as the Central Basin Platform, and to the north it is sometimes referred to as the Northwestern Shelf.7

states, will produce roughly 5.5 billion barrels of oil when it is ultimately depleted.13

Both the Midland Basin, the Delaware Basin, as well as the Central Basin Platform hold substantial oil and gas resources and reserves that are currently being developed using modern technology.8 Permian Basin hydrocarbon deposits are composed primarily of crude oil and natural gas liquids. In certain areas there are substantial amounts of associated natural gas.9 Some geological formations in the Permian Basin contain predominantly natural gas reserves, but these areas are in the minority.

THE DRAKE WELL (1859): EARLY U.S. OIL & GAS DEVELOPMENT The first well drilled in the United States specifically for crude oil was spudded in Western Pennsylvania in 1859. It was drilled to a depth of 69 1/2 feet.14 Christened the Drake well, it was developed using cable tools which was the standard drilling technology utilized at the time. When completed the shallow well produced roughly barrels of crude oil a day.

In much of the Permian Basin geologists tell us that the pressures, thermal maturity, and aging of the hydrocarbons was such that oil and some natural gas was effectively created from the trapped biomass over hundreds of millions of years. Conventional oil and gas fields exist in those areas of the Permian Basin where reservoir rock has the requisite porosity, permeability, and â&#x20AC;&#x2DC;cap rockâ&#x20AC;&#x2122; in place or faulting to trap any hydrocarbons that were formed.

The Drake well was drilled under the terms of an oil and gas lease that contained provisions that were commonly used for the drilling of saltwater wells. Salt at the time was used to preserve food. The owner of the land could lease to the driller with the landowner getting a 1/8 royalty on salt production.15 Later, when oil was the target, the landowner likewise received a 1/8 royalty on oil production.16 So it would naturally follow that the same technology and methodology used in salt water well drilling would be utilized when the focus turned to oil.

Current estimates rank the Permian Basin as the largest crude oil field in the United States measured both by reserves and production.10 With the increase in production and drilling activity over the last decade it currently produces roughly 24% of U.S. production.11 Much of the increase in production from the Permian Basin has occurred since 2009 when several new technological developments (discussed below) were introduced into the exploration and development process.

Technological advancements played a role with regard to the drilling of early oil wells and also with regard to the transportation of the products to market. At the Drake well the produced oil was stored in 42-gallon wooden barrels crafted nearby. Industry still uses the barrel as the standard volumetric measure of oil today.17 The barrels of oil were initially transported on barges down the local creeks to market. Later, railroad cars were used to assist in the transportation of oil from the Drake Well. These railcars, some of which were referred to as

The United States Geological Society (U.S.G.S.) recently evaluated the potential of one formation in the Permian basin, the Wolfcamp shale, and estimated that 20 billion barrels of oil could be recovered with 1.6 billion barrels of natural gas liquids.12 To put this in perspective the massive East Texas Oilfield, the largest conventional field ever discovered in the lower 48 4

Densmore cars, could significantly increase the amount of product that could be sent to market from the remote well locations.18 Pipelines were introduced when metallurgy advanced and made transport over intermediate distances feasible. Pipelines were especially useful when markets were near larger fields. Transportation costs and loss in transport, regardless of mode, typically absorbed a significant portion of the sales revenue for the product.19

The first technological advance that allowed the Spindletop developers to make the discovery was the fact the drillers utilized a rotary rig versus cable tool drilling technology.23 In a rotary rig the pipe is rotated in the hole as the well is deepened, versus the up and down pounding of a drill bit used in cable tool drilling. The rotary rig was more effective drilling though the loose sands encountered before the target depth. Secondly, the developers inserted ‘mud’ from a nearby pond pumped through the drill pipe into the wellbore to hold back loose sand. The loose quicksand like condition heretofore had clogged the wellbore of the first two cable tool drilled wells. This made drilling deeper and completing the wells impossible.24 These technological advances would be used in future years to control downhole well pressures and enhance drilling productivity.

NEW PRODUCTION AND MARKETS (1880-1900) Exploration and production expanded after the 1859 Drake Well discovery, moving from Pennsylvania into West Virginia, Ohio, and eventually into Indiana and Illinois. As of1900 these states were the primary oil producing provinces in the United States. John D. Rockefeller during this time was able to monopolize much of the transportation and refining capacity in these areas under the Standard Oil umbrella, which allowed him to build a fortune in this new industry.20

On January 10, 1901, an estimated 100,000 barrels per day of crude oil blew skyward from the Spindletop wellbore.25 The Spindletop well was the first time in world history where production from one well doubled global oil productive capacity overnight.26

As new markets for crude oil developed, including the demand generated by the internal combustion engine, public concern grew that oil supplies would not be sufficient to meet the longterm demand growth. In the emerging automobile industry roughly one-third of vehicles were powered by battery, one-third were powered by steam, and one-third were powered by the internal combustion engine in 1900.21 At that time the internal combustion engine was comparatively noisy, dirty, vibrated violently and was difficult to start, but many of these drawbacks were eventually overcome as the automotive engine technology advanced.

The geology of the Spindletop well was also unique compared to that of existing fields in Ohio and Pennsylvania. Located in southeast Texas near the Louisiana state line, Spindletop was drilled into an oil field that was associated with the apex of an underground salt dome.27 Historically Ohio, West Virginia, and West Texas oil reservoirs generally involved oil or gas structural traps in areas once covered by ancient seas. WEST TX OIL FIELDS (1900-1922): THE PERMIAN BASIN During the 1900 to 1922 time period the potential for oil and gas production from lands in West Texas was considered remote. The area was known as a ‘graveyard’ for wildcat drillers.28 Due to the sparse population, arid nature of the land, lack of skilled labor, and lack of transportation facilities West Texas was generally avoided by explorationists. Few developers would risk investing funds for leases or by drilling in West Texas.

SPINDLETOP AND THE AGE OF OIL (1901) The concern about the scarcity of crude oil was addressed by an event that occurred in Southeast Texas in January of1901, an event that was to change the future of energy use forever. Using technological advancements deployed after the failure of two prior drilling attempts a well on Spindletop Hill blew out at a location near Beaumont, Texas.22 5

When the State of Texas joined the U.S. it dedicated millions of acres of western ranch land to support higher education.29 For years the land was leased for grazing purposes, however the arid nature of the land and remote location led to a situation where.30agricultural rentals were modest.30

amounted to $43,136, ten cents per acre, as provided for in the statute. Attempting to raise the money from investors to pay for the leasehold rights he was unable to generate sufficient interest or funds.39 To recover at least a part of the costs he incurred attempting to lease, Ricker sold the right to acquire the leases to a promoter named Frank Pickrell for $2,500. Pickrell agreed to pay the initial lease rentals if he could raise the funds.40 Ultimately Ricker’s applications for the leases expired and Pickrell had to re-file applications with the State of Texas for the leases.41 Pickrell organized a company he named Texon to raise capital, to develop these leases, and planned to drill an exploratory well within 18 months somewhere on the property.42

Mineral leasing for oil and gas exploration and drilling activity in West Texas, at least in the Permian Basin area, was rare in the early 1900’s. A University of Texas geological professor, Dr. Johan Udden, conducted a study of the Permian Basin lands in 1916 and concluded that in his opinion the lands could in fact hold substantial quantities of oil and gas even though none had been found to date.31 The problem for developers was that oil prospectors at the time considered the area a haven for dry holes. Geologists, even professors, were not considered to be entirely credible due to the new nature of their science and expertise.32

CABLE TOOL DRILLING TECHNOLOGY In the early years of oil and gas exploration activity wells were drilled using cable tool rigs.43 This methodology had been used for hundreds of years to drill water wells. It was adopted by the oil and gas industry as those products became valuable. Early reports indicate that landowners drilling for water frequently encountered natural gas or crude oil in Pennsylvania, New York and Ohio. In the early 1800’s salt springs created a robust and profitable salt manufacturing industry in West Virginia as the brine was evaporated.44 Salt was utilized for food preservation in the day. Too much natural gas or crude oil would ruin a good water well, to say nothing about safety issues.45

No producing oil field at that time had been discovered within 100 miles of the Permian Basin.33 Adding in the remote nature of the lands, lack of manpower, the physical difficulty getting equipment to the area, led to a situation where few were willing to take a chance drilling. Those that did explore the Permian Basin prior to 1923 generally encountered a series of dry holes or very marginal wells.34 Several wells were drilled in the 1880’s that were dry, although a small oil field was discovered in Reeves County in 1903.35 A well drilled in 1920 on the Eastern Shelf of the Midland Basin produced somewhere between 10 and 50 barrels of oil per day.36

Much of the technology and methodology used in early oil well drilling had its start in the drilling of salt water wells.46 The first well drilled in North America, as opposed to dug, was a salt water well drilled by the Ruffner brothers in West Virginia in the early 1800’s.47 It was common for natural gas to also be discovered in salt water wells. The gas could be utilized in the manufacturing process to evaporate the water.

A University of Texas law student at the time from a small town in the Permian Basin named Rupert Ricker heard about Dr. Udden’s geological study of the Permian Basin lands.37 When he graduated Ricker decided to try to raise money to explore the Permian Basin, leasing lands for oil and gas from the State in 1920. Under the State of Texas leasing rules in place at the time Ricker acquired rights to roughly 431,360 acres (680 square miles).38 Under the lease terms Ricker had 30 days in which to pay the oil and gas rental payments. The rental payments

Cable tool technology provided the driller few means to control downhole pressures that might be encountered in oil and gas formations. As a result, many early cable tool wells “blew out" which resulted in a great waste of oil and gas, 6

substantial damage to the environment, as well as creating a substantial fire hazard.48

formations, such as encountered in Southeast Texas where the Spindletop well was located, sand would cascade from the wellbore walls into the well making cable tool drilling difficult or impossible.49

In addition to the problems noted above, when a well erupted the public quickly became aware of the potential value of the surrounding leases. Third parties could take financial advantage of the event by leasing lands near the productive well, even though the driller and developers had incurred all the drilling and economic risks.

Because of the nature of the drill bit, the drilling method, and the cleaning out of the well the cable tool drilling operations were generally slow. When drilling for water many of those wells were less than 100 feet deep so the cable tool process was sufficient from a technological standpoint.

In most cases, the power source for the cable tool rig in the early years was a steam engine. In areas of West Virginia, Pennsylvania, Ohio, and Indiana the water and fuel for the steam engine was abundant, usually wood from the local forest or coal.

The cable tool drilling method had several advantages for the developer. First the driller could continually monitor the lithology of the well as it was drilled. Second any oil or gas shows would be quickly noted. It was relatively easy for the developer to identify exactly what depth and strata the oil or gas production originated from.50 Due to these advantages, and several drawbacks of the more advanced rotary rigs introduced around 1900 in certain fields, cable tool rigs were utilized much longer in the Permian Basin than elsewhere.51 SANTA RITA #1 (1923) PERMIAN BASIN DISCOVERY WELL Frank Pickrell, like law student Ricker, had difficulty raising funds from potential investors to explore the Permian Basin. Hugh Tucker, a geologist Pickrell had hired at Texon, pinpointed a location on the Permian Basin leases at which to locate a well.52

When cable tool rigs moved to arid areas such as West Texas, Western Oklahoma, and Western Kansas not only was fuel in short supply but many times water was not readily available in the quantities needed to generate steam. It was not uncommon to ship water and fuel to the drill site to power the steam engine.

Transportation options at that time were such that moving a cable rig to the specific location identified by geologist Tucker would be extremely costly and time-consuming. Nonetheless, the promoter contracted for a cable tool drilling rig and had the rig transported to a location around14 miles west of Big Lake, Texas, on the railroad line running through the area.

Due to the nature of the cable tool drilling, the vertical lifting and dropping of a heavyweight with a pointed tip to break the rock, wells drilled using this method could only be drilled vertically or nearly so. It was difficult, if not impossible, to deviate a hole from vertical.

Due to time constraints, and lack of capital, the cable tool rig was set up 124 feet north of the railroad right-of-way miles away from the location geologist Hugh Tucker had selected for the well.53 Pickrell also found he needed to spud the well almost immediately to extend the term of the lease,

Every three feet or so the rock clippings or chips had to be removed from the well bore to allow drilling to proceed. In extremely sandy 7

and further did not have the funds or time to transport the equipment to the desired location.

water was more valuable than oil, and the cost of moving oil to market was prohibitive.60

The wildcat well was christened the Santa Rita #1 well. Pickrell had raised some drilling funds but needed more, so visited New York City where he obtained funds from interested third-party investors. Santa Rita was the Catholic Saint of the Impossible according to legend, which is why the name was chosen.54

The drill site had at least one advantage: Because the Santa Rita #1 was drilled so close to the railroad it could be used to transport oil to market. The nearest pipeline was 125 miles away.61 The developers built 17 oil storage tanks nearby each with a capacity of 80,000 barrels, and eventually a 400-mile pipeline to the refineries on the coast of Texas.62

Drilling using cable tools is extremely slow in the best of times. In the Permian Basin area, there was a lack of water and a lack of fuel for the steam engine that powered the drilling apparatus. The Santa Rita #1 well was spudded timely, thereby preserving the leases. Drilling was extremely slow due in part to material shortages, labor shortages, and the nature of the geology. The well took 20-21 months to drill to a depth of just over 3,000 feet.55

PERMIAN BASIN: SANTA RITA & RELATED DEVELOPMENT WELLS Under the terms of the State of Texas oil and gas leases acquired by Frank Pickrell, numerous wells were required to be drilled to extend the terms of the leasehold acreage. Pickrell had raised some capital but did not have the amount needed to drill and equip numerous wells. To address the problem, he negotiated the sale of a large portion of the leasehold interest, as well as the interest in the Santa Maria #1 discovery well.63

Because cable tool drilling methodology doesn't provide the means to address high pressure natural gas or oil on discovery these substances generally rushed from the formation into the wellbore. The substances frequently moved upward in the wellbore with extreme force, resulting in an uncontrolled well condition. Many times, the highly pressurized oil or gas would damage the cable tools or rig during the eruption, and it was not usual for a crater to form around the wellbore.

The interest was purchased by two well-known and successful wildcatters from Pittsburgh, Michael Benedum and Joseph Trees.64 These parties agreed to drill at least eight wells on leases surrounding the Santa Rita #1 discovery well.65 Trees and Benedum formed the Big Lake Oil Company to develop the Permian Basin properties, using the entity to raise capital back east.66 They also formed a parent company to hold Big Lake Oil Company stock, Plymouth Company, which also was used to raise capital and to invest in West Texas ventures other than the Santa Rita leases.67

Drilling activity on the Santa Rita #1 was completed the evening of May 27, 1923, and the well sat quietly overnight. Before the dayâ&#x20AC;&#x2122;s operations could commence it began to blow out the morning of May 28.56 The well erupted every 12 hours for a number of days, alerting the public that there could be substantial amounts of oil wealth hidden underground.57

The first eight wells drilled by Benedum and Trees after the Santa Maria #1 discovery well were marginal at best.68 Despite this fact the wildcatters decided to allocate more capital and to continue drilling on the prospect.69 While wells number two through eight were marginal, the Santa Maria #9 and the Santa Maria # 11 wells observed initial flows of anywhere from 3,000 to 8,000 barrels per day.70 These flow rates, if maintained, would make the wells economic.

The Santa Rita #1 well produced roughly 100 to 150 barrels per day of oil, along with substantial water, during the eruptions.58 While a fraction of that from the East Texas Spindletop well it was the first time that substantial oil production had been discovered in the West Texas Permian Basin.59 As with Spindletop the rural, sparsely populated, arid area created challenges with regard to transportation of the product to market. In fact, in many areas of the Permian Basin at the time

Several years later, in 1926, the prodigious Yates Field would be discovered in the Midland Basin to the south, with the initial well producing 8

4,000 barrels per day.71 By the time they drilled the Yates #32 well the initial production rate observed by the developer was 204,000 barrels per day, a record for both the state of Texas and the world!72 These wells illustrated the potential viability of the Permian Basin and were the largest discoveries ever for successful wildcatters Benedum and Trees.73

Roberts patented the process and charged $100 to $200 per shot, with an additional royalty of 1/15th of any increased production from the blast.76 Keep in mind this is in the late 1800’s, so these charges were quite substantial. As a result of the substantial cost of shooting using the Roberts torpedo a number of producers rigged their own explosive to shoot a well, violating the patent, which resulted in a large amount of litigation. Since the blasts were illegal these producers generally shot at night, hence creating the term ‘moonlighter.’77

THE NITROGLYCERIN TORPEDO Crude oil in the ground is frequently trapped in formations at high pressure and at elevated temperatures. Once liberated from that high pressure, high temperature environment dissolved substances in the oil or gas are likely to precipitate as the oil cools and reaches ambient pressures.

Nitroglycerin is very unstable. Getting the chemical to the wellsite was a challenge since many of the roads were dirt, mud, and full of rocks and holes. It was common for the explosive to detonate during transportation or prematurely at the well, causing many deaths and injuries.78

One of the early operational issues that many crude oil producers experienced was the fact that oil wells would tend to plug up with paraffin, wax, tar, or similar substances. The quality of the oil determined how much wax or paraffin precipitated out of the oil.74

None-the-less torpedoing a well usually resulted in increased production – and eventually was replaced with hydraulic fracturing techniques utilized today.

In addition to impurities, formations that developers encountered may have lacked the required permeability to allow the oil or natural gas to migrate from the formation into the wellbore.

RULE OF CAPTURE & THE PERMIAN BASIN Early courts adopted an ownership theory with regard to oil and natural gas referred to as “the Rule of Capture”. The rule stated that oil or natural gas is not owned until it is captured, or produced.79 As such development at wells such as the Spindletop Well in1901, and other discoveries of similar significance, proceeded at breakneck speed as the developer attempted to drill and produce as quickly as possible regardless of market conditions.

A creative inventor by the name of Edward Roberts designed a solution to the problem—an explosive charge he would insert in the wellbore.75 The blast would clean the wellbore of wax and paraffin. If the blast was powerful enough it had the additional benefit of creating additional fractures in the rock, which increased permeability, allowing the oil to flow more freely to the wellbore.

Due to the lack of transportation facilities and remote location of many of the new discoveries much oil and natural gas was wasted or lost. Within two or three years of discovery, the major producing sand at Spindletop well had been mostly depleted of its reservoir pressure.

Before shooting the well the explosive, usually nitroglycerin, was placed in the well in a metal canister and lowered to the point where the blast was desired. A pointed rod was dropped down the well, and when it penetrated the canister the well exploded. Usually the operator filled the well up with water to help keep the explosive pressures directed into the wellbore walls. This water also had a great effect at the surface as it was shot out of the well on ignition.

After the 1901 Spindletop discovery wildcatters began focusing northward and discovered the impressive Glenpool (1905) and Cushing (1912) fields in Oklahoma, some of the early discoveries occurring even before statehood (1907).80 In these fields there was a rush to develop and produce, again in large part due to the 9

ownership rules established under the Rule of Capture. The Santa Rita #1 and accompanying Permian Basin wells were somewhat unique in that they were drilled on a very large oil and gas lease block. Oil or natural gas was extremely unlikely to migrate far across lease lines in this area due to the distances to the lease lines, so the developers did not have to engage in a ‘drilling’ or ‘production’ race to establish ownership of the oil.

The rotary rig also has the advantage of allowing the driller to deviate the well from the vertical. With rotary drilling the drill bit constantly turns to the right as it penetrates the ground. As a result, in many cases it makes a ‘corkscrew’ like wellbore (highly exaggerated in the illustration) as the well is drilled. Such deviation could be used to cross lease lines, effectively draining oil from under neighboring lands. In some parts of the East Texas Oilfield it has been estimated that 10% of the wells were drilled across lease boundaries, usually from the edge of the filed into the producing formation.85

Likewise, later development was generally conducted on larger leases, removing a major concern that a competitor may drill nearby, drain the oil, and establish ownership of the oil or gas for themselves.

The following is an odd story about the application of World War II technology to oil and gas industry downhole surveys, recently retold by a professional acquaintance:

As a result of this situation the reservoirs in the Permian Basin have in general been developed more effectively, with more oil or natural gas recovered than in other fields.

Some may not be aware that gravity assures that the old cable tool drilling rigs drilled a straight, vertical hole. Then rotary drilling rigs were introduced, their wellbore tends to 'walk up dip'; by that I mean when a rotary rig drills into formations at depth that are dipping, there is a tendency for the bit to wish to drill at right angles to the dipping formation (the bit walks up dip).

ROTARY RIG DRILLING TECHNOLOGY Rotary drilling turned or rotated the drill pipe in the hole as the well was deepened (versus pounding a drill bit up and down as was the case with cable tool rigs). The technology replaced cable tool drilling and began to be adopted around 1900 and thereafter.81 Rotary rig drilling technology for oil was adopted from the drilling of shallow water wells where rotary rigs were drilling wells both quickly and economically.82

Due to the fact that rotary drilling did not drill a straight vertical well, there was the problem of not knowing the bottom hole location (also needing to know the vertical depth as opposed to the measured depth). There was the need/desire to obtain a directional survey of the well bore to accurately understand the trajectory of the well bore.

The rotary rig drilling process has certain technological advantages over cable tool rigs. First, the rotary drilling technology inserted water or drilling mud through the drill pipe which helped control any high-pressure oil and gas zones that might be encountered. While ‘mud’ is not expressly mentioned in the early years, soft shales and clays dissolved by the injected water created an effective mud in many early wells drilled near Corsicana, Texas, in the 1890’s.83

The first well logging tool that was constructed to do this used a bit of surplus WWII hardware - and that was the inertial guidance system from the German V-2 Rocket. The technology that allowed a rocket launched from Peenemünde on the German Coast to strike the Docks in the East End of

Second, drilling cuttings were continually removed from the well bore to the surface which made the drilling process more efficient.84 The water or mud also cooled and lubricated the drill bit. 10

London was harnessed to create a new well logging tool. The rotary rig had certain disadvantages, however. First, when water and early mud mixes were injected into the well to flush out drill cuttings many times these fluids migrated into the formation, damaging or destroying the well.86 Second, sometimes the rotary bit would drill completely though the oil or gas bearing formation and the driller would be unaware of that fact, leaving the oil and gas undiscovered due to the oversight.87 Cable tool drilling allowed the operator to be much more cognizant of any oil and gas zones, shows, or intrusions into the wellbore. PERMIAN BASIN LITHOLOGY Of the two sub-basins the Delaware, the western most sub-basin, is the deepest.88 Due to the depths the shale formations and the longer horizontal components of these wells the drilling rigs generally require more horsepower than in the Midland sub-basin or other unconventional fields.89

Because of the nature of the geology, drillers can locate multiple wells at one surface location, or pad, and drill from that site to different depth horizons. This procedure reduces surface damage and substantially increases drilling efficiency since a series of wellbores can be drilled by skidding the rig a few feet in one direction or another on the pad.

The Midland Basin is somewhat shallower that the Delaware. Some geologists attest that the rock or shale in the Midland Basin for the most part is a bit better quality than that in the Delaware. A cross section of the subbasins, the Central Basin Platform, and the Eastern Shelf is set out above (west to east cross section).

Surface facilities such as pipelines, tanks, separators, and compressors on the pad can also be designed so as to maximize efficiencies and minimizes costs. RECENT TECHNOLOGICAL DEVELOPMENTS

In both basins the Wolfcamp shale has proven to be one of the more productive for developers. In many areas the Wolfcamp formation will be subdivided into units, with four to six possible Wolfcamp zones.90

Historically, developers in Texas drilled vertical wells into â&#x20AC;&#x2DC;reservoir rockâ&#x20AC;&#x2122;. These are formations that had the requisite porosity and permeability to allow hydrocarbons to accumulate for the thousands or millions of years necessary to trap a commercial accumulation of oil or gas. It was not uncommon to drill multiple dry holes, even in producing fields and utilizing the latest geological data and geophysical interpretation.

Permian Basin wells are generally 4,000 to 10,000 feet deep, with the Wolfcamp shale being 700 to 4,000 feet thick.91 Average lateral length is roughly 7,550 feet, more than one horizontal mile!92 Some developers have claimed up to a dozen potential pay zones exist in the Delaware Basin.93 Because of the geology, the Permian Basin has been described by some geologists as a layer cake of stacked potential producing formations.94

The reservoir rock also had to include a trap, generally a fault or stratigraphic cap rock to keep the hydrocarbons from escaping. Over the last ten years drilling and fracing technology advanced to the extent that wells now 11

can be drilled into the source rocks. The source rock was previously non-commercial, and in many cases consisted of shale. The shale now can be fractured with pressurized fluids and proppant.

Local sands have been used but generally have been somewhat less effective, although the cost of the local sand is much lower and access to quick deliveries is enhanced. From an economic standpoint for roughly each incremental $1 worth of sand the return is $5 to $10, making a compelling case for increasing sand intensity.95 Five years ago select wells in West Texas used roughly 20 railroad hopper cars of sand. Today it is not uncommon for a well to use a ‘unit train’, a 100-hopper car train a mile long.96

The ‘layer cake’ nature of the Permian Basin allows the developer to develop multiple source rock formations from one surface pad, increasing efficiency and decreasing water disposal and hydrocarbon transport costs.

Rystad Energy, an energy consulting firm, conducted a Permian Basin well survey of changes in well characteristics between the first quarter of 2014 and the first quarter of 2017.97 The results are a stunning snapshot of productivity enhancement for those who don't follow the industry closely: 1. Laterals have increased in length by 27% over the 3-year period 2. Proppant intensity per foot has roughly doubled over the 3-year period As drilling and completion attempts evolve developers are finding that longer horizontal laterals are proving more productive and economic. Measurement while drilling (‘MWD’) technology allows the operator to track the position of the drill bit as it bores hole thousands of feet from the entry point. In addition, sensors can detect if the drill bit is in the target shale, or if it has deviated out of the source rock.

3. Fluid intensity per foot has roughly doubled 4. The 30-day initial production rate bbl/d for oil increased 30% 5. The oil estimate ultimate recovery has increased by 106% As a result of the longer laterals, more proppant and fluid, and enhanced completion techniques efficiencies are increasing, which wells are yielding much more oil and gas than early completion attempts. The estimated ultimate recovery of oil has increased by over one hundred percent in the last three years according to some estimates.98

Logging technology has also evolved where the lateral section can be logged to determine if any faults exist which may impact frac performance. The logging technology can also be used to determine the characteristics of the target formation which allows the operator to design an effective fracturing program. With regard to fracing, the companies are generally finding that the more sand they use per horizontal foot the better the well performance. Sand from Wisconsin, referred to as Northern White, has been the preferred sand due to the spherical nature of the sand and the grain strength which keeps formations propped open and allows oil or natural gas a pathway to the wellbore.

CONCLUSION Drilling and completion efficiency in the Permian Basin continue to improve quarter to quarter as technology continues to evolve in a rapid manner. Over the last decade massive amounts of wealth have been created for mineral owners, companies, and the nation due to these 12

advances. In addition, thousands of new, wellpaying jobs have been created.

Associated gas, sometimes referred to as casinghead gas, is natural gas that is produced in junction with crude oil. 10

See James Osborne, A Massive Oil Field in West Texas, DALLAS MORNING NEWS (July 25, 2013), http://www.dallasnews.com/business/energy/2013/07/25/amassive-oil-field-in-west-texas-but-how-massive.

The 1812 Brothers Grimm Tales involve a King who was told a miller’s daughter can spin straw into gold. Unlike the fable, Permian Basin developers did not need Rumpelstiltskin to accomplish the seemingly impossible task. Technology has allowed areas which had been abandoned due to marginal economics to be converted into some of the most promising prospects on the face of the earth. The technology to spin straw into gold has been revealed at last.

Forty percent of U.S. drilling rig activity in the Permian Basin as of April 21, 2017. See Permian Basin Oil Production and Resource Assessments Continue to Increase, U.S ENERGY INFO. ADMIN. (Apr. 26, 2017), http://www.eia.gov/todayinenergy/detail.php?id= 30952 12

U.S. GEOLOGICAL SURVEY, ASSESSMENT OF UNDISCOVERED CONTINUOUS OIL RESOURCES IN THE WOLFCAMP SHALE IN THE MIDLAND BASIN (2016). The study also found that 16 trillion cubic feet of associated natural gas is recoverable.

This is especially true in Texas, site of numerous major conventional oil and gas discoveries and the location of four major unconventional shale basins. These basins include the Permian Basin, Eagle Ford Shale, Barnett Shale, and Haynesville Shale.

JAMES A. CLARK & MICHAL T. HALBOUTY, THE LAST BOOM 257, 287 (1972) (noting that a good-sized conventional oil field would be 0.1 billion barrels in size). 14

J.E. BRADLEY, HISTORY OF OIL WELL DRILLING 64–75 (1971).

Some analysts have noted that the value of Permian Basin assets have increased by hundreds of billions of dollars, due in part to the massive size of the oilfield and due in part to technology making heretofore uneconomic deposits viable.

Efficiencies, with further technological advances, are expected to continue lowering production costs and improving profitability. As technology has advanced mineral owners, lessees, the State, and the nation have benefited.

American Oil & Gas Historical Society, Making Hole – Drilling Technology, AOGHS.ORG , http://aoghs.org/technology/oil-well-drilling-technology/. (last visited Jan. 19, 2018) [hereinafter American Oil & Gas] (noting that in 1802 drillers in West Virginia discovered enough saltwater to develop a salt manufacturing center for early settlers).

EARL A. BROWN, JR., THE LAW OF OIL & GAS LEASES (2d ed. 1973).

At the end of the Permian era the earth experienced its worst mass extinction in history with 90% of plant and animal life forms disappearing from the face of the earth. See generally PETER BRANNEN, THE ENDS OF THE WORLD (2017).

Not all barrel measurements are equal. A barrel of beer is customarily 36 gallons, while a barrel of oil is 42 gallons. 18

American Oil & Gas, supra note 15. James and Amos Densmore of Meadville, Pennsylvania, were granted the patent for their “Improved Car for Transporting Petroleum” in 1866.

Northern Europe is the site of one of the largest natural gas fields in the world, the Permian age Groningen field. The natural gas from this field is produced from the Rotliegend sandstone reservoir rock, with a Zeckstein salt cap rock creating the hydrocarbon trap. The source rock for the hydrocarbons is the underlying carbonaceous shales and coal seams. This analysis will focus solely on the North American Permian province.

Even today many systems track “lost or unaccounted for” gas or oil, referred to as system “lug.” High lug levels indicate problems with measurement, engineering design, or pipeline integrity, and reduces economic returns.

See Permian Hyperbole, THE ECONOMIST, Nov. 5, 2016. We will refer to the Midland and Delaware sub-basins as the Midland Basin and the Delaware Basin for the purposes of this paper.

Henry Flagler, partner with Rockefeller, was instrumental in arranging transportation modes for the crude oil in a way that would benefit the Standard Oil companies. Oil, without a reasonably priced transportation method to reach the end use market, is of little value at the wellhead. EDWARD N. AKIN, FLAGLER: ROCKEFELLER PARTNER AND FLORIDA BARON 24, (Kent State Univ. Press Paperback ed. 1991).

John A. White, Roth Capital Partners, The Horizontal San Andres: What a Difference a Year Makes (July 17, 2017). 8

Geologists indicate the ancient seas of Permian age extend into Mexico, however that area has not been well explored or developed. In Mexico the government controls the mineral rights and development, unlike the United States where minerals are owned, and capital is allocated mainly by private parties.

The History of the Electric Car, U.S. DEP’T OF ENERGY (Sept. 15, 2014), http://energy. gov/articles/history-electriccar (noting that electric cars had roughly one third market share in 1900, and shared the market with steam and internal combustion vehicles.

The 25-foot-high hill was originally named Sour Creek Hill, and locals claimed you could smell sulfurous odors emanating from trapped substances underground. JO STILES ET AL., GIANT UNDER THE HILL: A HISTORY OF THE SPINDLETOP OIL DISCOVERY AT BEAUMONT, TEXAS, IN 1901 at 106–09 (2002).

JO STILES ET AL., supra note 22, at 48. Id. at 116

Id. at 134.

Id. at 134–35 (indicating that the Texas legislature amended applicable statutes allowing larger blocks of acreage to be leased and extended the term of the leases issued by the State by six months); see also COX, supra note 31, at 41– 49.

HAROLD WILLIAMSON, THE AMERICAN PETROLEUM INDUSTRY: 1899-1959 THE AGE OF ENERGY 29 (1963) 25

Id.

WILLIAMSON, supra note 23, at 29. Early Permian Basin development also saw the use of cable tool rigs almost exclusively, although rotary rigs had been introduced and were becoming more popular since they generally were much more efficient.

William J. Knights, Vice President, Netherland & Sewell Oil & Gas Property Evaluation Seminar (2015). 27

Salt dome formations are relatively common along the Gulf of Mexico coast as well as offshore. Oil or natural gas tends to be trapped above the dome or along the side of the salt formation.

BRADLEY, supra note 14, at 62–71.

See American Oil & Gas, supra note 15. The Ruffner brothers drilled for saltwater in 1802 in West Virginia and established a manufacturing and distribution center for salt. Any associated oil was sold as a medicine.

SAM MALLISON, THE GREAT WILDCATTER: THE STORY OF MIKE BENEDUM 327 (1953); see also GUS CLEMENS, LEGACY: THE STORY OF THE PERMIAN BASIN REGION AND SOUTHEAST NEW MEXICO 133–39, (1983). 29

In 1876 the Texas Constitution allocated acreage to endow the Permanent University Fund. MALLISON, supra note 28, at 326.

See BRADLEY, supra note 14, at 62–71.

Id.

Some reports were that early Pennsylvania settlers when drilling a water well had them ignite due to the natural gas, throwing ‘fire and brimstone’ on the landscape. Some claimed that the driller had drilled all the way to hell. Natural gas seeps that ignited were referred to as burning springs. See American Oil & Gas, supra note 15.

Geologist L.C. Snider stated the Permian rocks ‘have not yielded any oil or gas . . . and their nature is such that it seems improbable that any will be found in them.” MIKE COX, TEXAS PETROLEUM: AN UNCONVENTIONAL HISTORY 41 (2015) (internal quotations omitted). CLEMENS, supra note 28, at 133–39. Dr. Udden when describing the geological structure noted “it does not appear unreasonable to regard it as suggesting the possibility of the presence of buried structures in which oil may have accumulated”. COX, supra note 30, at 41.

See id. The drillers utilized a rotary rig when drilling the Spindletop well since earlier attempts using cable tool rigs failed due to sand intrusion into the wellbore.

WILLIAMSON, supra note 23, at 29–32.

MIKE COX, WEST TEXAS TALES 100 (2011).

CLEMENS, supra note 28, at 133–39.

Id. at 29. Cable tools were also used longer in West Virginia and the Rocky Mountain area, but were quickly replaced by rotary rig technology in those areas with sand or shale formations that inhibited cable tool drilling due to wellbore instability.

Id.

BOBBY WEAVER, OILFIELD TRASH: LIFE AND LABOR IN THE OIL PATCH 109 (2010).

CLEMENS, supra note 28, at 35–36. A well later drilled at the location identified by geologist Tucker ironically was dry.

The Abrams #1 well was drilled in Mitchell County and produced roughly 10 to 100 barrels of oil per day. The well was located on the Eastern Shelf, or edge, of the Permian Basin. See COX, supra note 31, at 41–49. The literature is inconsistent as to how productive the well actually was, possibly because the well was torpedoed with nitroglycerin which would impact short term production rates.

WEAVER, supra note 32, at 108 (indicating that the well was 174 feet north of the railroad); MALLISON, supra note 28, at 323 (indicating that the well was 150 feet north of the tracks). 54

WEAVER, supra note 32, at 110 (stating that the well also drilled through natural gas formations and a thick section of potash)

CLEMENS, supra note 28, at 133–39.

COX, supra note 31, at 41– 49; see also MALLISON, supra note 28, at 328. 39

CLEMENS, supra note 28, at 133.

Id. at 108.

Id. at 110 (stating that a train of spectators was brought to the wellsite in early June, with an estimated 1,000 visitors observing the periodic blowouts). 58

history for their efforts in the Permian Basin. MALLISON, supra note 28, at 321. 74

WILLIAMSON, supra note 23, at 152. The practice of placing of an explosive charge at the bottom of a water well to enhance the well capacity was adopted by the oil industry, with similar positive results increasing well productive capacity.

MALLISON, supra note 28, at 321.

Some claim the 1920 Abrams #1 was the first commercial well completed in the Permian Basin, the accounts differ as to how productive that well was from an economic standpoint.

Id. at 148. Early water well drillers inserted charges into the wells to enhance flow rates, from which Roberts apparently borrowed the idea. Initially Roberts used black powder, then advanced to nitroglycerin which was much more powerful but also much more dangerous. Many were injured or killed due to unexpected or premature explosions.

Drinking water was shipped to the wellsite from Big Lake, a dozen miles to the east. CLEMENS, supra note 28, at 143; MALLISON, supra note 28, at 344–45. 61

COX, supra note 31, at 100.

WEAVER, supra note 32, at 111.

Id. at 152. The cost to manufacture the torpedo was estimated at $20, so the margins were incredibly lucrative. Enforcing his patent Mr. Roberts became responsible for more litigation than any U.S. citizen.

Pickrell sold a 75% undivided interest in the leases on the condition that a number of new wells would be drilled by the purchasers. See CLEMENS, supra note 28, at 137.

Benedum had originally told Pickrell he had no interest in the Permian Basin leases and recommended he talk with the majors about development. Pickrell returned to Benedum and Trees several months later after the majors showed no interest, and they were impressed that the production from the initial well had held up so well. MALLISON, supra note 28, at 322; see also CLEMENS, supra note 28, at 137.

Id. at 154.

The Abrams #1 well, drilled on the Eastern Shelf of the Midland Basin, was shot with nitroglycerin in 1920, (well discussed above) 79

See generally Kelly v. Ohio Oil Co., 49 N.E. 399 (Ohio Sup. Ct. 1897)

It was agreed that Benedum and Trees would be required to drill these wells only if they cost less than $50,000 each. MALLISON, supra note 28, at 333.

BRADLEY, supra note 14, at 257.

WILLIAMSON, supra note 23, at 29.

BRADLEY, supra note 14, at 1122.

WILLIAMSON, supra note 23, at 29.

CLARK & HALBOUTY, supra note 13, at 281.

See generally KENNY A. FRANKS, THE RUSH BEGINS: A HISTORY OF THE RED FORK, CLEVELAND AND GLENN POOL OIL FIELDS (1984).

MALLISON, supra note 28, at 334.

See COX, supra note 31, at 41–49; see also MALLISON, supra note 28, at 334. 68

MALLISON, supra note 28, at 340.

Id. at 342.

Id.

WILLIAMSON, supra note 23, at 29. This problem still occurs from time to time, and drilling contractors are very careful with regard to the composition of their drilling muds and fluids. Fluid intrusion into the formation is referred to by engineers and geologists as ‘skin’ damage.

Id. at 309. The oil zone was encountered much shallower than expected at around 1,000 feet, which allowed for subsequent wells to be drilled by a mobile cable tool drilling rig. The well was productive from the Big Lime formation, today known as the San Andres formation, a formation that is still productively encountered in new wells.

Id.

U.S. GEOLOGICAL SURVEY, supra note 12.

The wells were so prolific that the developer had to install storage and the site and later a pipeline was built to move the oil to market. The Yates field, like the Santa Rita field, was developed by Mike Benedum and Joseph Trees. MALLISON, supra note 28, at 311.

As the laterals get longer engineers note that more horsepower is required for drilling, and in general laterals are 27% longer today than they were three years ago. Impact of Downturn on Shale Development: Permian Success Story, RYSTAD ENERGY (June 20, 2017), http://www.rystadenergy.com/newsevents/news/pressreleases/2017-annual-oil-recoverable-resource-review [hereinafter Rystad Energy Press Release].

In the end Benedum and Trees were later recognized as the discoverers of one of the richest oilfields in American

The formations are named the Wolfcamp A, B, C and D, and some of these zones have been subdivided. U.S. GEOLOGICAL SURVEY, supra note 12. 91

The porosity is roughly 4% to 12%, with little permeability. See generally Peter Blomquist, Wolfcamp Horizontal Play, Midland Basin, West Texas (2016). 92

Rystad Energy Press Release, supra note 89.

These include the Avalon, Bone Spring (1, 2 and 3), plus the Wolfcamp series. Blomquist, supra note 91. 94

Ed Brooks, US Prospectors Feast on a Shale Oil ‘Layer Cake’, FINANCIAL TIMES, Nov. 2016, at 17. 95

Dan Steffens, Chief Executive Officer, Energy Prospectus Group Luncheon, Dallas, Texas (May 2017). 96

Id.

Rystad Energy Press Release, supra note 89.

See id.

prior to drilling a well3, clearly the minority rule in American oil and gas law, distinguished West Virginia from other oil and gas-producing states by greatly limiting the options for exploration and production companies in the absence of unanimous consent among the co-tenants.

The BIG XII: 12 Recent Appalachian Basin Legal Developments By: Andrew Graham1

In the face of hold-out co-tenants, many operators could develop wells only after the completion of a partition action that either (1) divided the tract into one owned by those who favored development and another owned by those who opposed it or (2) forced a sale or allotment of the oil and gas estate. Given the fact that split estates have existed in many parts of West Virginia since the late 19th century, oftentimes vested in complicated heirships, this change is accurately described as a “Modernization” Act.

INTRODUCTION This summary discusses 12 recent developments for oil and gas law in the Appalachian Basin, specifically developments in West Virginia, Ohio, and Pennsylvania. For your convenience, case citations have been added in footnotes to assist any future research. Please note that these materials are public information and have been prepared solely for educational purposes. These materials reflect only the personal views of the author and are not individualized legal advice. It is understood that each case and/or matter is fact-specific, and that the appropriate solution in any case and/or matter will vary. Therefore, these materials may or may not be relevant to any particular situation.

The new law took effect on June 3, 2018, and it established a mechanism by which a parcel can be developed absent the consent from all of the coowners.4 But, the law does not completely repeal the unanimous consent rule.5 It only applies in situations where seven or more cotenants exist and at least seventy-five percent of the ownership has consented to development.6 Once the thresholds are met, a non-consenting co-tenant must choose to either (1) receive a pro rata share of the royalty (free from post-production deductions) at the highest rate to be received by a consenting cotenant or (2) participate in the development of the tract.7 Unknown or missing cotenants are deemed to have elected the first option.8

Thus, the author and Steptoe & Johnson PLLC cannot be bound either philosophically or as representatives of their various present and future clients to the comments expressed in these materials. The presentation of these materials does not establish any form of attorney-client relationship with the author or Steptoe & Johnson PLLC. While every attempt was made to ensure that these materials are accurate, errors or omissions may be contained therein, for which any liability is disclaimed.

2. NPRO Consent to Pooling In Gastar Exploration, Inc. v. Contraguerro, the West Virginia Supreme Court of Appeals held that an oil and gas lease that covers a tract of land in which there is a nonparticipating royalty interest can be validly pooled without the consent or ratification of the owner of the nonparticipating royalty interest.9 The court also reaffirmed that West Virginia follows the contract theory of pooling and does not follow the cross-conveyance theory of pooling.10

WEST VIRGINIA 1. Cotenancy Legislation House Bill 4268, called the Co-Tenancy Modernization and Majority Protection Act, eased the West Virginia rule that had characterized oil and gas production as waste under W. VA. CODE § 37-7-2 unless all of the co-tenants had consented to its development.2

In Gastar, an executive right for the oil and gas estate was ultimately acquired by PPG Industries, Inc. (“PPG”) and, in 2011, PPG granted an oil and gas lease to Gastar Exploration USA, Inc. (“Gastar”), which covered multiple tracts in

The previous law, which required unanimous consent from all oil and gas co-tenants in a tract 17

Marshall County, including a 105.9 acre tract.11 In 2012, Gastar then pooled 700 acres from the PPG lease, including the 105.9 acres, with other oil and gas interests to create the Wayne/Lily Unit.12 Although Gastar did not obtain consent from any nonparticipating royalty owners prior to creating the Wayne/Lily Unit, it did seek ratification of the unit, but the nonparticipating royalty owners in the 105.9 acres refused to ratify the unit.13

District of West Virginia held that an oil and gas lease that did not contain a traditional pooling clause, but that (1) granted the lessee the right to operate the leased premises alone and conjointly with other lands for the production and transportation of oil and gas, and (2) also contained a secondary term that permitted the lessee to hold the lease so long as the leased premises were operated in search for or in production of oil or gas as long as such land is utilized by the lessee alone or conjointly with neighboring lands, expressly granted the lessees the right to pool.21

The royalties due to the nonparticipating royalty owners were placed into escrow and, in 2014, the nonparticipating royalty owners filed a declaratory judgment action against Gastar and PPG in the Circuit Court of Marshall County, asking the court to determine what royalties were payable to them from Gastar’s operations and alleging that PPG should not have given Gastar the right to pool the 105.9 acres with other tracts without first obtaining their consent.14

The mineral owners filed suit against the oil and gas lessee alleging that pooling was not permitted under their oil and gas lease because the lease did not contain a pooling clause and they had refused to execute pooling modifications sought by the lessee.22 In spite of the absence of traditional pooling language in the lease, the lessee filed a pooling declaration that included parts of the mineral owners’ property in the unit.23 After filing the pooling declaration, the lessee drilled a well and began producing natural gas.24

In 2016, the circuit court granted partial summary judgment to the nonparticipating royalty owners and held that the pooling provision in the PPG lease and the resulting Wayne/Lily Unit were void until such time as the nonparticipating royalty owners consented to the pooling.15 In reaching its decision, the court had relied upon Texas law that pooling creates a cross-conveyance of royalty interests and that the nonparticipating royalty owners’ interest could not be conveyed to the other parties in the Wayne/Lily Unit without their consent.16 PPG and Gastar appealed.17

Subsequently, the lessee assigned its interest to a successor lessee, who filed an amended pooling declaration that excluded the mineral owners’ property from the unit.25 The lessee and successor lessee filed motions to dismiss the mineral owners’ complaint because the oil and gas leases permitted the lessee to pool or unitize the mineral owners’ interest, even though the leases did not contain express pooling clauses.26 In granting the motions to dismiss, the court focused on the express language of the granting clause and the secondary term.27

The court reversed and held that West Virginia does not follow the Texas cases that pooling creates a cross-conveyance of royalty interests.18 Rather, the Court recognized that earlier West Virginia cases had already determined that pooling consolidates the contractual and financial interests regarding production for the pooled tracts, but does not create joint ownership in the oil and gas.19 In rejecting the cross-conveyance theory, the court noted that its adoption at this point in time would create uncertainty in West Virginia’s oil and gas jurisprudence, and would effectively give executive rights back to nonparticipating royalty owners.20

The granting clause conveyed all other rights and privileges necessary, incident to, or convenient for the operation of the mineral owners’ property, alone and conjointly with other lands for the production and transportation of oil and gas, and for the injection, storage and withdrawal of gas.28 Further, the secondary term provided that the lease would be held so long as the mineral owners’ property or any portion thereof is operated by the defendants, in search for or in production of oil or gas as long as such land is utilized by the defendants alone or conjointly with neighboring

3. Pooling Authority In Stern v. Columbia Gas Transmission, LLC, the United States District Court for the Northern 18

lands for either the storage of gas by injection, storage and removal of gas through well or wells operated on either the mineral owners’ property or other adjoining or neighboring lands comprising a part of the same gas storage field, or for the protection of any gas stored in such storage field.29

the statute and a 1/8 royalty on those drilled after enactment.37 The mineral owners sued the oil and gas operator in the Circuit Court of Doddridge County, alleging that the company had underpaid royalty for production from the post-statute wells because the company had taken deductions for post-production costs as part of calculating the mineral owners’ royalty.38 After removal to the United States District Court for the Northern District of West Virginia, the federal court certified the following two questions to the West Virginia Supreme Court of Appeals:

The court determined that such language contemplated pooling or unitization because work within the unit that includes the mineral owners’ property would extend the lease even though the lease did expressly provide for pooling.30 Further, the repeated use of alone and conjointly with other land convinced the court that the parties intended to grant pooling rights to the lessee.31

1. Does Tawney v. Columbia Natural Resources, L.L.C., 219 W.Va. 266, 633 S.E.2d 22 (2006), which was decided after the enactment of West Virginia Code § 226-8, have any effect upon the Court’s decision as to whether a lessee of a flat-rate lease, converted pursuant to West Virginia Code § 22-6-8, may deduct postproduction expenses from his lessor’s royalty, particularly with respect to the language of “1/8 at the wellhead” found in West Virginia Code § 22-6-8(e)?39

The court rejected the mineral owners’ argument that pooling was incompatible with the lease because the lease contained no provision for the apportionment of royalties, and held that the mineral owners’ royalty would be the same under the lease as it would be under a community lease, which would entitle the mineral owners to a royalty in the proportion that their tract of land bears to the unit acreage.32 The court also refused to consider the lessee’s attempts to modify the leases to add pooling as evidence that the leases did not provide for pooling.33

2. Does West Virginia Code § 22-6-8 prohibit flat-rate royalties only for wells drilled or reworked after the statute’s enactment and modify only royalties paid on a per-well basis where permits for new wells or to modify existing wells are sought, or do the provisions of West Virginia Code § 22-6-8 abrogate flat-rate leases in their entirety?40

4. Post-Production Deductions In Leggett v. EQT Production Co., the West Virginia Supreme Court of Appeals held that a flat-rate royalty statute requiring the payment of a 1/8 royalty “at the wellhead” for new or reworked wells on flat-rate royalty leases permitted the use of the net-back method of calculating royalty, which would allow for deduction of postproduction costs, in spite of a 2006 decision that otherwise prohibited this method of calculation for leases requiring a 1/8 royalty “at the wellhead.”34 The Court had previously held that the statute did not allow for net-back calculation of royalty, but after granting a rehearing, and the seating of a new justice because of an intervening judicial election, the Court reached the opposite conclusion.35

At first, the Court, in a 3-2 decision in November 2016, answered the district court’s first certified question in the affirmative and held that, in light of Tawney, the flat-rate statute required that the mineral owner must receive a 1/8 royalty that has not been “diluted by costs and losses incurred downstream from the wellhead before a marketable product is rendered.”41 The Court declined to answer the second certified question.42 After granting the oil and gas company’s motion to reconsider, the Court held, in a 4-1 decision in May 2017, that royalty payments under the flat-rate statute “may be subject to pro-rata deduction or allocation of all reasonable postproduction expenses actually incurred by the

Nine wells had been drilled on the leased premises, some before enactment of the flat-rate statute and some after.36 The oil and gas company paid a flat rate royalty on the wells drilled prior to 19

lessee.”43 It reformulated the certified questions into the following two questions:

OHIO 5. Ohio Dormant Mineral Act

(1) Are royalty payments pursuant to an oil or gas lease governed by West Virginia Code § 22-6-8(e) (1994) subject to pro-rata deduction or allocation of postproduction expenses by the lessee?44

Following the enactment of the 2006 version of the Ohio Dormant Mineral Act (“ODMA”), there was confusion in the courts about whether the 2006 version would apply retroactively to previously abandoned mineral rights, or prospectively to rights claimed following the date of its enactment.

(2) May an oil or gas lessee utilize the “netback” or “workback” method to calculate royalties owed to a lessor pursuant to a lease governed by West Virginia Code § 22-6-8?45

The Supreme Court of Ohio answered this question in Corban v. Chesapeake Exploration, L.L.C. when it held, in part, that the 2006 version of the ODMA (1) “applies to claims asserted after its effective date[;] and [(2)] specifies the [required] procedure” for having “dormant mineral rights deemed abandoned and merged with the surface estate.”54

The Court answered both reformulated questions in the affirmative.46 As a result, the lessee may use the net-back method to calculate royalties owed under the flat-rate statute.47 In reaching this conclusion, the new majority concluded that the use of “at the wellhead” in the flat-rate statute clearly expressed a legislative intent to value the royalties paid pursuant to the statute based on the unprocessed wellhead price.48

The Court stated that the 2006 version of the ODMA “is not expressly retrospective, and it applies prospectively to all claims that mineral rights have been abandoned that are asserted after its effective date.”55 In practice, this ruling means that a practitioner need only check to see if there was a judicial ruling prior to the 2006 amendment, and, if not, then the 2006 procedures would apply.

Both the Court’s majority opinion and a concurring opinion asked the West Virginia Legislature to enact additional provisions regarding post-production deductions.49 The mineral owners appealed the Court’s decision to the United States Supreme Court, but certiorari was denied.50

Overall, the Court held that the 2006 ODMA applies to all claims asserted after June 30, 2006, even if the mineral rights were abandoned prior to the amendment.56

In the aftermath of Leggett, Senate Bill 360 clarified the legislature’s intent pertaining to W. VA. CODE § 22-6-8 and abrogated the Leggett decision.51 The legislature answered the charge set forth by West Virginia Supreme Court to enact specific provisions to assure fairness and reasonableness in the calculation of postproduction costs.

Thereafter, the Court either affirmed or reversed several cases which were stayed pending the outcome of Corban. Additionally, the Court held that the 1989 version of the ODMA was not self-executing and did not automatically transfer ownership of dormant mineral rights by operation of law.57

As amended, the flat-rate royalty statute now more clearly states that, where wells are drilled pursuant to flat-rate royalty leases, mineral owners shall be paid a royalty of no less than one-eighth “of the gross proceeds, free from any postproduction expenses.”52 The changes in royalty calculation took effect on May 31, 2018; however, the changes may only be temporary due to a lawsuit filed to challenge the constitutionality of the recent amendment.53

Rather, the surface holder of the land in question was required to bring a quiet title action “seeking a decree that the mineral rights had been abandoned in order to merge those rights into the surface estate.”58 Similarly, the Court held that the 2006 version also does not self-execute, but instead lists the procedural method required in order to establish the surface owner’s marketable record title in the mineral estate.59 20

Overall, the Court specifically requires that the landowner would have commenced a quiet title action in order to obtain abandoned minerals under the 1989 version of the ODMA.60 The quiet title action had to be filed before the ODMA was amended on June 30, 2006.61 If there was not a quiet title action prior to 2006, this holding requires that the surface owner follows the procedure outlined in the 2006 version of the ODMA in order to assert a claim.62

The Court noted that the word “shall” means that the notice and affidavit obligations are mandatory, further exemplifying the fact that the 2006 ODMA provides procedural requirements.69 6. Landman Licensing In Dundics v. Eric Petroleum Corp., the Seventh District Court of Appeals upheld a Mahoning County ruling that landmen must be licensed real estate brokers to receive compensation for negotiating oil and gas leases.70 The opinion relies heavily upon the interpretation of OHIO REV. CODE ANN. § 4735.21, which states in relevant part: “No right of action shall accrue to any person, partnership, association, or corporation for the collection of compensation for the performance of the acts mentioned in section 4735.01 of the Revised Code, without alleging and proving that such person, partnership, association, or corporation was licensed as a real estate broker or foreign real estate dealer.”71

The Court also answered whether the payment of a delay rental is a “title transaction” or “savings event” for purposes of the ODMA.63 The Court answered this question in the negative and held that the payment of delay rental is not a saving event under either the 1989 or the 2006 versions of the ODMA because the payment is not “filed or recorded in the office of the county recorder of the county in which the lands are located,”64 as required under OHIO REV. CODE ANN. § 317.08 or § 5301.47.

This statute further defines “real estate broker” as one who engages in certain specified conduct for compensation, such as one who “sells, exchanges, purchases, rents, or leases, or negotiates the sale, exchange, purchase, rental or leasing of any real estate …”72 Therefore, the court’s decision focused on whether oil and gas rights are considered “real estate.”73

Moreover, the Court noted that a title transaction is a transaction that affects title to any interest in land, which cannot be said for a delay rental payment.65 Because a delay rental payment (1) does not affect title to any interest in land, (2) occurs outside of the chain of title, and (3) is not filed or recorded in the office of the county recorder, it is neither a title transaction nor a saving event.66

The court relied in large part on Ohio precedent to reach the conclusion that an oil and gas lease affects the surface estate, and thus an oil and gas lease pertains to real estate.74 Therefore, the real-estate-broker rule applies to landmen who are compensated to negotiate oil and gas leases.75 On November 1, 2017, the Supreme Court of Ohio granted an appeal and agreed to review the case.

Since the decision in Corban, the Court has reiterated its holding. For example, in Walker v. Shondrick-Nau, the Court stated that “the 2006 version of the Dormant Mineral Act applies to all claims asserted after 2006 alleging that the rights to oil, gas, and other minerals automatically vested in the owner of the surface estate prior to the 2006 amendments.”67

7. Paying Quantities Analysis In Hogue v. Whitacre, the Seventh District Court of Appeals affirmed a decision which held that indirect operating expenses should not be considered when determining paying quantities under a habendum clause of an oil and gas lease.76 For Ohio, this was a case of first impression. Lessors signed an oil and gas lease in 2006 and, later that year, a well was drilled and oil and gas production started.77 Although the well had

Similarly, in Albanese v. Batman, the Court expanded upon the holding in Corban and stated that under the 2006 ODMA, in order for a severed mineral interest to be deemed abandoned and vested in the surface owner (1) the mineral interest cannot be in coal, (2) the mineral interest cannot be held by certain entities, (3) no savings event can have occurred during the relevant period, and (4) the surface owner “shall” have served notice and filed the required affidavit.68 21

produced every year since production began, the quantities and profits were very low.78

ambiguous because it did not specifically state how to treat deductions.90 Conversely, the court noted that the “at the well” rule would apply clear and unambiguous meaning to the language in leases.91

Eventually, the lessors filed a complaint against the operator seeking a declaration that the lease had been terminated due to the lack of production in paying quantities.79 The trial court granted summary judgment in favor of the operator.80

Although the court did not expressly adopt the “at the well” rule, it held that the operator did not breach the leases when it deducted post-production costs in calculating the royalty payments because the language contained within the leases permitted it to do so.92

The lessors had alleged that the operator misrepresented its expenses from operating the well by excluding overhead costs for its business, such as office payroll, office lease, software, postage, professional services, building utilities, fire resistant clothing, vehicles, and machinery, when calculating the profitability of the well.81 Had the operator had these expenses in its calculating of operating costs, then the well would not have been producing in paying quantities.82

PENNSYLVANIA 9. Rule of Capture In Briggs v. Southwestern Energy Prod. Co., the oil and gas lessee drilled horizontal wells in such a manner that did not enter a neighboring mineral tract, but the neighboring unleased mineral owners nonetheless filed suit alleging claims of trespass and conversion based on the theory that the horizontal wells had unlawfully extracted natural gas from their land, even though the wells had been drilled on lands leased by the oil and gas lessee.93

Since the case as a matter of first impression in Ohio, the court looked to Louisiana and Oklahoma where courts have held that administrative overhead should be excluded when determining the costs of producing a well.83 The court held that the operator correctly excluded overhead and other indirect costs from its calculation of whether the well was producing in paying quantities.84 On May 23, 2018, the Supreme Court of Ohio decided that it would not allow an appeal of this case.85

After some discovery, the lessee filed a motion for summary judgment on the grounds that the rule of capture precluded the neighboring mineral owners’ claims.94 The neighboring mineral owners moved to stay the resolution of the lessee’s summary judgment motion because the lessee had not answered certain interrogatories to the neighboring mineral owners’ satisfaction.95 The neighboring mineral owners also filed their own motion for partial summary judgment on the issue of liability.96

8. Post-Production Deductions In Lutz v. Chesapeake Appalachia, LLC, a group of lessors brought a putative class action suit against an operator for the alleged underpayment of royalties.86 The district court certified the question to the Supreme Court of Ohio as to which rule should be followed—the “at the well” rule or the “marketable product” rule.87

The trial court granted the lessee’s motion for summary judgment and denied the neighboring mineral owners’ motions.97 Following appeal by the neighboring mineral owners, the Superior Court of Pennsylvania reversed the trial court’s judgment and held that “the rule of capture does not preclude liability for trespass due to hydraulic fracturing.”98

The Supreme Court held that oil and gas leases are contracts and the remedies are controlled by the individual lease terms, unless the language proved to be ambiguous.88 If ambiguity exists, like other contract causes of actions, extrinsic evidence could be used to determine the intent of the parties.89

In this case of first impression, the Court discussed distinguished hydraulic fracturing and horizontal drilling from conventional methods of oil and gas extraction.99 The rule of capture

However, the district court rejected the lessors’ argument that the “at the well” language was 22

assumes that oil and gas originate in subsurface reservoirs or pools, and can migrate freely within the reservoir and across property lines, according to changes in pressure.100 Natural gas, when trapped in a shale formation, is non-migratory in nature and will not escape to adjoining lands absent the application of an external force, such as hydraulic fracturing, in which case the natural gas contained in the shale can move freely through the channels in the shale created by the hydraulic fracturing.101

led the jury to believe would be presented to them at the outset of this trial.108 Further, although the evidence offered in support of the plaintiffs' sole remaining claims was limited, often substantially rebutted or discredited, and notably lacking with respect to damages, the jury found in the plaintiffs' favor and awarded them $4.24 million.109 However, the district court vacated the jury’s verdict because of the weaknesses in the plaintiffs’ case and proof along with irregularities in the testimony and presentation of the plaintiffs’ case.110 These combined to undermine the court’s faith in the jury’s verdict.111

The Court held that applying the rule of capture to instances of horizontal drilling would effectively allow a mineral lessee to expand its lease by locating a well near the boundary line of the oil and gas lease and then withdrawing natural gas from the adjoining property for which it does not have a lease.102

Moreover, the jury’s award of more than $4 million in damages for private nuisance bore no discernible relationship to the evidence, which was at best limited.112 Even had the district court found that the jury’s verdict of liability should stand, it held that it could not perceive a way in which the jury’s damages award could withstand even passing scrutiny regardless of the applicable standard of review.113

While the rule of capture typically leaves aggrieved mineral owners with the option to drill an offsetting well to protect themselves from drainage, the Court was not satisfied that this traditional remedy was appropriate to circumstances involving horizontal drilling and hydraulic fracturing because of the costs involved in drilling a horizontal well and the expertise needed to successfully drill such a well.103

On April 26, 2017, the operator’s supersedeas bond was released by the court.114 11. Oil & Gas Regulations Most recently, on July 3, 2018, the United States Court of Appeals for the Third Circuit held in Wayne Land & Mineral Group LLC v. Delaware River Basin Comm’n that the owner of property in the Delaware River basin faced real and substantial threat of harm due to the Commission’s ban on most natural gas hydraulic fracturing projects located within the drainage area of Special Protection Waters.115 The Court also held that the owner had standing to bring a claim, the claim was ripe for adjudication, the final agency action and exhaustion of administrative remedies were not implicated by the owner’s complaint, and the compact was ambiguous as to whether hydraulic fracturing-related activities constituted a project, and thus survived the motion to dismiss.116

The Court denied the lessee’s motion for rehearing on June 8, 2018, but on July 9, 2018, the lessee appealed the case to the Pennsylvania Supreme Court.104 10. Water Damage In Ely v. Cabot Oil & Gas Corp., multiple plaintiffs originally sued an operator for alleged injuries and property damage in Dimock Township, Susquehanna County, Pennsylvania.105 On March 10, 2016, following a trial that capped more than six years of litigation, a jury found in favor of the plaintiffs on claims that an operator’s drilling activity was negligent which caused the plaintiffs' compensable nuisance injuries by interfering with and damaging the plaintiffs' access to water and their enjoyment of their property.106

In 1961, four states (Pennsylvania, Delaware, New Jersey, and New York) entered into the Delaware River Basin Compact, which created the Commission to protect water quality and quantity within the basin states.117 The Commission was granted broad powers, including the power to

This claim, which was the sole claim submitted to the jury, differed significantly from the claims described in the original complaint.107 It also varied materially from the claims that the plaintiffs 23

regulate hydraulic fracturing-related activities.118 In 2009, the Commission passed a moratorium that banned most hydraulic fracturing projects within the drainage area of Special Protection Waters unless there was prior approval from the Commission.119

the royalty due to the lessor in Slamon v. Carrizo (Marcellus) LLC.129 Slamon brought a class action against multiple operators, alleging the royalties paid to him and others similarly situated under their oil and gas leases were improperly calculated.130 Slamon alleged that the operators had breached the leases by deducting fees and post-production costs incurred from the sale of gas to a third party from the royalty paid to him.131 Though the district court had not yet certified the class, motions to dismiss were filed by the operators.132 Finding that Slamon adequately pleaded a cause of action for breach of contract, the court denied the operators’ motion to dismiss.133

A Pennsylvania-based oil and gas operator with land within the basin wanted to drill an exploratory well but, due to the moratorium, it would not have been able to extract gas for sale without approval from the Commission.120 Subsequently, the operator filed a complaint in federal district court that alleged that the Commission lacked the authority under the compact to renew and approve gas-related activities on its property.121

The relevant provision in the lease stated that the “Lessee shall pay Lessor the following royalty, free of all costs, whether pre-production or postproduction…”134 The term “post-production costs” was not defined in the lease.135

More specifically, the operator sought a declaratory judgment that hydraulic fracturing did not constitute a project.122 The district court denied the Commission’s motion to dismiss and concluded that the claim was ripe because it sought declaratory judgment, and without relief, the operator could face a series of fines for noncompliance; however, the court decided sua sponte to dismiss the complaint for failure to state a claim since the project plainly and unambiguously included proposed hydraulic fracturing.123 The operator appealed.124

The operators agreed with Slamon that the royalty provision did not allow them to deduct post-production costs.136 The operators argued, however, that the complaint did not allege that the operators deducted post-production costs from Slamon’s royalties.137 Instead, they note that the complaint alleged that a third party buying the gas deducted its costs after the operators had already sold the gas to the third party.138 As such, the operators argued that the costs incurred by the third party who purchased the gas did not fall within the definition of the term “post-production costs” because the term was not defined in the lease.139 The court found that the term was not limited to only those production expenses incurred directly by the operators.140

On appeal, the Third Circuit reaffirmed the district court’s finding on ripeness, standing, and exhaustion of administrative remedies.125 But, the Court vacated the order dismissing the operator’s complaint for failing to state a claim because it found the compact’s language to be ambiguous.126 More specifically, not only did the district court’s reading not solve the ambiguity, but other provisions within the compact further exacerbated the ambiguity as to whether hydraulic fracturingrelated activities constituted a project subject to the Commission’s review.127 The Court remanded the case to the district court for additional factfinding.128

The court stated that Slamon pleaded that, because post-production costs were built into the sale price that the operators received from the third party, and because of Slamon’s royalties were calculated from that sale price, his royalties were improperly reduced by post-production costs.141

12. Post-Production Deductions

The court concluded that because the lease does not clearly limit post-production costs to only those production expenses incurred directly by the operators—as opposed to those incurred directly to third parties and passed onto the operators—

The United States District Court for the Middle District of Pennsylvania considered the propriety of deducting certain post-production costs from 24

Slamon had adequately pleaded a cause of action for breach of contract.142

Id.

Id. at 854.

Id.

Leggett v. EQT Prod. Co., 800 S.E.2d 850, 853 (W. Va. 2017).

Andrew Graham practices oil and gas law with Steptoe & Johnson PLLC in Morgantown, West Virginia. He is also as an adjunct assistant professor of energy land management at West Virginia University. He would like to thank Tony Faini, who is a rising 3L law student at West Virginia University College of Law, and recently a law clerk in S&J’s Morgantown office, for his assistance in preparing this paper and the accompanying PowerPoint slides.

Leggett v. EQT Prod. Co., No. 16-0136, 2016 W. Va. LEXIS 890, at *18 (W. Va. Nov. 17, 2016).

W. VA. CODE § 37B-1-1 et seq. (West 2018).

W. VA. CODE § 37-7-2 (West 2018).

W. VA. CODE § 37B-1-1 et seq. (West 2018).

See W. VA. CODE § 37B-1-4 (West 2018).

Id.

Id. at 867.

Id. § 37B-1-4(b)(1)–(2).

Id.

Id. §37B-1-4(d).

Id.

Id. at 868.

Id. at 866. Id. at 869, 871.

7 8

Id. at *23.

Leggett v. EQT Prod. Co., 800 S.E.2d 850, 868 (W. Va. 2017).

Gastar Expl., Inc. v. Contraguerro, 800 S.E.2d 891, 900– 01 (W. Va. 2017). 10

Id.

Id. at 895.

Id.

Id. at 896.

W. VA. CODE § 22-6-8(e) (West 2018).

Id.

Id. at 896.

Id.

Id. at 894.

See EQT Prod Co. v. Caperton, Civil Action No. 1:18-cv72 (N.D.W. Va. Apr. 12, 2018) (suit alleges flat-rate royalty statute violates Contracts Clause and the Due Process Clause of the XIV Amendment of the U.S. Constitution).

Id. at 900–01.

Id.

Id. at 900.

Leggett v. EQT Prod. Co., 800 S.E.2d 850 (W. Va. 2017), cert. denied, 138 S. Ct. 472 (2017).

Corban v. Chesapeake Expl., L.L.C., 149 Ohio St. 3d 512, 2016-Ohio-5796, 76 N.E.3d 1089, ¶ 41.

Stern v. Columbia Gas Transmission, LLC, No. 5:15CV98, 2016 WL 7053702, at *1–*2 (N.D.W. Va. Dec. 5, 2016) (mem. op.).

Id. ¶ 33.

Id. ¶ 31.

Id. ¶ 26.

Id. ¶ 40.

Id. at *1.

Id.

Id. ¶ 41.

Id.

Id. ¶ 28.

Id.

Id. ¶ 40.

Id. at *1.

Id. ¶ 41.

Id. at *2–*3.

Id. ¶ 36.

Id. at *2.

Id. ¶ 38.

Id. at *3.

Id.

Id. ¶ 39.

Id.

Walker v. Shondrick-Nau, 149 Ohio St. 3d 282, 2016Ohio-579374, N.E.3d 427, ¶ 16.

Albanese v. Batman, 148 Ohio St. 3d 85, 2016-Ohio5814, 68 N.E.3d 800, ¶ 20.

105

106

Id.

107

Id.

108

Id.

Ely v. Cabot Oil & Gas Corp., No. 3:09-CV-2284, 2017 WL 1196510, at *2 (M.D. Pa. Mar. 31, 2017).

Id. ¶ 20.

Dundics v. Eric Petroleum Corp., 2017-Ohio-640, 79 N.E.3d 569, ¶ 20 (7th Dist.). 71

OHIO REV. CODE ANN. § 4735.21 (West 2019).

109

Id. at *3.

Id. § 4735.01 (West 2019).

110

Id. at *14–15.

Dundics, 2017-Ohio-640, 79 N.E.3d, ¶ 23.

111

Id. at *10.

Id.

112

Id. at *5.

Id. ¶ 26–27.

113

Id.

114

Id. at *5–6.

Hogue v. Whitacre, 2017-Ohio-9377, 103 N.E.3d 314, ¶ 26.

115

Wayne Land & Mineral Grp. LLC v. Delaware River Basin Comm'n, 894 F.3d 509, 523 (3d Cir. 2018).

Id. ¶ 2.

Id. ¶ 5.

116

Id. at 520–21.

Id. ¶ 6.

117

Id. at 515.

Id.

118

Id.

Id. ¶ 17.

119

Id. 517–18.

Id. ¶ 22.

120

Id. at 517.

Id. ¶ 28.

121

Id. at 519.

Id. ¶ 31.

122

Id.

Hogue v. Whitacre, 2018-Ohio-1990, 98 N.E.3d 294.

123

Id. at 521.

124

Id.

125

Id. at 522–23.

Id. at *4.

126

Id. at 521.

Id. at *16.

127

Id. at 527.

Id. at *16–17.

128

Id. at 522.

Id. at *17.

129

Id. at *18.

Id. at *20.

Lutz v. Chesapeake Appalachia, LLC, No. 4:09-CV2256, 2017 WL 4810703, at *2–3 (N.D. Ohio Oct. 25, 2017). 87 88

Slamon v. Carrizo (Marcellus) LLC, No. 3:16-CV-2187, 2017 WL 3877856, at *15 (M.D. Pa. Sept. 5, 2017). 130

Id. at *1.

131

Id. at *15.

132

Id. at *2.

Id. at 155.

133

Id. at *18.

Id.

134

Id. at *3.

Id.

135

Id. at *16.

Id.

136

Id. at *15.

Id. at 164.

137

Id. at *6.

Id. at 162.

138

Id.

139

Id.

140

Id.

Id. at 163.

141

Id.

142

Id. at *6–7.

Briggs v. Sw Energy Prod. Co., 184 A.3d 153, 154 (Pa. Super Ct. 2018). 94 95 96 97

100 101 102 103

104

Briggs v. Sw. Energy Prod. Co., 197 A.3d 1168 (Pa. 2018)

need for capital as a response to the upswing in prices leading into 2008. “As a result [of high commodity prices], there was a much deeper and broader pool of capital available to … E&P companies than historically had been the case. From commercial debt and public-market capital to private-equity funds, the array of capital choices and dollars grew to an all-time high heading into 2008.” 5 However, the global recession that was in part triggered by the housing market crisis pushed the oil & gas industry roller coaster on a downward slope as commodity prices began to drop to concerning levels. “The toxic nature of poorly underwritten home-mortgage loans infected the U.S. and international financial markets.” 6 For all intents and purposes the entire world’s capital markets halted lending and, just like essentially all businesses of every industry, E&P companies’ borrowing capabilities and access to capital were drastically affected.7

The Influx of Private Equity into the Oil & Gas Industry By: Matthew Gibson Recent STCLH Graduate Attorney with Kirkland & Ellis LLP

I NDUSTRY B ACKGROUND : R OLLER C OASTERS C AN O PEN D OORS The Oil & Gas industry is cyclical in nature1 and even the United States domestically is influenced by many worldwide factors affecting commodity prices. This cyclical industry has been a roller coaster from inception to present day; creating problems, forcing solutions, and ultimately many booms and busts depending on your position regarding the industry. Leading into the 2008 housing market and financial crisis, oil prices came up from around $50 in 2007 to almost $150 deep into 2008. A product of this upslope in the oil & gas industry’s roller coaster was the fact that reserve-based lending (RBL) was cemented as a desirable option by energy lenders based on a perceived very lowrisk profile.2 For most Exploration and Production (E&P) companies, acquiring capital for obtaining leases for access to petroleum reserves (assets) and funding development/drilling programs was done through capital markets and the mechanism of RBLs.

With oil prices tanking and general publicequity-market investors’ fear of how much the stock market would eventually decline, accessing public markets for capital was too expensive for E&P companies. [Capital expenditure] budgets and acquisitions were cut back. The era of easy credit for the oil patch had ended just as it did for would-be homebuyers.8 This resulted in some shaky tracks for the oil & gas roller coaster, but thankfully some relief came in late 2009 as some lending sources opened back up in part due to the ‘Shale Revolution.’ Also, because of the 2008 financial crisis, Dodd-Frank was passed which began to fuel Private Equity investment into the oil & gas industry.

“A publicly traded E&P company could acquire acreage by accessing the debt or equity markets for acquisitions but would need additional capital to drill and operate using its RBL or other [debt] facility.3 RBLs work on essentially a value based or merit system. “The defining feature of the RBL is that the size of the facility is determined by reference to the current value of the borrower’s oil and gas reserves rather than the strength of its balance sheet.” 4 Therefore, if an E&P expended most of its capital in acquiring valuable leases, it could then acquire funding for its drilling program through RBLs based on the value of those leases.

Fast-forwarding to 2014, RBLs and traditional forms of lending came back online in a fury as industry optimism and commodity prices continued to rise coming off the 2008 crisis downturn. Extremely favorable terms were handed out to E&Ps from the debt markets as lenders were essentially fighting over the yield from the oil & gas industry. The industry’s production, thanks in part to the shale revolution, in million barrels per day were at 40-50-year highs. Production, and the

Banks and other lenders and investors increased lending and investing to the energy sector with confidence to accommodate E&P’s 27

excess storage of which, was amounting to levels that had OPEC taking serious note as the industry was being affected worldwide – setting up a major downslope in the oil and gas roller coaster.9

longer duration of low commodity prices than most had expected.

“From the beginning of this down-slope in 2015 through the end of 2018, one-hundred and sixtysix (166) E&Ps have filed for bankruptcy.”

While American producers sat down for Thanksgiving dinner in November of 2014, OPEC members announced that they would not decrease their output that would have stemmed declining world oil prices. Sometime between the stuffed turkey and the pumpkin pie, the price of oil dropped more than 10%. And, as world markets digested the news, WTI fell from more than $73 per barrel prior to Thanksgiving to $53 as the New Year began.10

The effect of this reality has been tough on the industry and its players. “As oil prices continue to remain low following the precipitous price decline in late 2014, many oil and gas exploration and production companies have faced significant distress as revenues have been slashed and hedges have expired.” 14 The complex structure of the additionally acquired debt of E&Ps, combined with the low commodity prices, caused a massive wave of bankruptcies. From the beginning of this down-slope in 2015 through the end of 2018, onehundred and sixty-six (166) E&Ps have filed for bankruptcy.15 Although that number is staggering to think about, as well as the amount of debt involved, the E&Ps that did not file bankruptcy had to get creative in their acquisition, operation, and management of capital to keep business going.

OPEC’s actions and the industry’s response triggered a complete reversal. Prices dropped; banks scrambled to evaluate the value RBLs were granted on; and E&Ps reacted by drastically cutting their capital expenditure budgets and operations nationwide. Even though prices decreased as a result of the industry reactions to OPEC, the banks’ willingness to loan stayed positive. Access to public markets for debt and equity were readily available as well. The industry kept their eye on the low prices but was optimistic enough to keep operations going along, not expecting prices to stay low for too long. The industry and its lenders expected the roller coaster to turn upwards, and that thought seemed to be shared by the entire industry. “In early 2015, following their December top-down loan portfolio review, bankers by and large were still positive that their borrowers could survive oil in the $50s— if it didn’t last too long.”11

Given the precarious leverage of some of the more aggressive shale players, capital providers looked for assurances that their investments would be protected in the event the producer went bankrupt. Off-balance sheet transactions popular in the late ’90s were dusted off. Non-banks purchased volumetric production payments or made loans with equity kickers in the form of convertible overriding royalty payments that, upon repayment of the principal, would automatically convert to net profit interests in the financed properties.

The misguided hopes of the industry and its lender’s let them down. E&Ps and their lenders got themselves into trouble by thinking an up-slope was coming. E&Ps acquired more debt from multiple sources and banks were not worried with those actions. By mid-2015 commodity prices had continued down the roller coaster and reality had finally sunk it. In his December 2017 interview with the Oil & Gas Financial Journal, renowned Houston energy lawyer Bernard F. (Buddy) Clark Jr.12 stated, “The ‘lower for longer’ reality kicked in…”13 The ‘lower for longer’ mantra refers to a

A new twist on the type of drilling dollars majors had contributed to independents back in the 1930s to prove up acreage was the financial partner “DrillCo” agreement, primarily beginning in mid-2015. Instead of dollars from major oil companies, private-capital providers joined producers 28

in drilling wells in this joint-venture structure in which the producer contributes raw acreage and the financial partner contributes drilling dollars in exchange for a working interest in the wells…

PRIVATE EQUITY’S INFLUX INTO THE OIL & GAS INDUSTRY Since doors were opened for investment opportunities in the oil & gas industry, someone had to step up and continue to supply capital to E&Ps. “With the traditional capital sources still largely on the sidelines, what has enabled the industry to recover and increase production in the lower 48 since 2015?...Enter private equity.”19 Of course private equity invests in essentially every industry worldwide, but private equity recognized a golden business opportunity and has allocated more funds towards the oil & gas industry based on the historical background discussed above. “[Private Equity] firms identified the gap left by traditional financing sources and provided a platform for institutional investors looking to diversify, mitigate market volatility and obtain high returns on investment to become key providers of funding to the O&G sector.”20

…The DrillCo structure was favored by investors as a “bankruptcy remote” entity that would be separate from the producer’s assets in the event of bankruptcy.16 The industry’s players were thankful for these alternative financing tools because the traditional methods of lending and capital acquisition were no longer widely available. “The financial model that had impelled the growth of the energy industry became unsustainable due to low commodity prices severely impacting access to public debt and capital markets, constraining bank lending and producing less favorable company and asset valuations.”17

“A new twist on the type of drilling dollars majors had contributed to independents back in the 1930s to prove up acreage was the financial partner ‘DrillCo’ agreement, primarily beginning in mid-2015.”

The role of private equity has increased immensely from the 2008 financial market crisis, through the 2014/2015 oil & gas market crisis, to current day.21 From investing about $5 billion in the upstream sector of oil & gas during 200820012, private equity investments had increased to more than $200 billion during 2012-2017.22 The ‘upstream’ sector of the oil & gas industry, which is the focus sector of this article, is responsible for finding, acquiring, and developing oil & gas assets. In his interview with the Oil & Gas Financial Journal, Buddy Clark Jr. further opined that “70% of the activity in the industry [in 2017] is private equity driven. Ten years ago, it would have been considerably less, and 20 years ago it would have been zero.”23 In the same interview, when asked if he thought private equity would continue to invest in oil & gas in 2018, Mr. Clark replied:

Because traditional financing sources through commercial banks became scarce for most E&Ps, the door was opened to these alternative financing tools to become new sources of capital for E&Ps and additional options for investors to continue to profit from the oil & gas industry. “Restrictions imposed by the [new] guidelines on commercial banks will create opportunities for alternative capital sources, including mezzanine lenders and private-equity sources.”18 2019 commodity prices are still wavering compared to prices pre-2008 and 2014 market crises. Traditional means of financing are still not available on a widespread basis, including a slow turnaround for the RBL market as well as access to public debt markets. During this time, P&E companies have continued to search for sources of capital opening the doors for investment opportunities.

Definitely. Unless private equity finds a better place for its investment, it will remain the principal capital provider to the industry in 2018. It used to be that the banks could dictate terms of credit agreements, but we’ve seen situations where private 29

equity has gone to a bank and said, “we’ll let you loan money to our management teams, but here’s the credit agreement you’re going to use.” You would have thought that after the crash in commodity prices that the private equity sponsors would not have been as aggressive, but it really hasn’t slowed down their view of the world. That’s an over generalization, of course, but they command a large piece of the market.24

an immediate impact, of course, but this influence is also going to have long-term implications on the industry. The focus of private equity’s business model could take over the industry. “The US onshore oil and gas business has been fundamentally transformed with the involvement of private equity funds providing liquidity, technological innovation, and driving value creation.”29 Technological Innovation Private equity in the oil & gas industry has been compared to the venture capitalists in Silicon Valley’s tech startup sector.30 “Private equity was instrumental in the first U.S. shale boom, backing companies that experimented with [new] drill bits and rocks, and literally sketched out the landscape of burgeoning shale plays still in their infancy.”31 By using their high-risk/high-reward outlook towards the oil & gas industry, private equity was willing to take a chance on the shale revolution and its horizontal drilling techniques and technology. This risk has paid off and will continue to pay off.

There are no signs of the private equity investments slowing down in the oil & gas industry. 25 The seemingly only risks that would scare private equity off would be another major down slope in commodity prices or some alternative industry that would be a better place for them to invest their money. “Private equity is not a temporary fad, but a key (sometimes dominant) player in the upstream sector, especially as public companies continue to feel the pressure from shareholders to reduce capital spending and focus on core assets providing the highest returns on funds invested.”26 The O&G industry will continue to require a large amount of capital, and private equity firms are well situated to continue to capitalize on this fact. 27 Even with commodity prices having stabilized in late 2018 and in early 2019, oil & gas industry players are still going to keep a sharp eye out for industry factors that can cause future down slopes in the oil & gas roller coaster. However, it seems private equity is here to stay for the time being. “Regardless [of the industry outlook being uncertain], private equity is now an integral part of upstream development in the US, and it will likely continue to drive changes to how oil and gas properties are acquired and divested [and developed].”28

“Moneyball forces a team to find players that produce more value than they are being paid. Overall, the team benefits by saving money but reaping the benefits of the relative overachieving success. Private equity has taken this strategy and applied it to the oil & gas industry.” “Moneyball forces a team to find players Value Creation that produce more value than they are being paid . . Private . Overall, the has teambeen benefits by saving money equity compared to the iconic but reaping the benefits of the relative ‘Moneyball’ strategy used in Major League overachieving success.isPrivate equity ahasdifferent taken Baseball. Moneyball essentially this strategy it to athe oil based & gason perspective on and how applied to assemble team industry.” value creation at each roster spot. Instead of trying to grab as many super-stars and fill the rest of the spots with average players, Moneyball forces a team to find players that produce more value than they are being paid. Overall, the team benefits by saving money but reaping the benefits of the relative overachieving

PRIVATE EQUITY’S INFLUENCE ON EXPLORATION AND PRODUCTION COMPANIES Private equity has done more for the oil & gas industry than simply cast it a lifeline while traditional financing sources have subsided – it has also influenced the industry for the better in multiple ways. Private Equity’s influence has had 30

regarding what the industry could look forward to by stating,:

success. Private equity has taken this strategy and applied it to the oil & gas industry. “By charting a different path, relying heavily on analytics to generate the best returns by acquiring properties with investor money, proving them up as valuable plays, and then selling those properties within a relatively short timeframe.” 32 Stated in more detail:

Going forward, from a capital perspective, you see the same financial products with a new name trotted out every five years or 10 years. For example, in the 1980s there were MLPs, blind drilling funds and conventional farmouts. Today we’re seeing MLPs, SPACs, and DrillCos. To me it’s the same product in a new wrapper.36

The private equity approach, at its core, has been to grab a piece of the oil and gas value chain where the risk is high, but the potential reward is also high. By acquiring properties that are not fully developed, developing them further and “de-risking” them in the process, and then selling the properties (often to Strategic Players) to be fully developed by such subsequent buyer, private equity players are able to generate significant profits in a different manner than Strategic Players who might typically look to generate profits from more longterm development of properties.33

These ‘new’ transactions and deal financing structures have infiltrated and helped to revive the oil & gas industry. Further, because of the lack of traditional financing methods and private equity’s influence on the industry and its players, many small to mid-size E&Ps have been more than eager to team-up with private equity money in order to achieve both sides business goals. Transaction and Financing Structures Influenced by Private Equity in the Oil & Gas Industry

Besides supplying capital to the industry in its time of need, private equity’s business model and focus has further cemented private equity as a major player. “As the industry enters into a new consolidation phase, companies are trying build asset portfolios based on basic microeconomic principles like agglomeration, economies of scale, standardization and knowledge specialization to maximize performance and value creation.”34 Liquidity: Providing Transaction Structures

Capital

“The O&G industry has always been characterized by coming up with creative ways to finance projects.” 37 The following are prominent and innovative transaction and financing structures that have entered the oil & gas industry driven by private equity. DrillCos DrillCos have been referred to by many different titles; Drilling Joint Ventures, 38 Nontraditional Joint Ventures, 39 and Drilling Participation Agreements. 40 For clarification, a DrillCo is not a company – it is a partnership and joint venture evidenced through a contract entered into by an investor (private equity capital supplier) and an E&P company (who supplies the assets and executes the drilling).

Through

Private equity’s influence on the oil & gas industry has brought with it many types of deal structures that the industry was familiar with but now contain new twists due to private equity’s involvement. “[Disregarding traditional transaction and financing structures] PE firms have introduced alternative financing structures in recent years by using long-established O&G practices and adapting them to the PE Model…”35 In his interview with the Oil & Gas Financial Journal, Buddy Clark Jr. responded to a question

This type of deal derives from a ‘farm-out,’ which is a longstanding oil & gas industry deal41. Farm-outs are arranged with usually two E&Ps with ‘Farmor’ E&P owning the assets and ‘farming out’ the operations and development of the assets to the ‘Farmee’ E&P. The Farmee would 31

be in the position to have to ‘drill-to-earn’ its working interest in the asset(s).

experience in executing the acquisitions and development. Further, each side will receive a working interest in the assets tied to the amount of funds it contributed to the SPE.

Drill-to-earn essentially means paying for and executing the drilling of wells to a certain agreed upon extent in order get interest in the assets conveyed to itself by the Farmor. Some reasons the Farmor would enter a Farm-out could be that it does not have the capital to drill or it does not have the time to develop assets before its leases expire, but a Farmee E&P would. Capability and need would meet opportunity.

However, usually the private equity investor will pay a ‘carried interest’ by paying more than their proportionate share of the “shared” costs in order to take part in the AcqCo. Like DrillCos, part of the negotiations and development of AcqCos is a determination of a reversion of at least a portion of the interests to the E&P once achieves certain asset development goals.44 SPACs

“Unlike DrillCos and AcqCos, which are normally utilized in the upstream sector of the oil & gas industry, Special Purpose Acquisition Companies (SPACs) are utilized in the midstream sector.”

Unlike DrillCos and AcqCos, which are normally utilized in the upstream sector of the oil & gas industry, Special Purpose Acquisition Companies (SPACs) are utilized in the midstream sector. Very generally, SPACs are

Similarly, in a DrillCo, the E&P holding the assets (either through true ownership or through oil & gas leases) may not have the capital to execute the drilling plan and develop the assets…enter private equity. An investor, backed by private equity, will supply capital to the E&P to execute a drilling plan. Instead of drilling and acquiring interests in the leases with long term goals like the Farmee in a Farm-out, the investor, in return for supplying drilling capital, will be conveyed interest in the wells drilled but only for the amount of time it takes for the investor o reach a certain return on its investment. 42 The E&P and the investor agree on an internal-rate-of-return (IRR), and when that IRR is reached a portion of the investor’s working interest will revert back to the E&P. The investor will also retain a portion of its working interest or even an overriding royalty.43

…newly formed shell companies, without any revenue or operating history, that raise proceeds in an IPO (and a concurrent private placement 45 ) for the purpose of acquiring control of, or merging with, one or more O&G companies or asset portfolios. The offering proceeds, with the exception of amounts reserved for working capital, are placed in a trust account, and funds can be withdrawn only under certain limited circumstances. A SPAC must liquidate and return to investors their pro rata shares of the funds then held in the trust account fails to consummate its initial business combination (“IBC”) within the specified time frame (usually 24 months or less).46

AcqCos

These midstream/oil & gas centric SPACs supply capital as an alternative financing mechanism to facilitate new midstream infrastructure projects. Like AcqCos and DrillCos, SPACs facilitate private equity investment as an opportunity to back seasoned industry managers to acquire and develop (midstream) assets.47

Acquisition Joint Ventures (“AcqCos”) essentially pair private equity investor money with either a seasoned E&P or a management group with industry experience with the mission to acquire undeveloped or poor performing assets already held by other E&Ps. The two sides will create special purpose entity (SPE); both will contribute a certain amount funds to the SPE to use to acquire and develop assets; and the E&P or management team partner will deploy its 32

A DEEPER LOOK DOWN DRILLCOS

THE

WELLBORE

These general dynamics of DrillCos are the simplest way to recognize a DrillCo.

Basic Structure of DrillCo Transactions The basic structure and general dynamics are shared by essentially all DrillCo transactions. The parties involved in a DrillCo are usually a smaller to mid-size E&P company (the Operator) on one side and a private equity investor (the Investor) on the other.53 The transaction dynamics begin with a capital contribution by the Investor to the joint venture for the purpose of funding the asset drilling and development program.

Picking up from the high-level description in Section III supra, the focus of the next two sections of this article will be an in-depth look at DrillCos, as well as some emerging issues that lawyers representing the involved parties are dealing with today. As a result of economic factors and private equity’s influx into the oil & gas industry, many relatively new types of deal structures have worked their way into the industry. Of which, DrillCos are one of the most prevalent upstream deal structures utilized to fund drilling programs and seek returns nationwide.48

This capital contribution will pay for the Investor’s portion of the costs of drilling as well as an agreed upon portion of the Operators costs of drilling. In return for this capital contribution the Operator will assign to the Investor a percentage of working interest in the leases. Further, the parties will determine an Internal-Rate-of-Return on investment (the IRR) for the Investor.

DrillCos Are Tailored to the Parties Involved from Transaction to Transaction. In negotiating and structuring DrillCos, each party needs to consider their own capabilities and needs as well as the capability and value of the asset or assets involved. It is important for lawyers representing each side to understand that DrillCos are not cookie-cutter transactions; each DrillCo is structured and tailored to the needs of the parties involved. “This all sounds simple enough [regarding the basic structure of DrillCos]; but each DrillCo is negotiated and structured to fit the assets involved and the particular requirements and goals of the parties, and as such, can be anything but simple.”49 “While it is tempting to try to identify what is “market” in regard to any type of transaction, there is really no market for DrillCo transactions, as each DrillCo is a uniquely negotiated transaction.”50

When this IRR is reached a partial reversion of the Investor’s rights in the wells will be triggered and an assignment of the rights will be made back to the Operator. DrillCos are very complex and involve many more points of consideration, but these basic tenants are the core of what make up this type of drilling partnership agreements. *The following is a chart to visually lay out these key structural points of DrillCo’s Key Structural Point

However, notwithstanding the tailoring requirements, each DrillCo also shares many staple principles of structure and points of negotiation. “Each DrillCo is uniquely tailored to the particular operational and financial circumstances of the participants but they all share certain underlying principles.” 51 “While the structure of a DrillCo Transaction is limited only by the creativity of the parties entering into them, there are fundamental structural elements that appear in many recently announced DrillCo Transactions.”52 These ‘fundamental elements’ of each DrillCo are what make the DrillCo transaction unique concerning other joint ventures.

Operator

Investor

Asset Development Costs

____ %

Pre-IRR Working Interest

____ %

IRR Determination Post-IRR Working Interest

____ % ____ %

____ %

Asset Development Costs

and budget will be agreed upon at execution of the DrillCo.

The foundational need of the Operator in a DrillCo is the need for cash to execute a drilling plan to develop its assets. This is essentially the only role the Investor plays in the DrillCo – to supply cash for drilling operations. The capital contribution by the Investor does not exclusively operate to earn its working interest in the leases or pay for its portion of the costs correlated to its working interest percentage. The Investor’s capital contribution will also cover at least a portion of the Operator’s development costs which are correlated with the Operator’s remaining working interest percentage. “The investor pays for its share of all costs and some – or, in rare instances, all – of the Operator’s share of certain defined costs in wells drilled.”54

All subsequent Tranches, their work programs and budgets, are subject to some mechanism of approval by one or both parties to continue the DrillCo joint venture once each Tranche is complete. “After each Tranche is completed, the Investor and/or the [Operator] generally have the right to decide whether to proceed with subsequent Tranches.”58 These decisions or approvals of subsequent Tranches and to keep the DrillCo joint venture going can vary and just depend on the negotiated terms of the DrillCo. “Sometimes the [Operator] is required to propose one or more subsequent Tranches in which the Investor may elect to participate in or at its discretion. Other times, subsequent Tranches are subject to mutual agreement by both the [Operator] and the Investor.”59

The Investor’s additional cost coverage of a percentage of the Operator’s development costs is known in the oil & gas industry as a ‘carry.’ The capital contribution and the carry will be allocated to cover drilling costs (Development Costs) of each well planned for in the initial ‘Tranche’ (group) of wells. The full definition of Development Costs will be ironed out in negotiations but is generally defined as “those costs and expenses to drill, complete, and equip each DrillCo Well in a Tranche, and will include costs related to permitting, well site construction, drilling, testing, fracturing, and stimulating each DrillCo Well and the installation of flow lines to tanks or sales lines.”55

Pre-IRR Working Interest In return for the Investor’s capital contribution to the drilling partnership, the Operator will assign to the Investor a portion of the working interest in the leases dedicated to the DrillCo. “Of prime importance to the investor is receipt of the assignment of working interest…earned by the investor’s participation.” 60 This assignment of working interest is critical to the Investor as it conveys a real property interest in the subject leases enabling the Investor to claim the value of the production proportionate to the percentage of working interest assigned to it.

Amounts of, or possibly the entire capital contribution is essentially tied to a work program and budget approved by both parties for that particular Tranche. “DrillCos require significant capital commitments, typically staged in tranches, with commitment for each tranche often being in the hundreds of millions of dollars.”56 “A tranche usually comprises the wells included in an annual work program.” 57 The amount of the capital contribution for the initial Tranche, work program,

The exact percentage of the working interest conveyed to the Investor will be a major point of negotiation in setting up the structure of the DrillCo. It is important to keep in mind that the working interest percentage determined to be assigned to the Investor will dictate the amount of costs the Investor is responsible for as well as the amount of production the Investor has rights in.61 The specific working interest percentage will vary from DrillCo to DrillCo but is usually in the same range. The Investor can expect a working interest 34

assignment to be around 75% to 90%, which of course is subject to the partial reversion detailed below.62 Therefore, in the case of a 90% working interest assignment, the Investor will be responsible for 90% of the drilling and development costs63 but will also have the rights to 90% of the production from the DrillCo wells, up to the point of reversion.

wellbore, including those operations related to production and the movement of hydrocarbons within the entire wellbore.”66 Wellbore assignments are also regularly ‘depth limited’ at the wish of the Operator so as to limit as much as possible the extent of the conveyance to the Investor. This will limit the Investor’s access to production from certain agreed stratigraphic depths, but as usual this will be a point of negotiation before the execution of the joint venture.

Until now, this article has referred to the assignment by the Operator made to the Investor as simply an assignment of working interest in the subject leases of the DrillCo. This description is overly broad and will now be narrowed. The interest in the assets dedicated to the DrillCo joint venture that are earned by and assigned to the Investor are typically a ‘wellbore’ assignment. This type of property interest has a history full of turmoil as far as explaining with specificity what rights it entails.64

Until the assignment is made the Investor is not entitled to receive any profit from the oil & gas production. Therefore, the assignment itself is important to the Investor, as well as the basis and timing of the assignment. “Investor Assignments can be made on a well-by-well basis, on a Tranche basis or simply on a periodic basis, as negotiated by the parties.” 67 However, the timing of the assignments is a heavily negotiated topic and can be correlated with drilling cost payments, the beginning of drilling operations, and/or the completion of drilling operations.68

The general idea behind a wellbore conveyance is for the grantor to convey the least amount of property rights in the subject leasehold as possible while still conveying enough property interest for the grantee to be able to benefit from its production. “DrillCo deals typically involve [an assignment of] an undivided interest in the portion of the leasehold acreage required to produce from those wells (namely, a "wellbore" interest).” 65 Careful consideration and drafting should be done on the part of the Investor’s lawyers to make sure that the exact meaning of wellbore interest is stipulated in the DrillCo.

Notably, the Investor will prefer that the assignments be made once the initial capital contribution is made. “[Regarding timing of the assignment to the investor] There may also be situations (related to insolvency or bankruptcy concerns of Investor regarding the [Operator]) in which the Investor would be reasonable in requesting an up-front [assignment], which may cover a greater area than just the wellbore of each DrillCo Well.” 69 This preference derives from concerns of the Investor of the possible bankruptcy of the Operator. If the Operator were to file bankruptcy before the Investor has made a return on their investment, then the Investor will want to be able to claim their property interest in the leases (or wells) as security for their investment.

“The specific percentage of working interest in the leases or wellbores is intended to be conveyed with no strings attached other than contractual obligation of the Investor of the partial reversion once the IRR is achieved.”

Lastly, the assignment from the Operator is intended to be a true and outright real property conveyance. The specific percentage of working interest in the leases or wellbores is intended to be conveyed with no strings attached other than contractual obligation of the Investor of the partial reversion once the IRR is achieved. 70 This intention is by design for multiple reasons but once again with a focus on bankruptcy concerns. If the

Part of the focus should be on ensuring that what interest the Investor receives allows them to further develop and operate the wellbore in the case it would be forced to conduct drilling operations apart from the Operator. “Further, consideration should also be given to providing the Investor with rights to the remainder of the wellbore as may be necessary for conducting operations within the assigned portion of the 35

Operator were to file for bankruptcy before the IRR is achieved, the Investor would already have a vested interest in the conveyed percentage of the leases or wellbores.

the wells.” 74 The Investor will convey a percentage of its working interest back to the Operator as well as retain a small percentage of its own.

IRR Determination.

There are some instances where the Investor will actually convert its working interest to an overriding royalty interest (ORRI) by conveying all its working interest back to the Operator and then the Operator will convey an ORRI at an agreed percentage to replace the Investor’s working interest.75 When the ORRI option is used, the Investor will no longer be responsible for any portion of the drilling costs. When the more typical option of working interest reversion is utilized, the Investor will still be responsible for its share of the costs related to the amount of working interest it retains.

Another contract building block and a major focal point in negotiations in DrillCos is the internal-rate-of-return (IRR) for the Investor. “The commercial terms of a DrillCo transaction typically require reversion of some percentage of working interest to the operator at such time as the investor has achieved the agreed rate of return hurdle.”71 The IRR sets a return benchmark for the Investor that will trigger a reversion of part of its assigned interest in the leases or wellbores back to the Operator. “The assigned interest [from the Operator to the Investor] is subject to partial reversion to the operator upon the investor achieving an agreed internal rate of return typically between 10% to 20% (or some other agreed return metric) on its investment (the IRR hurdle).”72

There are also some variances as to the partial reversions being incrementally triggered throughout the life of the wells in the DrillCo. “Partial reversions may occur incrementally at different return levels...”76 “In that case [when the parties agree to multiple IRR Hurdles], there would be a partial reversion of the working interests conveyed pursuant to the Investor Assignments upon achievement of the initial IRR Hurdle, with subsequent, incremental reversions upon the achievement of any subsequent IRR Hurdle.”77 The option selected regarding reversion all depends on what best suits the parties needs involved and how the negotiations playout in forming the transaction.

As with any crucial monetary focal point of a transaction, the Investor’s lawyers must clearly delineate the manner in which the IRR will be calculated and achieved. “It is important that the return hurdle calculation contains a clear description of the revenues and costs that will be taken into consideration.”73 Much consideration is needed here as the IRR is achieved by the Investor through its share of production in the DrillCo wells while also taking into consideration all costs the Investor must bear. Highly important to both sides, the IRR sets Investor’s return on investment through the amount of ‘front-side’ production in which the Investor has a bigger piece of the pie (pre-reversion allocation of production).

Drivers for Each Side of the Deal in a DrillCo. As stipulated to above, the two parties to DrillCos are an Investor and an Operator. “While drilling joint ventures historically have been between two E&P Companies [Operators], today’s DrillCo Transactions are most often entered into by an E&P Company and a [Private Equity] Investor, and whose primary purpose is investing in DrillCo Transactions.” 78 Each party has their own reasons and motivations for entering into DrillCos.

Post-IRR Working Interest. As eluded to above, once the IRR hurdle is met by the Investor through its pre-reversion percentage of working interest, a partial reversion of the Investor’s rights to the Operator will be triggered. “[Regarding the reversionary interest conveyed to the Operator] The majority of the cash flow is going first to the financial sponsor [the Investor] and that threshold is in the mid-to-low teens and then reverts back to the operator. The operator gets to claw back some of the interest in

Operator Motivations. The main need for Operators that enter DrillCos is for capital to fund drilling operations. 36

petroleum assets and not waste their capital on other areas that only facilitate development. Instead of funding full management teams to buy, manage, and develop their own leases, or funding Operators that don’t already have rights to drill leases, Investors prefer to maximize their placement of funding directly and solely to developing assets. “DrillCos are often entered into with respect to an E&P Company’s oil and gas properties after a particular drilling prospect has been identified, tested, and the risks somewhat reduced from an operational and geological perspective.”85 DrillCos allow Investors to do this by joining an Operator simply by funding drilling. No other money is spent on any other aspect of the oil & gas industry in DrillCos.86

DrillCos can be attractive to Operators as they enable asset development through new cash flow streams with essentially no significant capital spending of their own and no debt being added to the balance sheet. Further, because the Operator will be entitled to a larger percentage of postreversion production of the wells, DrillCos can also provide Operators with consistent cash flows when wells begin to decline in production.79 An important concern for Operators, when entering DrillCos and taking the supplied capital by the Investor, is its ability to not add additional debt to its balance sheet. “For an operator with limited access to capital, but holding acreage with development potential, a DrillCo presents an attractive means by which to develop its acreage. The DrillCo is, in effect, off-balance sheet financing for the operator.”80 This allows for the Operator to develop the assets that it currently holds, while not burdening its balance sheet, stock price, or credit rating so further business prospects won’t be effected.81

Finally, and of extreme importance to Investors, are bankruptcy concerns regarding its business partners. Investors see DrillCos as desirable transactions in part because of the real property conveyance through the assignment of working interest that allow the Investor to have vested rights in the DrillCo assets. “Investors may also prefer DrillCos over other investments in the upstream oil and gas sector because they may offer better protection of the Investor’s investment in the event of an E&P Company bankruptcy. The Investor may be better protected because the Investor, after assignment, owns a real property interest in the assets.”87

An Operator is further drawn to DrillCos due to the fact that the Investor will stay out of the decision making and let the experts (the Operators) develop the wells. Besides the upfront negotiations and development of a drilling program plan 82 , Investors will stay out of the day to day operations. This is attractive to Operators who don’t want to be micro-managed and want to be able to do their job with little to no interference.83

If its Operator partner in the DrillCo were to file bankruptcy, the Investor would have a real property interest in the asset that cannot be touched (in theory) by the bankruptcy trustee. “Bankruptcy concerns involving the operator could cause the investor to require up-front assignments.” 88 Upfront assignments to the Investor are desirable for the Investor as it covers the Investor’s bankruptcy concerns from the start of the DrillCo. Whether up front or not, the design and intent of the assignment to the Investor is to convey its right to a percentage of production but also to protect its interests in the event of the Operator’s bankruptcy.

Investor Motivations For Investors, DrillCos permit access to prime petroleum assets in shale basins and more input and control than investments on other industries and their partners. “For an investor, a DrillCo provides an opportunity to deploy capital, sometimes in large amounts, while accessing oil and gas assets and management expertise not otherwise available to the investor.” 84 Private Equity investors have abundant amounts of capital to invest, and DrillCos present prime opportunities to invest in the upstream sector of the oil & gas industry. Further, Investors in DrillCos want to place as many dollars as possible into the development of 37

PROTECTING THE INVESTOR’S INTEREST IN A DRILLCO IN THE CASE OF THE OPERATOR’S BANKRUPTCY

gas/real property interest involved, inter alia, was a ‘term overriding royalty interest’ (TermORRI).93 The case focused on whether the termORRI interests should remain property of the bankruptcy estate due to its production limited nature.

Recently, DrillCo Investors have been concerned with the possible bankruptcy of their partner Operators before the IRR has been met.89 The concern here for the Investor’s lawyers is not so much a business concern but one of control of the vested property interest in the DrillCo assets to protect the Investor’s investment.90 Both parties to a DrillCo intend for the Investor’s assignment of working interest in the leases or wellbores to be a true property conveyance and not a disguised financing of sorts for the Operator.

“The ORRIs entitled the holders thereof [NGP Capital Resources Co.] to receive a specified percentage of gross proceeds attributable to ATP’s [the Operator] interest in the hydrocarbons attributable to a given well until the holders received a specified dollar amount, including a specified return.”94 Term-ORRIs are very similar in nature to the structure of the assignment of working interest couple with the partial reversion when the Investor achieved the set IRR.95

For example [regarding Investor concerns about the bankruptcy of the Operator], while the Development Agreement [inside the DrillCo] will often make expressly clear the parties’ intent that the Investor Conveyances are absolute transfers of interest in real property and not merely security for a debt, some Investors may be concerned that a bankruptcy court would characterize the transfer of the E&P Company’s interest in its oil and gas properties as something other than a transfer of a real property interest.91

Both parties moved for summary judgement, the plaintiff asserting that the term-ORRIs should not be considered property of the bankruptcy estate, and the defendant asserting that the termORRIs should be considered property of the bankruptcy estate. The court dismissed both parties’ motions for summary judgement and ruled that there were questions of fact regarding both positions taken. As such, In re ATP Oil & Gas Corp. was never fully litigated to an ultimate decision and settled outside of court which led to the said uncertainty and concerns of the Investors and their lawyers.

If a bankruptcy court were to determine that the interest conveyed to the Investor is something other than a real property interest in the DrillCo leases or wellbores, it would spell trouble for the Investor. In that instance, the bankruptcy trustee for the estate of the Operator could very well have the power to avoid the transfer of interest to the Investor and the Investor would be without any security for its interest in the DrillCo assets.

“Both parties to a DrillCo intend for the Investor’s assignment of working interest in the leases or wellbores to be a true property conveyance and not a disguised financing of sorts for the Operator.”

These concerns of the Investor and its lawyers stem from a recent bankruptcy case that ruled there was a question as to whether a very similar type of transaction was a true property conveyance or a disguised financing. 92 In In re ATP Oil & Gas Corp. the Plaintiff was NGP Capital Resources Co. (the Investor/capital supplier) and the Defendant was ATP Oil & Gas Corp. (the Operator). The transaction in In re ATP Oil & Gas Corp. involved a similar transaction to DrillCos except the oil &

The court in In re ATP Oil & Gas Corp., the United States Bankruptcy Court for the Southern District of Texas, gave some insight as to how a DrillCo transaction could be analyzed if the Investor’s fear of their Operator partner declaring bankruptcy ever came to fruition. The court explained that it would not hold itself to the intent of the parties in the transaction, but they will characterize the transaction based on its economic substance.96 In doing so the court analyzed both parties assertions, that the term-ORRIs were or 38

weren’t part of the bankruptcy estate, by applying a number of factors relevant to each possibility.97 Because no pointed decision was handed down, it’s easy to see why parties to DrillCo transactions, especially Investors, could be scared by this caseby-case and economic substance of each transaction analysis.

financing or merely a security for debt, the issue then becomes whether a precautionary mortgage will secure the Investor’s interest from the bankruptcy estate of the Operator. The trend for Investors, based on concerns arising from In re ATP Oil & Gas Corp., is for Investors to demand a precautionary mortgage be granted by the Operator to protect the investors interest in the case a bankruptcy court determines that the assignment in a DrillCo is not a true property conveyance. “Investors argue that such a precautionary mortgage would provide necessary protection in the event interests it received under the Investor Assignments were characterized as something other than a real property interest by a bankruptcy court.”99 Therefore, a full analysis on whether a precautionary mortgage would cover the Investor’s concerns is warranted.

The issue boils down to whether a bankruptcy court, applying the law of the state the case derives from, will determine the Operator’s conveyance of real property rights to the Investor in a DrillCo to be a ‘true property conveyance’ or a ‘disguised financing’.98 If the court sees the conveyance as a true property conveyance, then the Investor’s concern regarding control of their interests in the case of the Operator’s bankruptcy would be abated. However, if the court would determine that the DrillCo assignment is something other than a true property conveyance, and more of a disguised 1

Susan Klann, Could Low Oil Prices Crush Industry’s Cyclical Nature, HART ENERGY (Feb. 8, 2018) https://www.hartenergy.com/exclusives/could-low-oilprices-crush-industrys-cyclical-nature-30758.

Insolvency Issues, 29TH ANNUAL ENERGY LAW INST. FOR ATTORNEYS & LANDMEN (2016). 15

HAYNES & BOONE, LLP, OIL PATCH BANKRUPTCY MONITOR 7–11 (2019), http://www.haynesboone.com//media/files/energy_bankruptcy_reports/oil_patch_bankrupt cy_monitor.ashx?la=en&hash=D2114D98614039A2D2D5 A43A61146B13387AA3AE.

Bernard F. Clark, Jr., Excerpt from Oil Capital: The History of American Oil, Wildcatters, Independents, and Their Bankers, 2 OIL & GAS, NAT. RES. & ENERGY J. 31 (2016).

Steven P. Otillar et al., Private Equity in Upstream Oil & Gas Transactions: The Evolution of Purchase and Sale Agreements, INST. FOR ENERGY LAW 70TH ANNUAL OIL & GAS LAW CONFERENCE 1 (2019).

Eduardo Canales & Hillary Holmes, Effects of Private Equity in the Oil & Gas Industry: Deal Structures, Developments and Trends, INST. FOR ENERGY LAW 5TH MERGERS & ACQUISITIONS IN ENERGY CONFERENCE (2018).

ENERGY AND RESOURCES FINANCING: A PRACTICAL FINANCING 7 (Thomas Huw & Anthony Skinner eds., Globe Law & Business 2015). 5

Clark, supra note 2, at 39.

Id. at 45.

Id. at 45–52.

Id. at 52.

Clark, supra note 2, at 73.

Clark, supra note 2, at 78–79.

Clark, supra note 2, at 85 (emphasis added).

Otillar et al., supra note 3, at 2.

Canales & Holmes, supra note 18, at 1.

Buddy Clark Jr. is co-chair of Haynes and Boone LLP’s Energy Practice Group in Houston, Texas.

As further evidence of the arrival and clout of private equity in the oil & gas industry, for more than a decade there have been prestigious national oil & gas law organizations that have been paying attention to and researching issues related to private equity in the industry. e.g., see Jeffrey A. Zlotky, Equity Financings – Selected Issues in Structuring and Negotiating Private Equity Investments in Oil and Gas Companies, 3 ROCKY MTN. MIN. L. INST. 3 (2006); see also Douglas E. McWilliams, Raising Capital for the Oil & Gas Industry, 59 ROCKY MTN. MIN. L. INST. 25 (2013).

Id. at 74.

Id. at 75 (citing Julie Steinberg, Falling Oil Prices Worry Regional-Bank Investors, WALL STREET J. (2016)). 12

See Rising Private Equity Investment Fuels Surging US Oil and Gas Production, M&A Activity, BUSINESS WIRE (Jan. 23, 2018), https://www.businesswire.com/news/home/2018012300582

Mikaila Adams, Energy Capital Evolution, OIL & GAS FINANCIAL J., Dec. 2017, at 12. 14

Charles A. Beckham, Jr. & Kelli S. Norfleet, Troubles in the Oil Patch: A Review of Oil & Gas Bankruptcy and

8/en/Rising-Private-Equity-Investment-Fuels-Surging-Oil; Collin Eaton, Private Equity Poised for Oil Growth as Public Companies Pull Back, HOUSTON CHRONICLE (Mar. 30, 2018), https://www.houstonchronicle.com/business/energy/article/ Private-equity-poised-for-oil-growth-as-public12792385.php.

Canales & Holmes, supra note 18, at 5–6.

See generally Justin T. Stolte & Michael P. Darden, Private Equity JVs: Part I – DrillCos, OIL & GAS FINANCIAL J., Oct. 2017 [hereinafter Private Equity JVs]. The details here on DrillCos are simply a high-level, general description of DrillCos. A more thorough analysis of these joint ventures is detailed in Section IV below. 44

Id. at 6 (emphasis added); see also Canales & Holmes, supra note 18, at 1 (“Private Equity firms have become key players in the oil and gas industry.”).

See Canales & Holmes, supra note 18, at 6. Obviously, AcqCos involve much more than what is discussed above. For the purposes of this article DrillCos will be the main focus. Therefore, what is detailed here on AcqCos is again only a high-level description.

Adams, supra note 14.

A private placement involves the sale of securities to a relatively small number of select investors that are very regularly private equity funds.

R. Ryan Staine & Erin Hopkins, “Moneyball” for the Oil Patch: How Private Equity is Re-Shaping the Upstream Oil and Gas Mergers and Acquisitions Market, INST. FOR ENERGY LAW 69TH ANNUAL OIL & GAS LAW CONFERENCE 20 (2018). 26

Otillar et al., supra note 3, at 18.

Otillar et al., supra note 3, at 32. Id.

Collin Eaton, Private Equity Poised for Oil Growth as Public Companies Pull Back, HOUSTON CHRONICLE (Mar. 30, 2018), https://www.houstonchronicle.com/business/energy/article/ Private-equity-poised-for-oil-growth-as-public12792385.php. 31

Id.

Staine & Hopkins, supra note 26, at 2.

Id. at 8.

Michael P. Darden, Drilling Down on DrillCos, OIL & GAS INVESTOR, Mar. 2018, at 74 (“Historically, the parties to such a transaction would have been two traditional industry participants in a typical drill-to-earn farm-out. Now the parties are likely to be an operator that may or may not be an established E&P and an investor that may or may not have industry experience, but that is backed by private equity.”).

Canales & Holmes, supra note 18, at 13; see also Otillar et al., supra note 3, at 1 (“The bottom line is that upstream oil and gas development has been, and will remain for the foreseeable future, a capital-intensive business”). 29

Canales & Holmes, supra note 18, at 7 (emphasis added).

47 48

Id.

Private Equity JVs, supra note 44, at 2 (emphasis added).

Canales & Holmes, supra note 18, at 5 (emphasis added).

Michael P. Darden & Matt N. Savage, An Overview of DrillCo Transactions and Select Drafting Considerations, 42 SECTION REPORT OF THE OIL, GAS & ENERGY RES. L. SECTION OF THE STATE BAR OF TEX. 53 (2017) [hereinafter DrillCo Overview] (emphasis added).

Id.; see also Canales & Holmes, supra note 18, at 2 (explaining how private equity’s business model and focus has seen success in the oil & gas industry, as well as how E&P companies have learned and benefitted from these strategies).

Canales & Holmes, supra note 18, at 13.

Id. at 5

See Adams, supra note 14.

Id. at 52 (The reason for smaller to mid-size E&P companies utilizing DrillCos are akin to the beginning three sections of this article. Smaller and mid-size E&Ps are in need of capital to finance their operations. Because of the past economic and industry downfalls, that traditional financing is less attainable for these size E&Ps. DrillCos operate as a non-traditional source of financing for these E&Ps and create profitable opportunities for private equity firms to enter the oil & gas industry).

Canales & Holmes, supra note 18, at 5.

Id.

DrillCo Overview, supra note 54, at 57.

Michael J. Byrd et al., Acquiring Upstream Assets Via Joint Ventures: An In-Depth Study of Deal Structures, Key Negotiating Points, Drafting Tips, and Relevant Law, INST. FOR ENERGY LAW 2ND MERGERS & ACQUISITIONS / ACQUISITIONS & DISPOSALS CONFERENCE 10 (2015).

Darden, supra note 50, at 74; see also DrillCo Overview, supra note 54, at 56–57.

Chris Heasley et al., Trends and Issues with 'DrillCo' Transactions, TEXAS LAWYER, Nov. 2015, at 1. 41

Byrd et al., supra note 40, at 10.

Id.

DrillCo Overview, supra note 54, at 56.

Id.

Darden, supra note 50, at 76 (‘participation’ by the Investor in this context means contributing capital at the required times). 61

Keeping in mind the costs the Investor is responsible for also includes the negotiated amount of the ‘carry’. 62

Nissa Darbonne, The DrillCo, OIL & GAS INVESTOR, June 2016. 63

See David Drumm, Wellbore Assignments – Some Guidance At Last, CAPITAL, Fall 2009, at 1 (“In a wellbore assignment, the assignee's interest is limited to rights ‘in the wellbore’ of a specifically defined well or wells”); Kurt M. Petersen, Wellbores: Shedding Light on a Transactional Black Hole, 48 ROCKY MT. MIN. L. INST. 13 (2002) (“In its simplest form, transfer of the wellbore alone is a sale of personal property”). 66

DrillCo Overview, supra note 54, at 57.

Id.

Id. at 56

Darden, supra note 50, at 77.

Private Equity JVs, supra note 44, at 2.

Id.

Darbonne, supra note 66, at 16.

See Darden, supra note 50, at 77.

Private Equity JVs, supra note 44, at 2.

DrillCo Overview, supra note 54, at 59.

Id. at 53 (emphasis added).

Id.

See Darbonne, supra note 66, at 13.

DrillCo Overview, supra note 54, at 54.

Darden, supra note 50, at 76.

The upfront capital the Investor has supplied to the joint venture. 91

DrillCo Overview, supra note 54, at 63 (emphasis added).

NGP Capital Resources Co. v. ATP Oil & Gas Corp. (In re ATP Oil & Gas Corp.), No. 12-3443, 2014 Bankr. LEXIS 33 (Bankr. S.D. Tex. Jan. 6, 2014) 93

In re ATP Oil & Gas Corp.

Beckham & Norfleet, supra note 15.

The DrillCo structure containing the partial reversion trigger by the achievement of the Investor’s IRR is comparable to the Term-ORRIs in that when a certain amount of production is achieved, the term-ORRI will dissolve and the working interest holder’s interest will no longer be burdened by the ORRI. Similarly, when the IRR in a DrillCo is achieved the partial reversion is triggered and the Investor’s rights are lowered to whatever amount is to be retained. This structure is similar to the term-ORRIs in In re ATP Oil & Gas Corp. 96

In re ATP Oil & Gas Corp. at 15

The court in In re ATP Oil & Gas Corp. looked at factors such as: Reversionary Nature/Transfer Not Absolute, Satisfaction of the term override from multiple properties, Subordinated Interest to Diamond Offshore, Burdens and Benefits of Ownership, and Payment Terms in deciding if there were inconsistencies with a term-ORRI under Louisiana law. The court also looked to comparisons of the subject transaction to a secured and unsecured loan in deciding whether there were inconsistencies with a loan under Louisiana law.

Darden, supra note 50, at 74; see also DrillCo Overview, supra note 54, at 54. 81

Of major concern to Public Operators and their legal representatives is how the Securities Exchange Commission views and treats the supplied DrillCo capital from the perspective of the Operator. It seems that the determinations of the SEC are on a case-by-case basis. This topic would be best addressed in a ‘Part 2’ of this article as it is ripe for development that could lead to a guide for Operator’s lawyers in the DrillCo context.

Courts would most likely apply a test much like In re ATP Oil & Gas Corp. did while comparing the interests conveyed (lease interests or wellbore interests) to their normal conveyance through state law, and also would compare the transaction as whole to both, a secured and unsecured loan, under state law.

Or subsequent drilling program plans that are addressed once new tranches are considered by the parties involved. 83

DrillCo Overview, supra note 54, at 57.

DrillCo Overview, supra note 54, at 54.

Investors are also concerned with the Operator’s bankruptcy after the IRR has been met and the reversion has been triggered because in most cases the interest that remains with the Investor is a working interest and therefore a property right. In this instance the Investor is still focused on protecting its interest from the Operator’s bankruptcy estate.

Again, this cost would be in addition to the ‘carry’.

See Heasley et al., supra note 41, at 1.

Darden, supra note 50, at 74.

See Darbonne, supra note 66, at 14.

DrillCo Overview, supra note 54, at 63.

United States Energy Friends & Foes: A Brief Synopsis of Current United States Policies with Mexico, Canada, Iran and Venezuela By: G. Braxton Smith Recent STCLH Graduate

The United States political landscape has seen some serious course changes in national policy with regard to its energy “friends” and energy “foes.” The United States has withdrawn from established international arrangements 1 and is being forced to cope with turmoil in other nations2 all while trying to strengthen existing relations with its energy producing neighbors.3 This article will provide a concise review of the current issues and potential solutions to issues that the U.S. faces in regard to some of their energy “friends” (Canada and Mexico) and their energy “foes” (Iran and Venezuela). The U.S. is striving to become fully energy independent and is currently pursuing a policy of “energy dominance.” 4 This pursuit is set against the backdrop of changing global demands and everincreasing unrest in one of the globe’s largest oil producing countries. 5 While this push towards energy dominance and the removal of the U.S. energy export ban has bolstered the health of the U.S. energy economy, the U.S. energy economy nonetheless remains intricately linked with its North American neighbors and with choices made abroad.6 The current administration relied heavily on promises of renegotiating the North American Free Trade (NAFTA) agreement during the campaign. This discussion was focused on more general and nebulous concepts than hard and fast proposals, and very recently we have seen what that renegotiation entailed. The new agreement signed on November 30, 2018,7 the United StatesMexico-Canada Agreement (USMCA), does not provide any earth-shattering changes but does offer some added protections for U.S. oil companies who were excepted from some restrictions on dispute resolution proceedings between governments and the private sector.8 The agreement also offers certain concessions on the

part of the U.S. with regard to recognition of the other nations’ sovereignty. 9 The changes in the agreement are intended to benefit all North American nations but clearly are more favorable to the U.S. The agreement is still waiting for final approval but would serve as a mechanism for updating the two-decade old NAFTA. Unlike the cooperative nature of the discussions with Canada and Mexico, the U.S. remains increasingly antagonistic with both Iran and Venezuela. The new administration is outspoken about their displeasure with the prior “Iran Deal” or Joint Comprehensive Plan of Action (JCPOA) and is seeking to use renewed sanctions to garner more favorable terms. This appears to be a tough road to hoe, as most if not all of the previous nations who supported the original deal are open about their unwillingness to pursue measures that could facilitate a renegotiation. 10 Venezuela has been in a downward spiral which shows no sign of slowing down and the U.S.’s approach to the problems has been to bolster restrictions on Venezuela in an effort to force the already weakened nation to acquiesce to U.S. goals. 11 There is a very real threat that Venezuela will revert to nationalist policies that would negatively impact the energy markets in the U.S. The current tactic of stick over carrot may only serve to further hamper industry growth for all parties involved. THESIS The U.S. policy of energy dominance being pursued by the current administration is likely to cause more harm long term than good. The administration is approaching their objectives in an antagonistic fashion that is unlikely to result in the most effective policies to truly see the U.S. placed first. There have been minor concessions made in the USMCA, but these are mirrored against the U.S. insistence on the removal of other provisions that further U.S. interests. By favoring an adversarial rather than a collaborative strategy the administration is fostering resentment and unwinding bonds between nations that may become more resistant to favorable negotiation with the U.S. in the future. The current strategy

could produce short term gains but may leave lasting bruises that will present future impediments to sustained growth.

examine what the recent developments in energy policy from all three nations perspective and what that means to the continuing trade relationship

The current U.S. administration has also disavowed multilateral agreements made by the previous administration. This course change sets a dangerous precedent that will both undermine international confidence in future U.S. promises and potentially diminish the deterrent effect of long-standing U.S. foreign policy measures. The outward appearance of gamesmanship is likely to result in subsequent hurdles that will serve to stifle cooperation and access to global markets for U.S. energy producers at a time when the U.S. is ramping up its capacity to export.

Recent U.S.-Mexico Relations The fact that the U.S. and Mexico share a border which is rich with hydrocarbon reserves has dictated how the two nations’ economies and interactions have developed in the last century. As the world became steadily more and more reliant on oil and gas the U.S. and Mexico slowly became interdependent on each other’s production and methods for extractions. In the years following NAFTA energy cooperation has led to substantial reforms to Mexico’s domestic energy policy. These reforms were a reaction to the realities of hydrocarbon production and the limitations faced by Mexico in this field. The previous Mexican president created mechanisms for Mexican energy production to expand greatly, with the help of foreign investment, and the policies created in that administration made foreign investors comfortable in what can be a risky market.

MEXICO AND CANADA Recent elections in Mexico12 have changed the local climate in regard to international cooperation and this will invariably impact the current U.S. administration’s policies and portends serious ramifications for the now recovering energy industry in both nations. All three nations have outspoken presidents, which presents issues when it comes time for rhetoric to meet reality. The U.S. and Mexico are presided by populist nationalists whose ideologies fall on opposite ends of the spectrum. This presents noticeable hurdles for collaboration as much of their respective espoused policy runs contrary to the other. This modern age of overbearing internet fire side chats presents a cyber-minefield of potential political missteps which could trigger potent obstacles for crossborder collaboration.

The recent election of Andrés Manuel López Obrador (AMLO) to the presidency in Mexico casts serious doubts as to what direction Mexico will head with respect to its energy policies with the U.S. Much like Trump, AMLO has relied on cultivating an image of being a leader for the often overlooked demographics in his nation. AMLO has actively espoused pro-nationalization view points and has mentioned restricting upcoming bid cycles that would bring in foreign investment, 15 much of which would likely come from the U.S. Mexico is heavily reliant on their energy industry, in Latin America only Venezuela and Ecuador are more reliant on their energy industries.16

The conflicting ideologies of the U.S. and Mexico’s executives are not the only bumps in the trilateral interactions. Equally important is the relationship and cooperative policies between the U.S. and Canada. In 2012, Canada launched its plan for Responsible Resource Development (RRD), which detailed certain policy objectives in their domestic production and their energy exports. 13 Canada’s largest energy importer has historically been the U.S. However, both nations desire to expand their presence in the global market and current U.S. policy has threatened this long-standing relationship. 14 The article will

This heavy reliance on the energy market puts their industry at risk from any major political or economic change. Foreign investment is encouraged by reduced risk and the recent liberalization in Mexico has boosted their energy sector greatly. This recent push for privatization has been criticized by the new Mexican president who has been vocal about his disapproval of the reduced role the government is playing in their domestic energy production. 17 But Mexico has used their national petroleum company, Pemex, as a financial and political tool in the past 18 and the 43

current president seems inclined to reprise the use of Pemex as a political tool.

agreement and retained much of the original provisions. Despite the fiery rhetoric of the current U.S. administration, the USMCA is a close mirror of its predecessor. This is likely due to the fact that outright removal of NAFTA would greatly disrupt the economies of all nations involved and strong political posturing rarely facilitates any agreement. It was predictable that the new NAFTA would closely resemble the original agreement because in the decades since its enactment the collective national economies have grown entangled in the benefits presented by the initial accord.

Fossil fuels accounted for over 90 percent of Mexico’s total primary energy supply in 2015.19 Trade in natural gas from the U.S. to Mexico has soared in the last half decade and this has caused Mexico to become heavily reliant on affordable U.S. gas for its electrical generation. 20 The pipeline capacity between the two countries has doubled in the same amount of time and may double again by the end of 2018. 21 Much of Mexico’s growth will be contingent on ready access to affordable U.S. gas, and this is not something that is lost on policy makers on either side of the border.

The U.S. and Mexico have enjoyed a mutually beneficial relationship in energy trade for the past two decades due to the reduced tariffs under NAFTA.27 Outgoing Mexican President Enrique Peña Nieto undertook some very aggressive reforms in 2013, under which the Mexican energy industry made private investment in the state-run company Pemex possible which has facilitated substantial foreign investments in the company28 and substantial growth in the Mexican energy sector.29 Both of these factors have made Mexico appealing to U.S. companies and offered a degree of stability not common in Latin American markets. However, Peña Nieto is left office in the end of 2018, and his successor is outspoken about his misgivings for the increased privatization in the Mexican energy sector.30

“The U.S. and Mexico have enjoyed a mutually beneficial relationship in energy trade for the past two decades due to the reduced tariffs under NAFTA.”

The current U.S. administration’s renegotiation NAFTA could have a dramatic impact on the price of U.S. gas in Mexico. 22 Mexico is the tenth largest oil producer in the world and sits on the eighteenth largest oil reserves globally.23 About three quarters of Mexico’s oil production is from sallow water offshore fields, but there is speculation that there may be as yet undiscovered fields in deep water. 24 The close proximity to the U.S. and substantial unconventional and deep sea means that Mexico could benefit greatly from U.S. companies experience in extracting oil and gas.25 Much of Mexico’s crude production is refined in the U.S. and shipped back into the nation for its domestic use. 26 There is a deep symbiotic relationship between the two nations energy sectors and thus any discernable policy changes are felt throughout both systems. Despite the obvious symbiosis in the respective nations energy sectors there has been vitriolic posturing on either side of the border which, while mostly hot air, has raised the collective hackles of the citizens in each nation.

It is important that USMCA be ratified but not necessarily expanded or contracted. Increased cross border energy trade has benefited both nations and whether in line with party ideology or not, the existing energy provisions of NAFTA should be retained in the USMCA. Disregarding the proven benefits of reduced trade barriers for the energy industry in favor of nationalist goals is likely only to push the political pendulum away from either administration. Continued and even expanded economic growth is likely if the two nations can look past their vocal base and focus on a cooperative long-term energy policy. AMLO was sworn in on December 1, 201831 which means that Mexico’s energy reforms may soon face likely throttle backs. AMLO has already caused significant consternation amongst U.S. and other foreign energy companies with statements about his desire to see more oversight and limitations of private energy investment. 32 One

USMCA: An Old Dog with New Tricks The current restructuring of NAFTA into the USMCA has made only minor changes to the old 44

important issue presented by the ascension of AMLO is the status of the USMCA, the neoNAFTA advocated by the current U.S. administration. Peña Nieto did approve the USMCA as it is written.

early in his presidency. The immediate future for U.S. Mexico energy relations is stable on the surface but private energy firms would do well to note that the populism that gave rise to AMLO may impede future opportunities to exploit Mexico’s on and off shore resources. It is unlikely that any major changes will develop as Pemex is still very reliant on outside investments41 and any substantive dip in production will be far more harmful to AMLO’s presidency relative to any Pyrrhic gains for the ideologues in his party.

However, there is a speculation that the now president AMLO may muddy the waters and may seek to renegotiate the current proposal. 33 The USMCA will retain NAFTA’s investor-state dispute settlement (ISDS) with regard to U.S. and Mexico for disputes arising from government contracts in the energy sector. 34 It also adds a chapter not found in NAFTA that recognizes Mexico’s constitutional direct government ownership of its hydrocarbons.35 It also includes provisions to “lock in” the current legal framework for private energy projects 36 which AMLO has been outspoken on his criticism of. 37 This uncertainty on the horizon is tempered with the realities that although recently production has dropped in Mexico,38 Peña Nieto’s reforms have made significant improvements to the Mexican energy economy39 and have made the nation both more competitive and productive.

The USMCA will likely prove a helpful tool for tempering dramatic change sought on either side of the border. By retaining the NAFTA provisions and recognizing the Mexican government’s ownership of hydrocarbons within their border the USMCA has the concessions necessary to ensure its successful implementation. On its face and in a static political climate the USMCA seems like a sound agreement to ensure continuing cooperation and prosperity, but the political climate is anything but static so the USMCA’s success will depend on the leadership in both countries for its potential to be realized.

The USMCA has been written to maintain the status quo within the U.S.- Mexico energy trade, but there are concessions to both sides which has made the new agreement palatable for both sides. By recognizing the Mexican government’s constitutional ownership of the hydrocarbons within their borders the USMCA has left the door open for future Mexican politicians to backslide on the Peña Nieto reforms. However, the retention of the ISDS protocols for the original NAFTA do allow for the redress of infringements on existing agreements by the Mexican government or Pemex. The ISDS does have a deterrent effect on state imposed restrictions but as evidenced by Brexit, if there is strong enough domestic political support existing agreements can be ignored if favor of the current political climate despite the potential consequences.

A Popular Problem Currently the U.S. and Mexico have populist nationalistic presidents who have broad ideological differences, which are shared by their respective support bases. There is a real threat that the ideological differences could blind both policy makers to the clear benefit of cooperative energy trade. Recently the global trend has been towards political extremism and if that trend continues there is a risk that Mexico and the U.S. will sacrifice economic growth for political posturing. The leadership transition in Mexico has caused some consternation about the reliability of future energy investments in the country. The new president has been lukewarm at best about the reforms enacted by the previous president and has insinuated he will exercise greater scrutiny over them. The Peña Nieto reforms are progressive and allow for royalty rates to increase with oil price and production-sharing agreements have allowed the State’s profits to increase as specific projects profitability grows. 42 The assignment of development blocks has a mandate of transparency which gives the operations legitimacy in a country

AMLO has openly stated his intention to maintain the status quo of the Peña Nieto reforms but at the same time not allow the expansion of private investment within Mexico. 40 And while there is the potential that he may not agree to ratify the USMCA if given the option, the likelihood is that he would be unwilling to rock the boat this 45

weary from corruption scandals.43 However, there is substantial popular sentiment that has actively opposed the reforms along with the leftist parties in Mexico and this led to the election of the ascetic Andrés Manuel López Obrador, who has been publicly critical of the reforms and expressed an intention of putting a halt to the auctioning off of unused development blocks.44

Recent U.S.-Canada Relations Canada and the U.S. are the reciprocally each other’s largest energy trading partners,47 in 2017 alone the value of the energy commodity trading between the two nations was approximately $95 billion.48 The U.S. is the leading supplier of oil, gas, and electricity to Canada.49 Conversely the U.S. imports approximately four million barrels of oil a day from Canada.50 However, current U.S. policies, which support remaining reliant on coal and nuclear energy, favor a U.S. first orientation and may pose substantial risks to future cooperation with their northern neighbors. Also, with the dramatic increase in the production of natural gas domestically, the U.S. importation of Canadian natural gas has flat lined in recent years.51

“These political realities and this current political climate pose substantial risks to cross-border cooperation because the very nature of cross-border cooperation requires compromises.” AMLO rose to power on a tide of populism that resulted in his landslide victory and a sea change in the past two decades of Mexican politics. 45 Despite their ideological differences, AMLO and Trump work off a similar script. Like Trump, ALMO has a combative reputation and is staunchly nationalistic and strives to cultivate a populist image.46 It is this backdrop that poses a threat to the continued cooperation between the nations. Both leaders rely on their nationalist and populist base for their support and as such must not be curtailing their respective nations interests in favor of another. These political realities and this current political climate pose substantial risks to cross-border cooperation because the very nature of cross-border cooperation requires compromises.

With their heavy reliance on U.S. markets Canadian oil producers are closely following any the potential changes in the USMCA prior to ratification, and to the other agreements between the two nations. U.S. posturing or actual policy changes may drive Canadian producers to seek markets further afield and may put strains on the previously cordial and collaborative relationship. There has been substantial investment in cooperative pipelines and agreements between the two nations in the past52 and current U.S. policy could threaten the prospective success of these ventures.53 Two Countries Four Goals The U.S. and Canada have juxtaposing goals both within and without of their borders. Canada seeks to expand its energy market but has also been vocal about how they seek to curtail the use of fossil fuels. The current U.S. administration has stated its goal of U.S. global energy dominance as well as total energy independence, while they may not sound like outwardly competing goals if the energy dominance is treated with a myopic perspective it could serve to alienate existing trade partners and impede domestic production growth.

Promotion of international energy industry cooperation will facilitate the exploitation of the expansive energy resources in both nations. In order to foster this cooperation, the current administration should take a more affable approach to amending existing and proposing new North American trade agreements. Neighborly cooperation may not be an easy sell in the immediacy, but all sides will reap the long-term benefits of increasing cross border collaboration. Promotion of cooperation may also alleviate some of the current “us against the world” rhetoric that has risen to the surface in the election of both nations’ leaders.

Domestically, the Canadian government has continued to pursue options for reducing greenhouse gasses and remained committed to the Paris Agreement, 54 which the U.S. has currently withdrawn from.55 In 2012, Canada launched its Responsible Resource Development (RRD) 46

program 56 which is intended to take a wholistic approach to resource extraction. A key provision in the program is the strengthening of environmental protections by increasing scrutiny for large scale projects which could pose substantial impact to the environment and imposing serious financial penalties for noncompliance.57

environmentally conscious exploitation of the existing resources. The bilateral dependence on each otherâ&#x20AC;&#x2122;s energy markets means that despite political rhetoric there is a deep need for both nations to cooperate going forward if they intend to continue current economic growth. However, the recent increased polarization of the political climate and the slightly divergent outward objectives of both nations means that there will likely be some substantive changes in future. The fact that the Canada is marginally more reliant on exports to the U.S. than the U.S. is on sales to Canada,62 coupled with the substantial investment in transnational pipelines63 means the U.S. has some leverage in proposing or implementing these changes. However, the unfavorable global reputation enjoyed by the current U.S. administration might result in some recalcitrance on the part of the Canadians.

The RRD also includes provisions for enhancing Aboriginal consultation on energy projects that would impact Aboriginal communities.58 Cross border pipelines have been beneficial for both nations by allowing more economical transportation of energy resources, however there has been recent political push back in both nations for increasing this energy infrastructure. 59 The slow pace at which the pipeline infrastructure is developing is preventing Canada from properly exploiting their oil sands reserve in the Brakken shale and enabling this crude to reach refineries in the Gulf Coast.60

The USMCA is Will Not Rock the Boat

This juxtaposition of political motivation to reduce consumption of fossil fuels and a healthy reliance on the cross-border energy trade presents novel issues for the perennial partners. The Canadian government has committed itself to a carbon pricing scheme that will likely adversely impact the desirability, or at least the market competitiveness, of Canadian oil in the U.S.61

The USMCA is rather tepid with regard to U.S.-Canada energy relations and does not move the needle very far in any direction. This mild approach to energy trade reflects the difficulty of reconciling both nations internal and external energy goals. The agreement does have some important revisions to the older NAFTA energy policies but is still rather limited when dealing specifically with any updates to NAFTA regarding the Canadian-U.S. energy relationship. 64 The agreement actually removes the NAFTA chapter on energy but supplements with individualized provisions that deal with specific issues. 65 The agreement includes some safeguards for U.S. oil companies but does not deal substantively with any cooperative increase in egress pipelines for Canadian oil sands production or LNG. 66 The agreement retains the state-to-state dispute resolution mechanism for many of the disputes that may arise under the agreement.67

The current U.S. administrationâ&#x20AC;&#x2122;s goals of total energy independence and U.S. energy dominance may prove to be at odds. By isolating their interests from those of the U.S.â&#x20AC;&#x2122; oldest and most readily accessible energy trading partner, the administration is directly impairing the potential for greater growth based on a cooperative and collaborative relationship with Canada. Canadian bifurcation of its dual goals of increased environmental regulation and increased domestic energy production are also bound to impair their ability to accomplish either. Both nations would fare better by recognizing that moderating rhetoric and expectations would yield a more sustainable yet fruitful energy future. Cross border economic and educational collaboration presents the best opportunity for the U.S. and Canada to continue to grow its energy sectors and for both to examine the best practices and yield the most efficient and

While the binational dispute mechanism will remain in place it will eliminate the investor-state dispute settlement (ISDS) for Canada once NAFTA is terminated.68 There has been a number of proposals for harmonization and integration of national policies on both sides by research groups, but so far there has been a lack of concerted effort 47

to implement these policies. 69 While still fledgling, the USMCA has provisions within that appear to heavily favor U.S. companies and limit both Canadaâ&#x20AC;&#x2122;s and Mexicoâ&#x20AC;&#x2122;s opportunity to seek trade agreements with other nations.70

and Iran. The use of sanctions is the strongest form of policy controls that the U.S. government can place on the energy sector and recently the U.S. has been liberally applying this mechanism with regard to both countries.74

The agreement is also limited by its sixteen year sunset clause, which is triggered if no satisfactory renegotiation can be reached before the deadline. 71 The USMCA will however maintain the current working relationship between the two nations72 and this alone will more easily facilitate future collaboration, unless the parties decide the agreement has divested them of previous power or authority which will serve to backslide progress.

The U.S. has recently imposed substantial financial sanctions against Venezuela. The reimposition of previous sanctions and implementation of new sanctions however does not seem to have global support, though, which may make it difficult for the U.S. to proceed. 75 Iran and the U.S. have been at odds for decades and only recently has there been any substantive positive change in this relationship. 76 However, the current U.S. policies are dialing back recent progress in an effort to secure more favorable terms for the U.S.

As it stands without greater cooperation the industry at the border will stagnate and be less capable of meeting the growing global need for U.S. and Canadian energy resources. Good fences may make good neighbors, but recognition of mutual dependence is the better solution to the current policy demands. The threat of international competition is ever-present 73 but if the U.S. and Canada could continue to foster mutually beneficial and benign trade agreements both countries would be better able to withstand the recurrent energy market fluctuations. It is critical that the both nations understand the symbiotic realities of their energy industries and that greater cooperation would only serve to fortify their respective growth potential. Like with Mexico the U.S. should promote cross border development and transportation to help insulate the nation from market variances and overseas competitors. By building a strong North American energy trade the U.S. will not only help safeguard its desired energy dominance it will facilitate their ascension to this dominance. More importantly, if framed as North American energy dominance the stated, yet partially conflicting, objectives of both nations will be more readily attainable.

Venezuela is a country on the brink of collapse due to gross mismanagement 77 and recent U.S. sanctions.78 While the nation is one of the most resource rich in the world, they have floundered under their administration of the nationalized oil fields. 79 The country has suffering from hyperinflation80 since October and is the first oil producing nation ever to do so. 81 In the past, Venezuela has benefited from a favorable relationship with the U.S.,82 but current domestic policies have brought the countries at odds once again. U.S.-Iran: Rocky Recent Relations The U.S. and Iran have not seen eye to eye on energy or other policies in over a generation. 83 Following the rise of fundamentalist Islam in Iran and the collapse of the formerly friendly, U.S. backed, regime of the Shah, the U.S. and Iran have been directly at odds geopolitically.84 There is bad blood on both sides due to U.S. intentional interjection into Iranian politics and the Iranian governments actions following the transition to the current government.85 This does not change the fact that Iran has substantial oil and gas reserves86 and is eager to exploit them to spur economic growth within the nation.

IRAN AND VENEZUELA

Previously, sanctions backed by both the U.S. and a large international community, have been successful in compelling Iran to agree to limit certain domestic military goals in exchange for more access to global energy markets. what can be

The current U.S. administration has pulled out of a deal with Iran, which was agreed to under the previous administration. This has impacted both global oil prices and the potential for future improvement of the relationship between the U.S. 48

commercial aircraft to Iran.97 Direct importation of Iranian oil to the U.S. remained prohibited following the JCPOA but it did not prohibit the overseas exchange of Iranian oil.98

a risky market. However, recent dramatic shifts in the U.S. policy regarding Iran has hampered previously obtained concessions and threatens to militate the potency of future sanctions.87 In 2015 the Joint Comprehensive Plan of Action (JCPOA) was agreed upon by the five permanent members of the UN Security Council and Germany.88 The deal provided for easing sanctions imposed on Iran in exchange for an agreement from Iran to severely restrict their nuclear development program.89 It is the JCPOA which the current U.S. administration has withdrawn from.90

The U.S. also allowed for certain waivers for Iran to obtain shipping insurance for its exported oil from U.S. firms, which is crucial for their ability to increase production.99 These and many more sanctions will be reinstated by the current U.S. administration, unless there is some future agreement between the two nations. The fact that this agreement would likely take the form of another executive order does not provide security to businesses who would pursue projects in Iran.

Sanctions: When to Cry Wolf The U.S. has a long history of sanctioning Iran and has used this history to achieve some substantive gains, with the help of multilateral negotiations. The international conglomeration used the prospect of easing sanctions as bait to have Iran agree to scale back their nuclear ambitions, namely the pursuit of nuclear weapons.91 These recent gains have come under fire by the current U.S. administration as being too consolatory and ineffective.92 This yo-yo policy regarding the JCPOA by the U.S. threatens to both isolate the nation as well as sterilize the effectiveness of imposing sanctions beyond merely the penal result.

â&#x20AC;&#x153;With the EU, Turkey, China, and India openly stating they will not enforce the new sanctions the U.S. stands as the odd man out despite its expansive global economic presence. This isolation could serve to weaken the effectiveness of current and future sanctions, by forcing the U.S. between an economic rock and a hard place.â&#x20AC;? The renewal of sanctions however lacks the previous near unilateral support from other Western powers. 100 The first round of renewed sanctions went into effect on August 7, 2018, and the Iranian government has not swayed in the face of them.101 Further complicating the issue is that the renewed sanctions lack the support of the former multinational embargo group. 102 The sanctions are intended to block out anyone who violates them from U.S. markets.103

The JCPOA is not an executive agreement or a treaty and is not a signed document 93 and while originally seen as a novel solution to the problem of requiring a specific ratification process, the fact that is it not has opened the door for the current U.S. administration to walk back the U.S.â&#x20AC;&#x2122; prior commitments. Because of this the roll back of the U.S. sanctions was done through executive order94 and President Trump was able to undo U.S. participation by issuing a presidential memorandum95 and additional executive order to that effect.96

However, with the EU, Turkey, China, and India openly stating they will not enforce the new sanctions the U.S. stands as the odd man out despite its expansive global economic presence.104 This isolation could serve to weaken the effectiveness of current and future sanctions, by forcing the U.S. between an economic rock and a hard place. If indeed other major economic powers refuse to enforce and even violate the U.S. sanctions the U.S. must either alienate existing trade partners or walk back its rhetoric. Neither solution would benefit the efficacy of the imposition of sanctions going forward.

However, before the current U.S. administrations move to reinstate the sanctions removed by the JCPOA, Iran was presented with a large number of incentives to abstain from its pursuit of producing nuclear weapons. U.S. banks and banks which operated under U.S. jurisdiction were allowed to extend lines of credit to Iran also Iranian luxury goods were allowed to be imported into the U.S. and the U.S. authorized sale of 49

International sanctioning has historically been difficult in regard to accurately delineating objectives and means by which the sanctions will accomplish those objectives. 105 Sanctions have clearly been effective for imposing punishments and restrictions but compelling a nation to act through sanctions has generally proven elusive.106 This problem has been present both in the implementation and removal of sanctions against Iran.107 The restrictions imposed by the sanctions were tangible enough and effective enough to compel Iran to the table however, the removal of those sanctions has had a dramatically less tangible effect in the last three years.108

prohibition on refined energy products exported from a foreign nation that may have utilized Iranian oil to produce those refined product. 117 This is because the refined foreign oil is treated as a product of the refining nation and not that of Iran. 118 The foreign refinement exception notwithstanding, virtually all energy sanctions which may have been eased under the JCPOA were reinstated on November 4, 2018.119 One of the most potent sanctions implemented against Iran has been the Iran Sanctions Act (ISA) of 1996, which included a comprehensive sanction scheme for businesses and banks engaging in energy transactions with Iran.120 The ISA had long been used to either actually sanction nations or private actors who engaged in energy related transactions with Iran or to threaten sanctions to those who propose to do so.121

Private industry is reticent to engage with Iran because of a perception that the JCPOA adjustments are not on a firm enough foundation to would allow them to rely on and expand into Iran and avoid negative repercussions in the future.109 These concerns have shown themselves to completely justified by the U.S.’ withdrawal from the JCPOA and reinstatement of certain sanctions against Iran.110 The U.S. has currently withdrawn certain sanctions on the exportation of Iranian oil, however they have retained specific financial sanctions which cause private industry to view transactions with Iran as high risk due to the very real potential of fines or other adverse impacts for their U.S. business. 111 This uncertainty has stifled much of the potential Iranian growth following the signing of the JCPOA.

The JCPOA allowed for the rolling back of a myriad of sanctions for entities seeking to transact with the Iranian energy sector and provided at least the opportunity for the Iranian energy industry to be allowed to expand rapidly. 122 The planned tiered reinstatement of sanctions by the U.S. will effectively end any energy sanction roll back and any nation or business who violates the sanctions will be susceptible to a number of fiscal and punitive measures.123 This will dramatically limit or even prohibit their ability to do business within the U.S. or with U.S. companies.124 The planned reinstatement of all the ISA sanctions lacks international support but if implemented will still likely be followed by all but the most maverick of energy operators.125

The ongoing stated objectives of U.S. sanctions in Iran has been to try to compel Iran to cease its support of terrorism and, more generally, to limit their strategic power in the region.112 The current administration does not believe the JCPOA was sufficient to accomplish these objectives and has used this as the justification for the “snapback” of sanctions. 113 The JCPOA did not however facilitate any direct energy trade with the U.S.114 In fact, all energy trade between the U.S. and Iran is still expressly forbidden.115 There is a policy in place for U.S. companies to apply for licenses to “swap” Caspian Sea oil with Iranian oil however in practice this licensing provision has proven to be a functional ban as well.116 This ban does not attach to all the in situ Iranian oil (oil extracted from within the nation of Iran) because there is no

The apparent efficacy of the sanction reinstatement should not be misconstrued as a victory, however. While there is a real likelihood that, through attrition, the reinstatement could result in better terms for the U.S. objectives within whatever replaces the JCPOA, it will inevitably work more harm than good for any subsequent arrangement. By disavowing the previous administrations commitments, the current administration has demonstrated that postagreement transactions with Iran are incredibly high risk and will be subject to political whimsy rather than tangible market factors. 50

This ample application of vinegar will not draw much business to the honey pot that is the Iranian energy reserves. Instead, the recent fickle relationship between the U.S. and Iran will continue to prohibit proper exploitation of Iranian resources which could otherwise provide ample growth for both nations.

the nation not seeing an economic return on its production that in any way mirrors its neighbors. 131 Iran’s refinement capacity is dramatically inadequate compared to its domestic needs.132 The nation is importing around 61,000 barrels per day of refined gasoline to meet its own needs. 133 So, despite the potential to be a hydrocarbon superpower Iran has been hamstrung by sanctions and obsolete technology. 134 These factors all contributed to Iran’s agreeing to specific terms of the JCPOA regarding its nuclear ambitions. However, the current administration was not pleased with the scope of the concessions and has redrawn sanctions in an effort to force Iran back to the negotiation table.135

Prosperity Fosters Peace When people are dependent on one another for their success there is a substantially reduced likelihood that grievances will boil over into intractable situations. Rather, when there is a codependence then more often than not an amiable solution is sought to maintain the relationship. This was the concept behind the European Common Market, which has at the very least been successful in ending the vast majority of the perennial inter-state conflict pervasive throughout Europe since the fall of Rome. It is this same type of codependence that could usher in a new era of quite in a region of the world desperately lacking in moderate voices. With U.S. and Western guidance Iran could become a prosperous while also moderating some of its more aggressive rhetoric.

The antiquity of Iranian energy 136 infrastructure could provide unique opportunity for many U.S. firms to enter the Iranian market and see sustainable profits from proven reserves that have not been exploited due to the history of acrimony between the nations. There are certainly undeniable ideological disputes between the U.S. and Iran which provide for impasses in a cooperative relationship. The European Common Market, however, is proof that economic cooperation can be a substantial driving factor for positive change. This ripsaw policy of reinstating sanctions also serves to diminish U.S. bargaining power globally, because while the promise of easing sanctions may bring a nation to the bargaining table the real possibility of a perfidious resolution means that other actors will be hesitant to rely on any agreements reached at these negotiations. It is important for the U.S. to curb the current fairweather policy with Iran and hold fast to a concrete approach. This approach should be the easing of energy trade restrictions in order to promote a stronger domestic energy sector while still maintaining tangible influence in the region. By allowing U.S. energy businesses to operate in Iran, even under heavy regulations, the U.S. would be able to manipulate the Iranian economy in ways that would be substantially more compelling than relying on the outdated sanction methods.

“The antiquity of Iranian energy infrastructure could provide unique opportunity for many U.S. firms to enter the Iranian market and see sustainable profits from proven reserves that have not been exploited due to the history of acrimony between the nations” Iran has some of the globe’s most mature oil fields, with 80% of known reserves being discovered before 1965. 126 These fields have provided Iran with its domestic energy needs and when possible the potential to export oil and gas.127 Western and U.S. sanctions have pushed Iran to do business almost exclusively with China and Russia. 128 The sanctions have limited Iran’s capacity to modernize its aging infrastructure which limits the nation’s output potential. 129 Also, domestically Iran has a substantial demand for the refined oil it produces.130 This is coupled with historic government subsidies to domestic consumers for the refined oil and has resulted in

A nation’s policy is more easily influenced when there is substantial risk to its domestic economy than when it is threatened with punishments it has grown accustomed to. Iran has 51

potential substitute 150 the infrastructure is still insufficient to make transportation of the resource a viable alternative to the ready availability of Venezuelan crude.151

been facing a growing push for modernity and moderation and agreeing to the JCPOA was a response to this pressure.137 By injecting itself into the Iranian economy the U.S. and other Western nations could be influential in the evolution of Iran. If the current administration allowed U.S. energy businesses to build a foothold in the Iranian market the U.S. would have greater regional influence and the economic prosperity generated within Iran would mitigate the extremism that many U.S. administrations have sought to curtail.

Cui Bono It is against this codependent backdrop that the current U.S. administration’s sanctions were imposed. The sanctions were narrowly tailored,152 and it could be argued were intended to be mostly benign. 153 The August 2017, sanctions were targeted exclusively at U.S. entities and some companies have been granted waivers from enforcement. 154 The sanctions, as of now, have been aimed at restricting U.S. investors from investing in Venezuela’s markets going forward. 155 There has been speculation that the sanctions are a mechanism to allow certain foreign and U.S. operators to take steps they were already intending to take but now are “compelled” to under U.S. trade policy. 156 The Venezuelan president Nicholas Maduro has struggled to combat the deepening problem and has turned to dramatic measures both fiscally and politically in an effort to stop the bleeding.

Venezuela: The Draining Hourglass: Like Iran, Venezuela has the potential to be an energy superpower, more specifically it has the resources to be most economically influential nation in the Southern Hemisphere and even all of Latin America. However, resource mismanagement and the civil unrest that it has produced has served to drive the country to the brink of a failed state.138 Terms like humanitarian crisis and economic disaster have been the norm to describe the state of affairs in Venezuela in the last few years.139 Since 2013, Venezuela has seen a more dramatic economic decline than the U.S. did during the Great Depression. 140 Due to historic and ideological disagreements the U.S. has avoided providing assistance to the foundering state.141

Sanctions limiting U.S. imports of Venezuelan crude would likely disadvantage many U.S. refineries, particularly those in the Gulf and East Coast regions, that have optimized to utilize the sour heavy crudes produced in Venezuela. 157 Restricting the supply of crude could also impact the price that U.S. consumers and businesses pay for their fuel.158 The Venezuelan citizens would also be negatively impacted by U.S. importation sanctions as Venezuela would have to seek out markets further away and likely discount their prices to offset costs and market uncertainty due to the sanctions. 159 Further, additional sanctions could potentially have a more detrimental effect on the U.S. rather than Venezuela because as an exporter of crude Venezuela can sell to whomever while Gulf and East Coast refineries, which have been specially designed to refine heavy crude, would need to fill the void with a specific commodity. 160 This lack of flexibility on the refinery side means that the immediate impact of the sanctions would be detrimental to both nations and drive up U.S. domestic fuel costs.

Venezuela’s oil production is in near free fall and its GDP is at a 60-year low.142 The national oil company, Petroleos de Venezuela SA (PdVSA), has soured its relationships with foreign operators by consistently not living up to agreements 143 and U.S. sanctions have compounded the company’s woes by restricting foreign companies’ ability to lend money to PdSVA. 144 As a result many foreign operators have withdrawn in part or in whole from their involvement with PdSVA.145 The result has been a treacherous decline in production from Venezuelan oil fields. 146 This decrease in production does not impact Venezuela in a vacuum.147 The nation is the largest supplier of heavy and extra-heavy crude in the Gulf of Mexico and many of the refineries in the Gulf of Mexico148 are configured to refine this specific type of crude. 149 The production shortages will very likely impact the bottom line of refineries in the U.S. And while Canadian heavy crude could be a 52

The financial sanctions recently imposed on Venezuela have however, been designed to not interfere with ongoing U.S.-Venezuela energy transactions. Rather, their intent is to prohibit U.S. and other firms from future investments in Venezuela. 161 The sanctions may serve to expedite what appears to be Venezuela’s inevitable default, 162 which would affect many U.S. investors who hold Venezuelan government bonds.163 Fallout from a Venezuelan default could result in seizure of Venezuelan assets in the U.S., such as those held by Citgo which is majority owned by PdVSA. 164 Asset seizures would compound the market instabilities brought about by a default. Venezuelan instability and sanctions threaten large portions of the U.S. energy market 165 and there are currently not any easy solutions or firm proposals to handle the continuing crisis in the region.

believe that the move is simply a stunt at best and a sanction work-around scheme at worst.173 At the moment President Maduro is still hailing the Petro and a viable and functional currency.174 This is despite the fact that the Petro was declared an illegal currency by the Venezuelan Congress.175 While a nationally sanctioned cryptocurrency with backing from tangible resources would be a financial revolution, all indications appear that it will only be another in a long list of failures for the Maduro regime as Venezuela marches quickly towards total collapse. Recently the value of the Petro to the Bolivar has quadrupled but this is only an illustration of how poorly the Bolivar is doing.176 The Maduro government has pinned the value of one Petro at sixty U.S. dollars, however experts, economist, and rating agencies all label the Petro as a scam.177 The imposition of new sanctions, which are arguably geared to provide U.S. interests a convenient out from a crumbling economy, and the shell game economics being pursued by the Maduro regime do not seem to alleviate the myriad of problems facing the nation of Venezuela. These measures do seem to have overtly self-serving ends for those proposing them, however. The espousal of these self-interested agenda will continue to feed the flames that are devouring the country and its economy, and without any real international oversight the future of Venezuela will remain bleak.

The Bolivar, Venezuela’s national currency, is currently experience exponential inflation. International Monetary Fund (IMF) estimates put consumer price inflation at about 1,000,000 percent by the end of 2018. 166 While the U.S. sanctions are not wholly responsible for this spiraling inflation, they certainly are a contributing factor. In an effort to provide Venezuela access to global financial markets President Maduro has enacted dramatic and novel approaches to stop the bleeding. The Venezuelan administration raised the national minimum wage by 3,000 percent in September in the hope that those with jobs would be able to earn enough to jump start the economy. 167 Thus far the wage hike has done nothing but put greater pressure on employers.168 The country has also taken the unprecedented step of establishing the first nationally recognized and physical resource backed cryptocurrency, the Petro.169

The Truth We All Know but Agree Not to Talk About: There is certainly nothing simple with the crisis in Venezuela, but the unavoidable fact is that the nation is an energy giant, especially in the Western Hemisphere. The current U.S. approach all but amounts to putting its head in the sand. The U.S. Gulf Coast refineries have become nearly dependent on crude from Venezuela and would be hard pressed to replace this source if it evaporated.178 A Venezuelan economic collapse will palpably impact the U.S. energy markets and energy markets globally. The sad reality of the human rights abuses and national mismanagement severely restrict the desire for most Western nations to send aid to the country.179 Aid in almost any fashion will likely be appropriated by the

In what appears to be more of scam than an actual currency Maduro has set up the Petro to be backed by specific Venezuelan oil reserves and intends it to be a free method for financial exchange.170 Many see this as a means to avoid U.S. imposed financial sanctions and while the currency has only been “online” for a “pre-sale” the move does not show signs of success.171 The Petro was available for public “pre-sale” purchase on February 20, 2018172 but most industry experts 53

Maduro regime and used to bolster their diminishing position of power. To date there has not been much consideration given to the Venezuelan crisis and its eventual impacts on the U.S. and because of this the current administration has put forth very few potential remedies. Outside of proposing new sanctions the U.S. policy has offered few other solutions. Venezuela is an unattended house fire in the current global turmoil, but a U.S. led multilateral solution could potentially interrupt what is becoming a global crisis.

Venezuela will require similarly unprecedented actions to mitigate the crisis but without radical action Venezuela will continue to deteriorate and this will progressively impact U.S. and global energy markets negatively. The international community is clearly hesitant to use anything other than paper, especially with the interventions in the Middle East still ongoing. This paper policy has up to now proved ineffectual for even slowing the rapid decline of Venezuela, yet the concomitant international agreements persist in the face of their intangible results. There are few alternatives to stymie the continuing crisis in Venezuela and silent complacency is only prolonging the harm. There is an understandable reticence in the international community to take such proactive steps, but idle observation and halfhearted sanctions will not rectify this disaster. Venezuela is a major player in the international energy market, despite its current state of disrepair, and the international community would do well to correct the problem now before it reaches it inevitable disastrous climax.

Outright intervention may be the only solution to the problems facing Venezuela, this in an option that does not enjoy much, if any, support in U.S. or internationally. However, the situation in Venezuela has been allowed to fester for too long and their energy reserves are integral to continued U.S. economic growth. Without a multilateral approach to the legion of issues in Venezuela the nation will continue to charge towards a total collapse. There is a real risk that Venezuela will become a failed state within a decade and global willful ignorance will only serve to turn this risk into a reality. A resource rich failed state would pose much greater risks than simply increased oil prices for U.S. refineries. This is not to say Venezuela will resemble present day Syria but the prevalence of international criminal activity in South America and a failed Venezuela would send ripples through all of Latin America.

THE HORIZON OF NORTH AMERICA The current tack of the U.S. administration’s policy may produce immediate but moderate gains however, a comprehensive and forward-thinking strategy of planned cooperation will yield longer and more sustainable success. The USMCA, while not presently ratified, falls short of creating policies which would realize the potential level of growth present in the North American energy industry. Mexico’s new president, AMLO, will inevitably provide push back to many of the U.S.’ policies but it is imperative that the U.S. administration work with and impress upon him the need for bilateral cooperation.

Therefore, in order to preserve the stability that many other South American nations have seen in recent years it is imperative for the U.S. to champion measures designed to correct Venezuela’s current course. Imposing additional sanctions will not be the most effective mechanism to stop Venezuela from drowning. Rather, direct intervention with a multilateral backing seems likely the only way that Venezuela will avoid total collapse. The current administration may not have sufficient political capital to lead this push, but a proactive policy of intervention could yield broad improvements to both Venezuela and the U.S. Opening dialogue between North Korea and the U.S. was seen as a near impossibility at the beginning of this century however the current administration was able to bridge the divide and even host Kim Jong-Un at the White House.

“The current tack of the U.S. administration’s policy may produce immediate but moderate gains however; a comprehensive and forwardthinking strategy of planned cooperation will yield longer and more sustainable success.” The two nations are dramatically aligned in energy goals and have interconnected markets. A unified U.S.-Mexico energy sector could facilitate 54

better regional negotiation and foster prosperity among all Latin American energy producers.

capable of being resolved by long term change and require more direct approaches. The current administration may have a difficult time persuading the more timid nations to inject themselves into a crisis zone but never the less an ounce of intervention is worth a pound of protracted civil war.

Canadian and U.S. interdependence is a driving factor for why the USMCA, or its successor, must provide for comprehensive energy policy that takes into account both nations immediate and long-term goals. Canadian political motivation to decrease greenhouse gas emissions and U.S. pursuit of energy dominance could serve as balancing principals rather than stumbling blocks. A bilateral agreement to use best practices to access untapped resources and a cooperative agreement for distribution of those resources would allow Canada to convert much of its oil and gas into marketable goods which could be sold to the U.S. or with U.S. cooperation globally. By collaborating the two countries could work to more efficiently exploit resources while at the same time mitigate the risks inherent in the extraction of minerals, especially in the remote regions of the two countries.

Iran has produced oil as long as mankind has produced oil, but decades of disquiet both internally and externally have left the nation in the energy producing past. The U.S. could craft agreements that would allow Iran to slowly modernize, with U.S. energy actorsâ&#x20AC;&#x2122; assistance, and thereby burrow U.S. interests into Iranian ones. Western Europe spent the first third of the 19th century in the most violent conflicts the earth has ever seen but the Treaty of Rome effectively arrested inter-state violent conflicts by the beginning of the 21st century. If U.S. policy could similarly develop an interdependence within Iran there is a viable chance that Iran would become more moderate and work towards being a regional collaborator that could help stabilize one of the most unstable areas of the globe. It has long been shown that prosperity has a moderating effect on a population and despite the fact that the U.S. and Iran are nearly diametrically opposed ideologically, a long-term policy of cooperate and regulated growth would yield better results than continued begrudging and vacillating agreements.

The U.S. should focus on North American energy dominance rather than strictly U.S. energy dominance because as the nations with most developed energy infrastructure, what is good for the gander will be good for the goose. Through trilateral cooperation the North American energy industry could easily become the most influential actor on the globe. This position of strength could facilitate both economic growth and international stability. A unified North America would rival OPEC for primacy in the global energy would further strengthen U.S. bargaining power with regard to a myriad of international issues. This influence could help project all the nations of North America into a lasting position of economic stability.

There is little doubt that the crisis in Venezuela is dire and almost actively ignored by the international community. Currently no nation or international organization has a comprehensive plan for mitigating this crisis. This dearth of resolutions places the U.S. in a unique position to take the torch and dictate conditions that could alleviate some of the more dramatic potential consequences of this instability. Through direct multilateral intervention the U.S. could protect its own interests, which are inexorably linked to Venezuelan energy production. Without intervention the world will sit by and watch Venezuela collapse in on itself and become a hot bed for unrest that will likely drag surrounding nations down with it. A failed Venezuela will undo the strides made in Columbia and will likely foster a new era of South American violence and increased corruption. As unpalatable as it is, direct

On Course for Conflict The policy of punishment wrought through sanctions poses more a risk to the global economy and global security than a policy of promoting economic cooperation. Thus far U.S. sanctions have been effective at impoverishing nations and fanning the flames of discourse. By allowing U.S. energy markets access to underdeveloped areas the U.S. could greatly expand its influence in regions that have been slow to change under the whip of sanctions. However, certain situations are not 55

action is the likely the only solution to Venezuela crisis. This is a drastic solution, which may face staunch anti-interventionist sentiments globally but without drastic action to correct its current course the future of Venezuela seems destined for complete collapse.

for global energy production which could pave the way for a substantially more sustainable global energy market and future. Without cooperation however, the global energy market will remain susceptible to political whims and the tune will remain the same. The underutilization and inefficient exploitation of the current energy resources will continue and limit the potential for a timely solution to the impending production issues of this century. Collaboration with a steady eye to the future is the best possible alternative for the global energy market and would produce the greatest benefit to all energy producing nations as well as facilitate methods for more effective resource recovery and regulation of those resources.

U.S. energy policy too closely resembles the previous decade’s foreign policy with an emphasis on might makes right and a disregard of diplomacy. Without forward thinking collaboration the U.S. and the globe will miss the opportunity to properly expand its energy markets and lose out on a potential to foster sustainable growth paired with increased global stability. Through cooperation, even if marginal in some regions, the U.S. could help establish a new model 1

Jason Bordoff, Trump’s Iran Policy is Blowing up his Energy Agenda, FOREIGN POLICY (May 10, 2018), https://foreignpolicy.com/2018/05/10/trumps-iran-policy-isblowing-up-his-energy-agenda.

agreements/united-states-mexico-canadaagreement/agreement-between. 9

M. ANGELES VILLAREAL & IAN F. FERGUSSON, CONGRESSIONAL RESEARCH SERVICE, NAFTA AND THE PRELIMINARY U.S.-MEXICO AGREEMENT 3 (2018).

Francisco Monaldi, The Death Spiral of Venezuela's Oil Sector and What Can Be Done About It, FORBES (Jan. 24, 2018), https://www.forbes.com/sites/thebakersinstitute/2018/01/24 /the-death-spiral-of-venezuelas-oil-sector-what-if-anythingcan-be-done-about-it.

PAUL K. KERR & KENNETH KATZMAN, CONGRESSIONAL RESEARCH SERVICE, IRAN NUCLEAR AGREEMENT AND U.S. EXIT 25 (2018). 11

See generally REBECCA M. NELSON, CONGRESSIONAL RESEARCH SERVICE, VENEZUELA’S ECONOMIC CRISIS: ISSUES FOR CONGRESS (2018).

Todd Moss & Rob Mosbacher, Jr., Congress Gives US Energy Diplomacy A Turbocharge, FORBES (July 20, 2018), https://www.forbes.com/sites/

Elisabeth Malkin, U.S. Delegation and Mexico’s Next President Aim to Reset Relations, N.Y. TIMES (July 13, 2018), https://www.nytimes.com/2018/07/13/

thebakersinstitute/2018/07/20/congress-gives-us-energydiplomacy-a-turbocharge/#49b0d5a93883.

world/americas/mexico-lopez-obrador-pompeomnuchin.html?rref=collection%2Ftimestopic%2FL%C3%B 3pez%20Obrador%2C%20Andr%C3%A9s%20Manuel&ac tion=click&contentCollection=timestopics&region=stream &module=stream_unit&version=latest&contentPlacement= 5&pgtype=collection.

Rick Perry, Ryan Zinke, & Scott Pruitt, Paving the Path to U.S. Energy Dominance, WASHINGTON POST (June 26, 2017), https://www.washingtontimes.com/news/2017/jun/26/usenergy-dominance-is-achievable. 5

Monaldi, supra note 2.

INT’L ENERGY AGENCY, ENERGY POLICIES OF IEA COUNTRIES: CANADA 2015 REVIEW 30 (2015) [hereinafter CANADA 2015 REVIEW].

Kim Tae-Yoon, WEO Analysis: A Sea Change in the Global Oil Trade, INT’L ENERGY AGENCY (Feb. 23, 2018), http://www.iea.org/newsroom/news/2018/february/weoanalysis-a-sea-change-in-the-global-oil-trade.html.

ANDREW STANLEY, CTR. FOR STRATEGIC INT’L STUDIES, MAPPING THE U.S.-CANADA ENERGY RELATIONSHIP 1 (2018)

A New Canada-United States-Mexico Agreement. GOV’T (Nov. 30, 2018), https://www.international.gc.ca/trade-commerce/tradeagreements-accords-commerciaux/agr-acc/cusmaaceum/index.aspx?lang=eng. OF CAN.

Adrian Duhalt, Despite Political Uncertainty, Mexico Lures Oil and Gas Firms, FORBES (Apr. 5, 2018), https://www.forbes.com/sites/thebakersinstitute/2018/04/05 /despite-political-uncertainty-mexico-lures-oil-and-gasfirms/#3f4114ed3085.

The Agreement Between the United States of America, the United Mexican States, and Canada, United StatesMexico-Canada Agreement [hereinafter USMCA], https://ustr.gov/trade-agreements/free-trade-

FRANCISCO J. MONALDI, BAKER INST. MEX. CTR., CTR. FOR ENERGY STUDIES, THE RULE OF LAW & FOREIGN INVESTMENT IN OIL 11–14 (2017).

17 18

Id. at 20.

Duhalt, supra note 15.

Id.

Blackmon, supra note 32.

INT’L ENERGY AGENCY, ENERGY POLICIES BEYOND IEA COUNTRIES: MEXICO 19 (2017).

Azam Ahmed & Kirk Semple, Mexico Elections: 5 Takeaways from López Obrador’s Victory, N.Y. TIMES (July 2, 2018), https://www.nytimes.com/2018/07/02/world/americas/mexi co-election-lopez-obrador.html.

Jason Bordoff & Tim Boersma, For Mexico, US Could Become the New Russia, CNBC (Feb. 6, 2017), https://www.cnbc.com/2017/02/06/for-mexico-us-couldbecome-the-new-russia-commentary.html. 21 22

Id.

STANLEY, supra note 14, at 6.

Id.

BP STATISTICAL REVIEW OF WORLD ENERGY JUNE 2014, at 7–8 (2014), http://large.stanford.edu/courses/2014/ph240/milic1/docs/b preview.pdf.

Glen Hodgson, Donald Trump’s Energy Policy: No Commitment to Canada, THE GLOBE AND MAIL (July 31, 2018),https://www.theglobeandmail.com/business/comment ary/article-donald-trumps-energy-policy-no-commitmentto-canada.

CLARE RIBANDO SEELKE ET AL., CONGRESSIONAL RESEARCH SERVICE, MEXICO’S OIL AND GAS SECTOR: BACKGROUND, REFORM EFFORTS, AND IMPLICATIONS FOR THE U.S. 18 (2015) [hereinafter MEX. BACKGROUND REPORT].

Id.

STANLEY, supra note 14, at 7. Id. at 11.

Id. at 12.

Id. at 12–13.

Id. at 13.

Id. at 19.

Id. at 13.

Duhalt, supra note 15.

RADOSLAV DIMITROV, THE PARIS AGREEMENT ON CLIMATE CHANGE: AN OVERVIEW & IMPLICATIONS FOR CANADA 6 (2018). 55

President Donald Trump, Statement by President Trump on the Paris Climate Accord (June 1, 2017), https://www.whitehouse.gov/the-pressoffice/2017/06/01/statement-president-trump-paris-climateaccord.

Lucina Melesio, Leftist Lopez Obrador Sworn in as Mexico President, AL JAZEERA NEWS (Dec. 1, 2018), https://www.aljazeera.com/news/2018/12/lopez-obradorsworn-mexico-president-181201070756989.html. 32

David Blackmon, AMLO Impacts Energy Markets Even Before Taking Office, FORBES (Aug. 27, 2018), https://www.forbes.com/sites/davidblackmon/2018/08/27/a mlo-impacts-energy-markets-even-before-takingoffice/#3f5fdb6f1643. 33

CANADA 2015 REVIEW, supra note 13, at 30.

Id.

STANLEY, supra note 14, at 7.

Id.

Dennis McConaghy, It’s Time for Clarity on Canada’s Climate and Energy Policy, MACLEAN’S (Feb. 9, 2017), https://www.macleans.ca/economy/economicanalysis/itstime-for-clarity-on-canadas-climate-and-energy-policy.

Id.

IAN F. FERGUSSON & M. ANGELES VILLAREAL, CONGRESSIONAL RESEARCH SERVICE, PROPOSED U.S.MEXICO-CANADA (USMCA) TRADE AGREEMENT 1 (2018).

STANLEY, supra note 14, at 2.

Id. at 2.

Id. at 7.

Id.

FERGUSSON & VILLAREAL, supra note 34, at 1.

Blackmon, supra note 32.

Id. at 2.

See generally USMCA

FERGUSSON & VILLAREAL, supra note 34, at 1. Id.

CLARE RIBANDO SEELKE, CONGRESSIONAL RESEARCH SERVICE, MEXICO: BACKGROUND AND U.S. RELATIONS 12 (2018). 39

Id. at 12–13.

Blackmon, supra note 32.

MEX. BACKGROUND REPORT, supra note 24, at 7.

ALAN J. KRUPNICK & RAYMOND J. KOPP, ATTAINING SUSTAINABLE DEVELOPMENT OF OIL AND GAS IN NORTH

AMERICA: A REVIEW OF THE ENVIRONMENTAL REGULATORY LANDSCAPE 14 (2014).

Benjamin Dynkin, Shifting from "Consent’' to Advice: Reimagining the Role of the Senate in Foreign Affairs, 18 CARDOZO J. CONFLICT RESOL. 133, 146 (2016).

Exec. Order No. 13716, 81 Fed. Reg. 3693 (Jan 16, 2016).

Blayne Haggart, NAFTA Has Been Replaced but at What Cost to Canada?, THE CONVERSATION (Oct. 1, 2018), https://theconversation.com/nafta-has-been-replaced-but-atwhat-cost-to-canada-104174; USMCA are 34.7. 71

USMCA art. 34.7.

FERGUSSON & VILLAREAL, supra note 34, at 2.

KRUPNICK & KOPP, supra note 69, at 1.

Presidential Memoranda, Ceasing U.S. Participation in the JCPOA and Taking Additional Action to Counter Iran’s Malign Influence and Deny Iran All Paths to a Nuclear Weapon (May 8, 2018) 96

Exec. Order No. 13846, 83 Fed. Reg. 38,939 (Aug. 7, 2018).

Richard Nephew, The Hard Part: The Art of Sanctions Relief, THE WASHINGTON QUARTERLY, Summer 2018, at 63–64.

Exec. Order No. 13716, 81 Fed. Reg. 3693 (Jan 16, 2016). 98

Id.

KENNETH KATZMAN, CONGRESSIONAL RESEARCH SERVICE, IRAN SANCTIONS 7 (Sept. 26, 2018).

Id. at 68–69.

Id. at 8.

Antoine Halff, Francisco Monaldi, Luisa Palacios & Miguel Angel Santos, Code Red: Venezuela’s Oil & Debt Crises, COLUMBIA CTR. ON GLOBAL ENERGY POLICY (Feb. 26, 2018), https://energypolicy.columbia.edu/ research/global-energy-dialogue/code-red-venezuelas-oiland-debt-crises.

100

Id. at 45–46.

101

STANLEY, LADISLAW & VERRASTRO, supra note 88, at 2.

102

KATZMAN, supra note 99, at 46.

103

Id. at 1.

CLARE RIBANDO SEELKE ET AL., CONGRESSIONAL RESEARCH SERVICE, VENEZUELA: BACKGROUND AND U.S. RELATIONS 28 (2018) [hereinafter VENEZ. BACKGROUND REPORT].

104

STANLEY, LADISLAW & VERRASTRO, supra note 88, at 2.

105

Nephew, supra note 73, at 64–65.

106

Id. at 63.

Halff, Monaldi, Palacios & Santos, supra note 77.

107

Id. at 65.

Id.

108

Id. at 69.

Id.

109

STANLEY, LADISLAW & VERRASTRO, supra note 88, at 6.

SEELKE ET AL., supra note 78, at 24.

110

Laub, supra note 92.

Nephew, supra note 73, at 66.

111

Id.

112

KATZMAN, supra note 99, at 1.

82 83 84

Gregory Brew, The Oil of Iran: Past and Present in Perspective, E-INTERNATIONAL RELATIONS (Jan. 19, 2016), https://www.e-ir.info/2016/01/19/the-oil-of-iran-past-andpresent-in-perspective. 85

Id.

113

STEPHEN P. MULLIGAN, CONGRESSIONAL RESEARCH SERVICE, WITHDRAWAL FROM INTERNATIONAL AGREEMENTS: LEGAL FRAMEWORK, THE PARIS AGREEMENT, AND THE IRAN NUCLEAR AGREEMENT 1 (2018). 114

KATZMAN, supra note 99, at 7.

115

Id.

116

Id. at 8.

ANDREW STANLEY, SARAH LADISLAW & FRANK VERRASTRO, CTR. FOR STRATEGIC INT’L STUDIES, IRAN SANCTIONS AT THE HALFWAY POINT 2 (2018). 88

Id.

117

Id.

Joint Comprehensive Plan of Action, July 14, 2015.

118

Id.

119

Id. at 10.

120

Id. at 11.

Exec. Order No. 13716, 81 Fed. Reg. 3693 (Jan 16, 2016). 91

Zachary Laub, The Impact of the Iran Nuclear Agreement, THE COUNCIL ON FOREIGN RELATIONS (May 8, 2018), https://www.cfr.org/backgrounder/impact-irannuclear-agreement. 92

121

Anwar Iqbal, Tough US Warning on Iran Gas Pipeline, DAWN (Mar. 1, 2012), https://www.dawn.com/news/699341/tough-us-warning-oniran-gas-pipeline.

Id.

154 122

STANLEY, LADISLAW & VERRASTRO, supra note 88, at 4.

123

Id.

124

Id. at 6.

125

KATZMAN, supra note 99, at 46.

SEELKE, NELSON, BROWN & MARGESSON, supra note 154, at 29. 155

REBECCA M. NELSON, CONGRESSIONAL RESEARCH SERVICE, NEW FINANCIAL SANCTIONS ON VENEZUELA: KEY ISSUES (SEPT. 1, 2017). 156

126

Fareed Mohamedi, The Oil and Gas Industry, U. S INST. (2010), https://iranprimer.usip.org/resource/oil-and-gas-industry

157

SEELKE, NELSON, BROWN & MARGESSON, supra note 154, at 34.

FOR PEACE PRESS: THE IRAN PRIMER, 127

Id.

128

Brew, supra note 84.

129

Id.

130

KATZMAN, supra note 99, at 69.

131

Brew, supra note 84.

132

Id.

Halff, Monaldi, Palacios & Santos, supra note 77, at 4.

158

Id.

159

Id. at 35.

160

Id.

161

Halff, Monaldi, Palacios & Santos, supra note 77, at 4–5.

162

NELSON, supra note 142, at 8.

163

Id.

164

133

Id.

SEELKE, NELSON, BROWN & MARGESSON, supra note 154, at 36.

134

STANLEY, LADISLAW & VERRASTRO, supra note 88, at 1.

165

135

Id.

166

136

Brew, supra note 84.

Marco Bello, Venezuela's Annual Inflation Hits 488,865 Percent in September, REUTERS (Oct. 8, 2018), https://www.reuters.com/article/us-venezuelaeconomy/venezuelas-annual-inflation-hits-488865-percentin-september-congress-idUSKCN1MI1Y6.

137

Parisa Hafezi, Rouhani Says Iran Not a Threat, Wants Interaction with World, REUTERS (Apr. 7, 2016), https://www.reuters.com/article/us-iran-rouhanimoderation-idUSKCN0X40IO. 138

Halff, Monaldi, Palacios & Santos, supra note 77, at 3.

139

Id. at 11.

167

Fabiola Zerpa, Venezuela Raises Minimum Wage 3,000% and Lots of Workers Get Fired, BLOOMBERG, (Sept. 14, 2018), https://www.bloomberg.com/news/articles/2018-0914/after-getting-3-000-wage-hike-workers-are-fired-invenezuela

140

REBECCA M. NELSON, CONGRESSIONAL RESEARCH SERVICE, VENEZUELA’S ECONOMIC CRISIS: ISSUES FOR CONGRESS 2 (JAN. 10, 2018). 141

Halff, Monaldi, Palacios & Santos, supra note 77, at 2.

142

Id.

143

Id. at 3.

144

Id.

145

Id.

146

Id. at 2.

147

NELSON, supra note 142, at 1.

148

Id. at 7.

149

Halff, Monaldi, Palacios & Santos, supra note 77, at 4.

150

Id.

151

Id.

168

Id.

169

What is Venezuela's New Petro Cryptocurrency?, AL JAZEERA NEWS (Mar. 23, 2018), https://www.aljazeera.com/news/2018/02/venezuela-petrocryptocurrency-180219065112440.html. 170

Timothy B. Lee, Venezuela Says its Cryptocurrency Raised $735 Million—But It’s a Farce, ARS TECHNICA (Feb. 22, 2018), https://arstechnica.com/techpolicy/2018/02/venezuela-says-its-cryptocurrency-raised735-million-but-its-a-farce/. 171

Id.

172

Rachelle Krygier, Venezuela Launches The ‘Petro,’ Its Cryptocurrency, WASHINGTON POST (Feb. 20, 2018), https://www.washingtonpost.com/news/worldviews/wp/201 8/02/20/venezuela-launches-the-petro-itscryptocurrency/?utm_term=.7e6175d6b4c5.

152

CLARE RIBANDO SEELKE, REBECCA M. NELSON, PHILLIP BROWN & RHODA MARGESSON, CONGRESSIONAL RESEARCH SERVICE, VENEZUELA: BACKGROUND AND U.S. RELATIONS 28–29 (June 27, 2018). 153

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173

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Sabrina Martín, Venezuela: The Laughable Launch of the Petro, Maduro’s New “Cryptocurrency”, PANAM POST

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178

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179

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Mitigating Political Risk for 21st Century Energy Projects By: Sean Berwald Recent STCLH Graduate Attorney with Toeppich and Associates

INTRODUCTION Political Risk Insurance supports oil and gas companies in guaranteeing that actions by governments, nationally owned entities, and terrorist organizations do not threaten the welfare of the company in a critical way when operating globally. The international energy industry has used a variety of different mechanisms to insulate itself from geopolitics and the whims of global disorder that have transformed the world through dozens of wars in the last two centuries. The nature of these large energy projects is that the risks of a failure in any single project could bankrupt a company. Such a catastrophe not only impacts the energy company, its employees, and all the support services of the energy company, but also the national economy of the country in which the project was located. The long-term sustainability and tax revenue associated with these larger projects often attract unwanted attention from overly ambitious governmental power players. Increasingly large revenue streams invite many governmental figures to distribute more to themselves than they would have otherwise received, often causing the project to become economically unviable. Political risk issues encompass all of these problems and the various mechanisms of protection will be detailed below. POLITICAL RISKS Political Risk Insurance (PRI) should only be used as a last resort, after every other form of protection and guarantee has been exhausted. Insurance limits, challenges of public relations, and the geopolitical tactics that are used on the international stage often make political risk insurance a solution of last resort for some major companies. One major contributing factor to the overall challenges with political risk is that only

7% of the global oil and gas market is freely accessible to energy companies, with 61% being controlled by host governments that severely limit international oil company participation. 1 The major concerns related to political risk insurance include expropriation (nationalization), possible currency inconvertibility/transfer risk, political violence, contract repudiation, and issues affecting export transactions.

Nationalization and creeping expropriation are often explained as the elimination of private ownership through state seizure of assets.2 Many countries believe this type of action is lawful but only if â&#x20AC;&#x153;it is undertaken for a public purpose, is not arbitrary or discriminatory, and is accompanied by prompt, adequate, and effective compensation.â&#x20AC;? 3 The brazen nationalization executed with the help of military forces or state police departments have become increasingly rare. But, examples from Russia and Venezuela in the 21st century consistently remind us that even the largest energy companies are at threat from governments that see energy production as a national security concern. Historically, the problem with outright nationalization was that most nations did not have the technical capacity to work the machinery necessary to supply the oil or natural gas from the project to the people and markets that needed it. The collapse and deterioration of high-quality projects often followed nationalization, leading to a slower form of nationalization that the industry calls creeping expropriation. The creeping expropriation present today hails back to the Saudi system of nationalizationâ&#x20AC;&#x201D; taking smaller percentages of a company project over its lifespan instead of doing it outright from the start. An important aspect of creeping

expropriation is that during exploration and initial production, an energy company injects resources into a country’s governmental system that the host government needs. However, once production is underway and there is less need for the energy company to inject capital or investment due to the revenue of the project itself, expropriation becomes more intriguing in the minds of some government advisors.4 This style of expropriation is expected to continue to expand and become more sophisticated.

This should be distinguished from currency risk, the risk of devaluation of a currency, as this is a commercial risk and not a political risk. The biggest question relating to the policy trigger is whether there was a legal right to convert the local currency into hard currency at the time of the policy. 6 This will be discussed in more detail through the Overseas Private Investment Corporation (OPIC) policy. The third risk is political violence, which includes war, revolution, insurrection, terrorism, and internal civil strife. The issue with this risk is often that its trigger is very explicit, and causation related to the act that resulted in the damage to property often is too far outside the scope of what is covered. This results in a loss by the energy company. Again, OPIC has a policy topic on this particular risk and defines political violence as “a violent act undertaken with the primary intent of achieving a political objective…”7 When political violence takes its toll on a project, it can take quite a long time to see an insurance claim protected due to limitations on access to evidence for a court or arbitration tribunal initially. However, most political violence claims in public or private insurance end up paying out because of the broader issue of a nation’s instability at a minimum.

Mechanisms using this type of expropriation often come in the form of taxation and regulations that make it impossible for the company to continue to operate a project. This results in the company giving the project to the host country for much less than its value. Energy companies often have to train nationals from the host country and employ many of the locals to fill most jobs for an energy project today. Through this advanced training, host country concerns of being unable to take over an energy project for the nation’s benefit through nationalization without production or efficiency loss is minimized. This has resulted in assets all over the world being gradually seized for the benefit of governments seeking independence from western energy companies and the strings that come with their presence.

The fourth risk is contract repudiation, or when a government fails to honor the terms of an agreement. Such a breach of contract would be commonplace in American litigation, but when working with other national governments, it often requires extra measures to ensure that the host country honors arbitration provisions, the arbitration awards, or tries to use fraud or duress to obtain a favorable national award at arbitration. These concerns can never truly be eliminated as risks, but they can be mitigated with contract repudiation insurance.

The second category of risk is currency inconvertibility and transfer risk. This risk comes from an investor’s “inability to convert local currency earnings into US dollars or other hard currency or an inability to remit hard currency out of the country to pay dividends…, loans…, or repatriated capital.”5

Lastly, political risks that affect export transactions have some unique triggers. There are four main triggers that impact export transactions. The first main issue is losses associated “with wrongful calling of bid, performance, advance payment, and similar guarantees…” 8 posted by sellers in favor of buyers. Second, is contract repudiation, embargoes, and revocation of import/export licenses. Third is default or nonpayment due to currency inconvertibility or 62

political violence. Last is losses due to confiscation of assets or damaged/nonpayment stemming from political violence.

The limited nature of the investment insurance agency guarantees that there will be issues and concerns that an energy company must determine are within the acceptable risk limits for a particular project. Two main public insurance services exist in the market: The World Bank’s Multilateral Investment Guarantee Agency (MIGA) and the US’s Overseas Protection Investment Corporation. Both will be discussed as focal points for how political risk insurance works in international energy projects.

As a whole, these political risks pose critical failure risk for most projects if left unattended, resulting in the need for political risk solutions through investment guarantees. POLITICAL RISK SOLUTIONS Broadly, there are two solutions for the energy industry. First, an investment agency is the most direct guarantee of protection when operating abroad. Second, multilateral agencies that operate globally give companies the ability to have an alternative approach to protecting their assets. These two options both have their limits on being able to guarantee that a nation or powers inside a nation will not try to wrestle a project away from the company who developed it.

“Investment insurance agencies are the backbone of the global trade and mining industries.” First, political risk insurance is only available for war, nationalization/expropriation, and inconvertibility. As discussed above, these different categories of political risk pose serious threats if not managed and mitigated properly. Loss of assets associated with war and overt nationalization is the most severe risk and can often be readily identified. However, creeping expropriation may not be covered. 9 Issues with creeping expropriation usually happen gradually over such a long time period that defining an instant that made the project unviable is often impossible. In these instances, MIGA and other services try to cut their losses strategically, as any tax changes that affect a project could result in tens of billions of dollars in claims. This would overwhelm the MIGA financial protection system and make it too expensive to cover anything, so MIGA limits the claims to the ones stated above.

When the two main solutions end up failing to insulate an energy company from political risk, they often use non-traditional mechanisms to give themselves more protections. Bringing on national partners, using contractual freezing provisions, and the like allow for energy companies to take these guarantees to a court or arbitration tribunal that will later enforce them. However, the ability to enforce still often requires the multilateral agencies backed by international treaties. INVESTMENT INSURANCE AGENCIES: GENERALLY Investment insurance agencies are the backbone of the global trade and mining industries. They are generally the most effective means for directly managing the associated risks that global projects face through direct triggers that allow companies to be reimbursed for financial losses and made whole. Investment insurance agencies operate within a limited framework of particular triggers that are used to enforce coverage. These triggers are the political risks that have been talked about above. The energy company must pay a monthly or annual premium that ensures coverage will be available to the energy project if the triggers are satisfied.

Second, insurance premiums, as they exist everywhere, often add significant costs to a project, even if they are only 1% of total project expenditures. A project’s commerciality is often the single most precarious executive decision that the commercial and legal teams must balance. A careful review of contract arrangements and fees, government take, and other costs often add up quickly and affect a project’s viability. Yet, they are all critical issues that must be managed for the project to move forward. Insurance, however, is merely a background requirement to those government fees and contract terms and as such, often results in energy groups forgetting to 63

calculate the insurance premiums that could put a project below the required return on investment that an energy company need to keep the project in the portfolio.

corporations carrying on a business in the home country of the insurance agency. A typical global projectâ&#x20AC;&#x2122;s trajectory is that most groups are bringing in investors and players that have a variety of national backgrounds. The idea behind these national insurance schemes is that each nation should be able to host each joint-venture party to an energy project, resulting in parallel insurance schemes that encompass the project as a whole.

Third, the size and scale of projects make it nearly impossible for a project to actually be insured as doing so would bring imbalance to the insurance companyâ&#x20AC;&#x2122;s portfolio. Most insurance companies would avoid this kind of investment. Because of this, it would likely take several insurance companies in the foreign nation as well as the companyâ&#x20AC;&#x2122;s home country to cover the total investment. The challenges of parallel insurance would dramatically complicate a risk assessment profile for a project. The terms of each insurance company will likely be different, resulting in different triggers for policies, timings for payment, and litigation disputes should an issue arise. The complexity of such an arrangement may mean that different insurance companies are used on different aspects of the project, giving each company its own independent territory of responsibility. The task of integrating such an operation is made simpler if the entire project is also supported by insurance agencies with assets in other jurisdictions that are governed by multilateral treaties.

However, this does not provide enough coverage as the terms and conditions of each national policy will differ. If any issue were to arise in the project, then the complicated cross settlement procedures, insurance triggers, arbitration proceedings, and negotiations would result in a collapse of the system. If few major joint-parties are involved in a project, the ability remains for all insurance companies from host governments to come together to the negotiation table and lock down consistent terms. However, such actions are quite rare. These issues are often insurmountable barriers to using investment insurance agencies on projects and the primary reasons why some companies choose to use alternative solutions. However, there are a couple of major investment agencies that hold a global reach and have the capacity to remedy some of the aforementioned issues.

Fourth, recovery is measured only by the amount of the investment, which means that the potential profits expected by the investors cannot be recouped from the insurance agency. In common law, this concept is known as the lost profit doctrine. 10 Lost profit damages are an estimate of the total sum of money lost due to the buyer's breach of an agreement. It is the computation of benefits that would have been made by the seller on a sale if the buyer had adhered to the contract. The plaintiff can claim lost profit damages from the buyer by showing that the buyer's demand was met by the seller according to the terms of the agreement and that no alternative remedy exists. However, this lost profit doctrine has no application because of the speculative nature and size of the potential profit windfall that insurance agencies would then need to cover.

INVESTMENT INSURANCE AGENCIES: MULTILATERAL AGENCIES Multilateral agencies expand the traditional insurance company premium and guarantee system onto a global scale. The first real application of this concept occurred through the European Recovery Program after the Second World War. 11 This program sought to use US equity in order to jump-start the European postwar recovery. However, the companies required assurances that their investments would be protected. Known as the Marshall Plan, this program remains the most effective form of this investment to date.

Lastly, the coverage by these agencies may not extend to investor groupings of different nationalities because some insurers only provide coverage for their own nationals or for persons or 64

After the Marshall Plan ended in 1951, other forms of protection sprung up to continue the trajectory of international investment. The private side of the industry can often be too varied to generalize effectively. Meanwhile, the public sphere is dominated by two main providers: The World Bank’s Multilateral Investment Guarantee Agency and the US’s Overseas Private Investment Corporation. These two groups are the main multilateral agencies that have traditionally been involved in energy project investment.

held by the national government and not released. This applies when there is no forum protection, unreasonable delays, and no final judgment enforcement. Lastly, the risk of civil war disturbance, which is such a broad category that it often includes other aspects of the above political risk categories. MIGA has a variety of solutions that can be used to insulate and mitigate project risk.16 MIGA guarantees Production Sharing Contracts (PSC) or risk service agreement investments/breach of government contracts that are NOT covered under the national programs. MIGA co-guarantees the larger multi-agency finance investments. This scheme is beneficial because national and multilateral agencies are de-risked in their portfolios which results in uniform protection to all co-investors. MIGA provides reinsurance guarantees of state capital agencies that are focused on the particular portions of hefty investments instead of trying to cover the entirety of a particular project.

“With over $66 billion worth of investment in 2018 so far, MIGA is by far the largest foreign direct investor guarantee group in the world.” Multilateral Investment Guarantee Agency Multilateral Investment Guarantee Agency is the first and probably the largest international investment agency that supports global project development, regardless of nationality. 12 MIGA started in 1985 under the World Bank to support insurance programs covering non-commercial risks. The nature of how MIGA developed gives rise to slightly differing categories of insurance coverage. With over $66 billion worth of investment in 2018 so far, MIGA is by far the largest foreign direct investor guarantee group in the world.13

MIGA does not use the lost profit doctrine discussed above because the size of the windfall due to speculative value would overwhelm MIGA’s portfolio. For example, holding MIGA responsible for tens of billions of dollars in lost profits for a large energy project would likely overwhelm the MIGA portfolio and influence the likelihood it would help in the first place. MIGA limits damages to the actual value of the investment because it is a clearly defined term which can be easily quantified. Moreover, it is an amount that cannot balloon out of proportion to the rest of the project as it is a known financial value.

The continuing constriction of global financial circumstances, the escalation of trade pressures, commodity price volatility, and the rise in the number of global conflicts pose growing risks to international investors. Given these changes and its goal of mobilizing growth-oriented private investment, MIGA’s role in supporting investment and job creation is more critical than ever.14

Generally, MIGA retains other broad benefits for energy projects.17 MIGA offers protection up to a specified amount to cover political risk insurance not otherwise covered by the traditional insurance agency. MIGA seeks to mitigate political risks that could impact a large project, either in direct relation to the government of the country or through the World Bank’s indirect authority who can leverage a position more effectively than any single company. MIGA’s actions can protect uninsured investments and investors due to the totality of coverage when nationalization occurs. This nationalization protection covers all aspects of a project as well as

There are four broad categories of MIGA covered political risks.15 First, currency risk from national government restrictions on foreign exchange. Second, the risk of loss through legislative or agency action eliminating company’s ownership stake, control, or benefit from the investment. Again, creeping expropriation is not covered as discussed above. Third, loss of protection after an arbitration or settlement award when a government contract dispute amount is 65

potentially covering all parties if the claim is properly made.

political risk shifts from the commercial lenders to the World Bank and back onto the government of the relevant host country.

MIGA, however, has the ultimate goal of building climate change resilience development, and the existential threat of climate change has forced MIGA to abandon all upstream oil and gas financing after 2019. 18 As a result, a rush for MIGA financing in 2018 and 2019 is expected. Though, due to limited guarantees from other sources, it also means that developing nations with hydrocarbon reserves will have a more difficult time getting global energy companies to invest in their nations. MIGA’s focus on sustainability and the prevention of coastal erosion across West Africa and the rest of the world will impact how the global energy business handles political risk insurance in the future.

In all, MIGA has supported energy projects for many years but will be limiting its support of nonhydrocarbon energy projects in the decades to come. MIGA has reinforced the rule of law for energy finance and will continue to do so through its various mechanisms supporting the traditional political risk insurance agency. The Overseas Private Investment Corporation The Overseas Private Investment Corporation is the United States’ MIGA insurance program and has operated to protect American energy companies abroad for decades. 19 Political risk insurance is available to U.S. investors, lenders, contractors, exporters, and NGOs for investments in more than 160 developing and post-conflict countries. 20 Coverage is offered for small and large investments that provide positive developmental benefits. However, coverage will prioritize developing nations in particular. There are three issues that OPIC will use to determine the credentials for a project: eligibility, types of coverage needed, and cost details.

World Bank Direct Guarantees World Bank direct guarantees are critical to project viability. The World Bank will provide direct guarantees to lenders on a project. Alternatively, the World Bank will finance the cost of guarantees through loans to the government should the government request it. Typical areas for which direct guarantees will be bought by the World Bank include non-performance and force majeure. These are called “partial risk” guarantees on the repayment of loan, and they operate as follows:

Eligibility is required for any claimant to be able to use OPIC insurance and financing. Eligibility prioritizes ownership, a quality track record, and an assessment of the country the company will be doing business with in addition to that country’s associated policy criteria.21

First, loans to project companies and governments provide guarantees that no repatriation or other forms of creeping expropriation will occur, and the guarantees are embedded in the agreement contractually. Then, the World Bank issues a commercial lender guarantee with a trigger for project company default due to the government’s failure to comply with the contractual guarantees stipulated. The government provides the World Bank with an indemnity/counter-guarantee for payments to commercial lenders in order to better protect the World Bank from being left with the bill.

Ownership must be met through some American based citizenship. U.S Citizens and nonprofits easily pass this threshold. Additionally, a corporation established in the US that is 50% owned by American citizens or other American corporations satisfies the threshold. Other entities that are established outside the US but are owned by American citizens or corporations with a 95% or more interest also satisfy the ownership requirement.

The loan is provided by commercial lenders to the project company after which the World Bank issues to the commercial lenders a guarantee encompassing particular payments due with the loans. The government again provides the World Bank an indemnity/counter-guarantee. Thus,

All project teams must have a proven track record to satisfy OPIC requirements. The project team must have demonstrated competence for the proposed management of the project through a clear record of success with the same or similarly 66

related ventures. OPIC also requires project teams to have supporting documentation establishing their track record, such as financial statements and financial projections.

for coverage to be available. The issue in these situations is whether a government honors “an explicit, irrevocable sovereign guarantee of the borrower’s debt obligation.”24 One positive about this guarantee is that it can cover the lifetime of the project whereas other insurance schemes limit coverage 20 years or fewer. In all, NHSG protection is a good way to protect an energy project from a foreign government’s failure to honor existing energy exploration and production contracts.

Lastly, country and policy criteria allow American companies to do business in 160 different countries. Limitations apply to some countries including Venezuela and Russia which are sanctioned and therefore cannot be listed. Any sanctioned country cannot be on the list of allowable nations for OPIC. Likewise, particular regulatory, policy, and portfolio restrictions could limit the accessibility of OPIC programs in certain countries. Because of the focus on developing nations, OPIC must ensure that projects present a major benefit to the host country while simultaneously complying with economic impact, worker rights, human rights, and environmental priorities of the American government. Some companies involved with OPIC projects are concerned that the worker rights laws do not comply with those of some developing nations. Where things conflict, a company should be incredibly careful with OPIC assessments and reviews because they could point to employment or environmental breaches with the policy if a company seeks to make a claim.

The BOC for capital markets is for US bond markets related to developing country projects that are top governmental priorities. Often, these large energy projects will be the most capital-intensive projects a developing nation has ever faced. This results in an overburdening of governmental and financial systems which are unable to effectively support a project of the size and scale required to make these investments feasible. This coverage protects against a breach in financial terms and provides a safeguard against the threat of a host government obstructing the arbitration process or failing to pay arbitration awards. In most cases, a credit rating of single A or higher is required for this type of claim. In all, only those projects that would result in net saving for the sovereign should use this type of insurance.

The types of coverage included by OPIC are currency inconvertibility, expropriation, political violence, reinsurance, and capital markets. 22 Coverage for currency inconvertibility, political violence, and reinsurance are similar to what has been discussed previously. Capital markets coverage is a bit different as it focuses on protecting private capital in emerging markets through sovereign guarantees and breach of contract claims. Capital markets are split into two different groups, the non-honoring of a sovereign guarantee (NHSG) and the breach of contract for capital markets (BOC).23

Currency issues, political violence, and reinsurance are critical for any project and will be priorities in any protection scheme for an energy project. Capital market protections for sovereign guarantee and breach of contract issues related to financing and arbitration can be critical to the success of the project. However, these still have a maximum insurance rate of $200 million in most cases. This results in same issues that existed under MIGA with the World Bank—no single insurance scheme can adequately protect a major energy project abroad from political risk. For comparison purposes, since 1971 OPIC has covered 300 insurance claims amounting to $977.4 million. This would cover only half of a single offshore oil production project for a single country.25 The scale of these projects is simply so immense that it is hard to imagine this insurance as anything more than a backstop to other forms of guarantee.

An NHSG is specifically used when a sovereign government supports a governmentowned entity in an energy project with a private American energy company. Often times energy companies must work with the nationally-owned energy company in a particular country in order to do business there. This kind of guarantee helps protect that investment. However, the country rating for public insurance must be B/B+ or better

The scope of coverage and associated cost details are other major issues that OPIC and the 67

project team need to assess.26 For the election of coverage, a coverage ceiling and active amount are the necessary indicators. The coverage ceiling is simply the maximum amount of coverage needed. The active amount must, at a minimum, equal the book value of the insured investment unless the team decides a lower coverage ceiling. There are other more nuanced aspects to the coverage but the extent of coverage is usually available for up to 20 years or the length of the underlying contract. In the case of energy projects, it is possible to get a longer contract than 20 years when the underlying government agreement underlying is 30 years. The coverage is available for up to 90% of the total eligible investment, making OPIC far more attractive than MIGA for timing, scope, and amount insured. The goal is to have the investor bear at least 10% of the overall risk of loss. One positive aspect about this coverage is that loans and capital leases to unrelated third parties could be covered for the full amount of principal and interest. This is an advantage over most private insurance companies and makes OPIC one of the best coverage insurers for international energy projects.

OPIC can be an effective backstop of up to $200 million for an international energy project. The energy company has many avenues of guidance from OPIC that can support its process and claims.28 The claimant must present a remedy amount, a reason for the claim, and the insured’s compliance with contractual procedures and duties with the claimant’s insurance contract as the primary reference. Even after receiving an award, it is possible that another government will not honor the award or the country/company trying to receive the award. These problems continuously plague energy projects and impact how political risk is managed. Geopolitics, money, timing, and size of projects are the biggest factors for political risk insurance and its ability to support an energy project. ALTERNATIVE MECHANISMS OF GUARANTEE When using OPIC and MIGA are not enough for an energy company to insulate itself from political risk, they often use non-traditional mechanisms to allow themselves more protections. The main options companies include bringing on national partners, using contractual freezing provisions, and the like. These options allow energy companies to take these guarantees to a court or arbitration tribunal that will later enforce them. But the ability to enforce still requires the multilateral agencies be backed by international treaties, which are often complicated to secure and enforce in their own right.

“These problems continuously plague energy projects and impact how political risk is managed. Geopolitics, money, timing, and size of projects are the biggest factors for political risk insurance and its ability to support an energy project.”

One of the main options available to energy companies is export credit agency loan guarantees, commonly known as ECAs. An ECA is a public agency or entity that supports private international business opportunities with direct government guarantees. The ECA market is the largest private sector project development funding scheme in the world. Most industrialized nations use ECAs to protect national projects abroad.

The catch to any insurance is whether enforceability of the claim is fair and practical for a claimant. Enforceability of an insurance claim is critical and OPIC’s arbitration process is one of the most transparent and effective forms in the international insurance arena.27 To date, OPIC has enforced and paid out more claims than nearly any other guarantee service. OPIC makes either cash guarantees directly to investors or host government guarantees paid out to investors through the original contract. This system is incredibly effective and is the primary reason why many energy companies have used OPIC as an asset protection scheme in projects around the world.

The United States uses the Export/Import Bank of the United States (EXIM) as its national export credit agency. EXIM offers a far wider range of services than OPIC or MIGA. 29 Some of those services include bonds, hedging on projects, financing, foreign customer purchases, service exports, insurance, loan guarantees, lease 68

guarantees, and direct loans. Countries such as Mexico and Ghana have used the service in support of projects far exceeding the $200 million limit of the other services.30

loans provide one of the best forms of guarantee available to an energy company. Companies have different approaches on how to handle political risk protections. Most of the super-majors in the industry use political risk insurance and many of the alternatives interchangeably. However, it does include steep premiums, limits on each particular protection, and quite a bit of work on the front of a project to get cross-indemnity clauses in place for various lenders and guarantee agencies. Some companies, like Anadarko, have tried alternative means and found that the projects were successful and safe without MIGA or OPIC insurance guarantees.

Use of EXIM services in the US and abroad seems to be more attractive for energy projects for one major reason—it is far less likely repatriation will occur if the event causes a default on a loan of an official agency because the agency’s reputation with other sectors will be impacted. The ability for a company to protect itself through the use of credit ratings and agency reputation is often a much better guarantee than relying on international arbitration to protect a project in Asia, Africa, or the Western Hemisphere. US companies will often use EXIM to supply a new country entry project, meaning that the company is the first in that country to do exploration work for oil and gas. Such projects are critical to the development of the industry and EXIM provides a strategic role beyond just guaranteeing assets and investments.

Historically, Anadarko’s insurance team has not purchased political risk insurance because: 1) the limits available were insufficient given the size and scope of the given project; 2) Anadarko’s risk appetite allowed it to self-insure some or all of the exposures; and/or 3) Anadarko chose to utilize other risk mitigation techniques that they have found increasingly effective. Jessica Harris, one of the lead Risk Management attorneys with Anadarko Petroleum Corporation, states that:

Other project guarantees available to energy companies include doing a broad loan by many banks for the project with cross-default clauses. Many cross-default project loans protect you from a developing nation choosing repatriation and repercussions from one bank because they cannot risk the loss of credit-worthiness from many banks. This kind of mechanism is traditionally quite effective but usually does not include public insurance like OPIC or MIGA. The challenge with this type of arrangement is that it quite often requires many different groups to work together. Because each group uses different model forms and different triggers for claims, an energy project may get dragged down by the paperwork and complexity of the guarantees. Each claim having a different court or arbitration proceedings, multiclaim issues that trigger multiple policies, and other intricate issues could result in an energy company getting very little reimbursement because it has too many means of seeking funds. These reasons highlight why the broad loan must be made as a joint loan from the different banks instead of utilizing individual bank paperwork for the transaction. Although it might take a bit of time to hammer out the specifics, cross-default project

“Anadarko typically evaluates the political risk exposure of countries on a case-by-case basis. Anadarko often attempts to mitigate these risks with various mechanisms such as: choosing to partner with companies of different backgrounds/national ties than Anadarko; forming its foreign entities with connections to parent entities that are established in countries that hold bilateral investment treaties with the counterparty (i.e. host country); and attempting to build protections into its concession agreements with host governments such as stabilization clauses and arbitration and choice of law provisions that are outside of the host country.”31 The varying means of investment guarantee seem to be more effective than MIGA or OPIC because they are not restricted by the geopolitical limits of the World Bank and American investment 69

bureaucracies. This flexibility allows companies to operate abroad with discretion—playing out business ventures with the highest stakes for investors. Generally, oil and gas companies stay away from approaches to financing projects which entail a fixed charge obligation that would collapse a project through the premium costs. Project lending has developed so far in the last few decades and many of these solutions have been used on a variety of occasions because they stopped a repatriation or a decision to change the regulations of a government.

companies; it is merely the form of deterrence one chooses to use that must be decided. Moving forward, MIGA will no longer be an option for oil and gas companies to use for guarantees. Still, all other avenues are available for risk management teams to determine their political risk appetite. Article Sponsored By:

CONCLUSION These different types of mechanisms of investment protection are critical to a company’s decision on how to defend itself when operating in international jurisdictions. In the end, a company’s options really are alternative forms of deterrence from seizure by a government or nonstate actor inside the country. Deterrence has been the most effective protection for oil and gas 1

Alexander Van de Putte, David F. Gates & Ann K. Holder, Political Risk Insurance as an Instrument to Reduce Oil and Gas Investment Risk and Manage Investment Returns, 5 J. OF WORLD ENERGY L. & BUSINESS 284, 289 (2012).

MULTILATERAL INVESTMENT GUARANTEE AGENCY, 2018 ANNUAL REPORT 3 (2018), https://www.miga.org/sites/default/files/201811/MIGA%202018%20Annual%20Report.pdf [hereinafter MIGA 2018 REPORT].

CLAUDE DUVAL ET AL., INTERNATIONAL PETROLEUM EXPLORATION AND EXPLOITATION CONTRACTS 261 (2009).

Id. at 14.

RESTATEMENT (THIRD) OF THE FOREIGN RELATIONS LAW OF THE UNITED STATES § 712 (1987).

Jurgen Voss, The Multilateral Investment Guarantee Agency: Status, Mandate, Concept, Features, Implications, 21 J. OF WORLD TRADE L. 5, 10 (1987).

See generally IBRAHIM F.I. SHIHATA, MIGA & FOREIGN INVESTMENT (1988).

Van de Putte, Gates & Holder, supra note 1, at 285–286.

INTERNATIONAL LAWYER'S DESKBOOK 71 (Lucinda A. Low et al. eds., 2d ed. 2003) [hereinafter DESKBOOK].

See CLAUDE DUVAL, A PRACTICAL RESPONSE TO STATE INTERVENTION IN RESOURCE PROJECTS: INTERNATIONAL INSURANCE AGAINST POLITICAL RISK THROUGH MIGA (1988).

KAUSAR HAMDANI, ELISE LIEBERS & GEORGE ZANJANI, FED. RESERVE BANK OF N.Y., AN OVERVIEW OF POLITICAL RISK INSURANCE 3 (2005). 7

Political Violence, OVERSEAS PROTECTION INVESTMENT CORP., https://www.opic.gov/what-we-offer/political-riskinsurance/types-of-coverage/political-violence (last visited Nov. 20, 2018). 8

DESKBOOK, supra note 5, at 72.

DUVAL ET AL., supra note 2, at 270.

22 U.S.C. § 2191 et seq.

Political Risk Insurance, OVERSEAS PRIVATE INVESTMENT CORP., https://www.opic.gov/what-weoffer/political-risk-insurance (last visited Nov. 20, 2018). 21

Eligibility, OVERSEAS PRIVATE INVESTMENT CORP., https://www.opic.gov/content/eligibility (last visited Nov. 20, 2018).

See Bear Creek Mining Corp v. Republic of Peru, ICSID Case No. ARB/14/21, Award, ¶ 673 (Nov. 30, 2017).

Types of Coverage, OVERSEAS PRIVATE INVESTMENT CORP., https://www.opic.gov/what-we-offer/political-riskinsurance/types-of-coverage (last visited Nov. 20, 2018)

Van de Putte, Gates & Holder, supra note 1, at 291.

Ibrahim F.I. Shihata, Towards a Greater Depoliticization of Investment Disputes: The Roles of ICSID and MIGA, 1 ICSID REV.–FOREIGN INV. L. J. 1, 21 (1986).

MIGA 2018 REPORT, supra note 13, at 6.

19 20

are/transparency/claims-and-arbitral-awards (last visited Nov. 20, 2018).

Breach of Contract for Capital Markets, OVERSEAS PRIVATE INVESTMENT CORP., https://www.opic.gov/whatwe-offer/political-risk-insurance/types-of-coverage/capitalmarkets (last visited November 20, 2018). 24

How to Present an OPIC Insurance Claim Effectively, OVERSEAS PRIVATE INVESTMENT CORP., https://www.opic.gov/sites/default/files/docs/opic_claim.pd f (last visited Nov. 19, 2018).

Id.

What We Do, EXPORT-IMPORT BANK OF THE UNITED STATES, https://www.exim.gov/what-we-do (last visited Nov. 19, 2018).

INSURANCE CLAIMS EXPERIENCE TO DATE: OPIC AND ITS PREDECESSOR AGENCY, OVERSEAS PRIVATE INVESTMENT CORP. 1 (2017), https://www.opic.gov/sites/default/files/files/2017_Annual_ Claims_Report.pdf

Types of Coverage, OVERSEAS PRIVATE INVESTMENT CORP., https://www.opic.gov/what-we-offer/political-riskinsurance/types-of-coverage (last visited Nov. 20, 2018).

Project Off Ghana Gets Support From U.S. Exim Bank, OIL & GAS JOURNAL (Apr. 15, 1996), https://www.ogj.com/articles/print/volume-94/issue-16/inthis-issue/drilling/project-off-ghana-gets-support-from-usexim-bank.html.

Telephone Interview with Jessica Harris, Risk Management Team, Anadarko Petroleum (Oct. 24, 2018).

Claims and Arbitral Awards, OVERSEAS PRIVATE INVESTMENT CORP., https://www.opic.gov/who-we-

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

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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. In recent years, the College has directed a portion of its annual operating budget to fund the formation of the Harry L. Reed Oil & Gas Law 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 to expand its reach through partnerships with the industry and other academic leaders, new CLE courses, and symposia, the ENERGY NEWSLETTER and the College are 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 innovative and purposeful. It requires us to adapt, reimagine, and transform. 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/ For future article submissions or inquiries for professional sponsorship of the ENERGY NEWSLETTER, direct your emails to the address below: ryan.hoeffner@stcl.edu South Texas College of Law Houston, Oil & Gas Law Society Office