International Oil & Gas Seminar

International Oil & Gas Seminar

21 October 2014 Houston, Texas

International Oil & Gas Seminar Agenda Tuesday 21 October 2014 Four Seasons Houston Timings and presenters of the sessions are subject to change without notice. 10:00 a.m. – 12:00 noon Unconventional Oil and Gas Development*

Randel Young – Partner, K&L Gates, Houston

David Sweeney – Of Counsel, K&L Gates, Houston

Lian Yok Tan – Partner, K&L Gates, Singapore

James Green – Partner, K&L Gates, London

Simon Salter – Partner, K&L Gates, Perth

12:00 – 1:30 p.m. Networking Luncheon

1:30 – 3:00 p.m. FPSOs, FLNG, and Offshore Oil and Gas Structures*

Steven Sparling – Partner, K&L Gates, Houston / Washington, D.C.

Raja Bose – Administrative Partner, K&L Gates, Singapore

Mike Stewart – Partner, K&L Gates, London

Michael Chalos – Partner, K&L Gates, New York / Charleston

3:00 – 5:00 p.m. U.S. Exports of Oil, Condensates, and Gas*

David Wochner – Partner, K&L Gates, Washington, D.C.

Darrell Conner – Government Affairs Counselor, K&L Gates, Washington, D.C.

Steven Sparling – Partner, K&L Gates, Washington, D.C.

Lian Yok Tan – Partner, K&L Gates, Singapore

5:00 – 9:30 p.m. Cocktail Reception and Dinner

*CLE credit offered in CA, IL, NY, PA, and TX

International Oil & Gas Seminar Tuesday 21 October 2014

Speaker Biographies

Raja Bose Administrative Partner, K&L Gates, Singapore +65.6507.8125 [email protected] FPSOs, FLNG, and Offshore Oil and Gas Structures Raja Bose is the Administrative Partner of the Singapore office of K&L Gates and leads the firm’s Commercial Disputes and International Arbitration practice in Asia. He has more than 20 years of experience in international dispute resolution and has worked in both London and Singapore. He is qualified both as an Advocate & Solicitor of the Supreme Court of Singapore as well as admitted as a Solicitor of England & Wales.

Michael Chalos Partner, K&L Gates, New York, Charleston +1.212.536.4097 [email protected] FPSOs, FLNG, and Offshore Oil and Gas Structures Michael Chalos is a Partner in the firm’s New York and Charleston office and has been practicing maritime law for more than 35 years. He has handled a number of matters involving traditional maritime issues such as collisions; groundings; failure of equipment; damage to cranes and offshore rigs; cargo and other damages; Jones Act issues; Death on the High Seas Act; arrests; and insurance issues relating to cargo, P&I, hull, indemnity, and general liability.

Darrell Conner Government Affairs Counselor, K&L Gates, Washington, D.C. +1.202.661.6220 [email protected] U.S. Exports of Oil, Condensates, and Gas Darrell Conner is a government affairs counselor based in the firm’s Washington D.C. office and has more than 20 years of experience working with Congress and the executive branch. He also has extensive legislative experience in general public policy analysis and planning, strategic counseling, and coalition management and coordination. Mr. Conner also assists clients in incorporating public policy into their strategic planning, integrating public relations into their legal and advocacy activities, and legislative drafting.

http://www.klgates.com/raja-bose/

http://www.klgates.com/michael-g-chalos/

http://www.klgates.com/darrell-l-conner/


James Green Partner, K&L Gates, London +44.(0)20.7360.8105 [email protected] Unconventional Oil and Gas Development James Green is a Partner in the London office, and spearheads the Africa group within the firm. His practice covers a broad range of corporate areas, including fundraising and other transactions on the Official List and AIM (acting for both companies and nominated advisers/ brokers), mergers, acquisitions, joint ventures, group reorganisations and venture capital investments. Mr. Green has experience in a range of sectors, but has a particular focus on oil and gas, mining and cleantech/renewable energy.

Simon Salter Partner, K&L Gates, Perth +61.8.9216.0930 [email protected] Unconventional Oil and Gas Development Simon Salter is a Partner in the firm’s Perth office with extensive experience in a wide range of transactional work for both private and public clients. He provides strategic advice on, and negotiates a wide range of transactions for clients principally in the resources sector and for internet service providers. He works closely with lawyers from other areas of the firm to provide comprehensive solutions for our clients. Mr. Salter advises clients in connection with a wide range of resource-related issues in a variety of jurisdictions in Africa, the Americas, Europe and Asia.

Steven Sparling Partner, K&L Gates, Houston, Washington, D.C. +1.202.778.9085 [email protected] FPSOs, FLNG, and Offshore Oil and Gas Structures U.S. Exports of Oil, Condensates, and Gas Steven Sparling is a partner in the firm’s Washington, D.C. and Houston offices. Mr. Sparling has a comprehensive understanding of the global LNG and oil industries—legal, operational, and commercial. He has represented clients in connection with the strategic assessment, project development, and optimization of over 30 projects in the Americas, Asia, and Europe.

http://www.klgates.com/james-o-green/

http://www.klgates.com/simon-anthony-northcott-salter/

http://www.klgates.com/steven-c-sparling/


Mike Stewart Partner, K&L Gates, London +44.(0)20.7360.8141 [email protected] FPSOs, FLNG, and Offshore Oil and Gas Structures Mike Stewart is a Partner in the Energy, Infrastructure and Resources group in the firm’s London office. He focuses on complex, high-value disputes arising out of major energy and infrastructure projects in emerging markets. Mike’s practice is divided between acting as project counsel and appearing in international arbitrations.

David Sweeney Of Counsel, K&L Gates, Houston +1.713.815.7351 [email protected] Unconventional Oil and Gas Development David Sweeney is based out of the firm’s Houston office and advises corporate and institutional clients on a broad range of oil and gas, coal, and other natural resource and infrastructure transactions, as well as advising on anti-corruption compliance matters for companies in the oil and gas business and related service sectors. Over the past ten years, Mr. Sweeney has advised on energy-related mergers and acquisitions (aggregate transaction value, over US$60 billion) and energy finance transactions (aggregate transaction value, over US$2 billion), as well as U.S. and international operational matters and projects.

Lian Yok Tan Partner, K&L Gates, Singapore +65.6507.8105 [email protected] Unconventional Oil and Gas Development U.S. Exports of Oil, Condensates, and Gas Lian Yok Tan is a Partner in the firm’s Singapore office and has over 18 years of experience specializing in a broad spectrum of energy, mining, and oil and gas matters including, among other projects: power plant, smelter, and refinery construction; financing and operation; oil and gas exploration and commercialization; infrastructure development; electric power sale and distribution; hydrocarbon and mining assets sale and disposal; and U.S. and international operational matters and projects.

http://www.klgates.com/michael-r-stewart/

http://www.klgates.com/david-h-sweeney/?nomobile=perm

http://www.klgates.com/lian-yok-tan/


David Wochner Partner, K&L Gates, Washington, D.C. +1.202.778.9014 [email protected] U.S. Exports of Oil, Condensates, and Gas David Wochner is a Partner in the firm’s Washington, D.C. office and represents clients on natural gas, LNG, and oil-related matters, including natural gas commodity and pipeline transportation issues, LNG imports and exports, and natural gas as a transportation fuel. He has served as lead Washington counsel on behalf of a major international drilling company in multiple Congressional and federal agency investigations and hearings related to the Gulf of Mexico Macondo oil spill, including House Committees on Energy and Commerce and the Judiciary, the Bureau of Safety and Environmental Enforcement, and its predecessor agencies.

Randel Young Partner, K&L Gates, Houston +1.713.815.7348 [email protected] Unconventional Oil and Gas Development Randel Young is a Partner in the firm’s Houston office with over 30 years’ experience in the energy, natural resource and electric power and related service, manufacturing and supply sectors. His oil and gas project development, M&A and transactional experience spans virtually every major segment of the oil and gas business. Mr. Young has represented national oil companies, international oil companies and other multinational businesses in structuring and implementing cross-border transactions in the United States, the Americas, and around the world.

http://www.klgates.com/david-l-wochner/

http://www.klgates.com/randel-r-young/

© Copyright 2013 by K&L Gates LLP. All rights reserved.

2014 International Oil & Gas Seminar

Tuesday 21 October 2014 | Four Seasons Houston


Unconventional Exploration & Development


Introduction Randel Young Houston, Texas

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Source: EIA/ARI World Shale Gas and Shale Oil Resource Assessment, May 17, 2013

Assessed World Shale Gas and Shale Oil Resources (42 Countries, including U.S.)

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Part 1 − Lifecycle Stages, De-risking, and Risk Allocation

David Sweeney Houston, Texas

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Unconventionals vs. Conventionals Key Differences?

Some key differences between unconventional and conventional projects Project lifecycle

Project phases tend to be less distinct when compared to conventional projects Certain risks decrease more gradually over time instead of abruptly at the end of a discrete phase

Risk profile Risks are similar to a “conventional” project However, risks increase and decrease differently over time

Types of risks – examples of differences in impact Exploration

Conventional – “dry hole” Unconventional – “play concept”/not-economic, well variability, acreage prospectivity

Operational Conventional – rig problems/downtime, lost hole, impenetrable substances Unconventional – inefficiencies, difficulty obtaining services (e.g., frac crews), long cycle times, high

service/material costs External

Conventional – commodity prices, regulatory framework, NIMBYism Unconventional − commodity prices, regulatory framework, NIMBYism

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Project Lifecycle – Conventional

Phase Description Major Risk(s) Allocation Exploration Search for hydrocarbon

accumulation Dry hole All participating parties

High sole risk premium

Appraisal Determine whether accumulation is commercial

Noncommercial discovery

Participating parties Lower sole risk premium

Development Drill wells/build infrastructure/determine monetization scheme

Cost overruns; Construction delays

U.S. – Participating parties (well-by-well) Non-U.S. – All parties

Production Produce and sell hydrocarbons Maintain production

Commodity prices; Change in laws/regulatory environment/politics

U.S. – Participating parties (well-by-well) Non-U.S. – All parties

Discovery?

FID/Sanction?

First Production

P&A/Decommission

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Project Lifecycle – Unconventional*

* Reproduced with permission of Preston Cody of Wood Mackenzie Consulting

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Similar Risks – Different Degree & Duration*

* Reproduced with permission of Preston Cody of Wood Mackenzie Consulting

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Exploration and Concept/Variability Risk

Exploration vs. “concept” and well variability risk Conventional exploration risk is substantially eliminated through the drilling of exploration and

appraisal wells Play concept risk and well variability risk continue for a much longer period of time over the life

of the project Operator may have difficulty obtaining consistent, repeatable, and commercial results (well

variability) and/or find that parts of a play are better than others (acreage prospectivity)

“Concept” and “Pilot” phases vs. exploration phase Exploration and appraisal phases largely eliminate “dry hole” risk in conventional project “Dry hole” risk is less relevant for an unconventional project; however, “play concept” and “well

variability” risks amount to the same thing─no commercial project “Concept” and “pilot” phases do not usually eliminate these risks

Lessons UNCONVENTIONAL E&P IS NOT EQUIVALENT TO MANUFACTURING NOT ALL UNCONVENTIONAL ACREAGE IS CREATED EQUAL

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Exploration and Concept/Variability Risk Risk allocation – traditional methods

Traditional Exploration and (sometimes) appraisal wells − participate or relinquish/breach Follow-on/development wells after project de-risked – well-by-well in U.S.; all-in or all-out

outside U.S. Problems

De-risking may take much longer and involve many more wells and production testing Allowing parties to “get out” potentially places concept/variability risk on one party, which

may result in under-investment However, forcing parties to “stay in” may incentivize over-expenditure

Risk allocation – potential “unconventional” methodology Agree to specific, contractually mandated pilot program “Sub-areas” and different “pilot” stages Step-down premium matrix No sole risk/non-consent

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Operational Risk “Ramp-up & exploit” vs. “development & production”

Similar risks, but different project sensitivities and timing Vs. conventional projects, unconventional projects generally:

require more, and more expensive, wells/facilities have sharper decline curves have higher GOR/NGL content require ongoing capex, almost to the end of project life (in proven areas) have higher acquisition costs/taxes/royalties/fees

These operational risks are largely eliminated by the end of the development phase in a conventional project but continue to the end of an unconventional project

Risk allocation – traditional methods Cost overrun provisions (not typically in U.S. onshore ventures) Procurement limitations Accumulation of surplus stock is “to be avoided” (COPAS 2005)

Risk allocation – proposed “unconventional” methodology Agree on operating philosophy (e.g., early “pad” based horizontal drilling vs. drill-and-hold vertical test wells)

ahead of time Strategic procurement Alternative decision-making structures Consider (carefully…) CAPL “operator challenge”

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External Risks Generally

Rarely dealt with contractually in a comprehensive fashion Managing these risks results in part from understanding them

Political risk/NIMBYism Changes in law

Risk that operations required for optimal development (especially given thin unconventional margins) will not be permitted or made significantly more expensive

Examples New York, the Netherlands, UK “ban” on hydraulic fracturing Municipality-required setbacks/landscaping Disclosure of frac fluid contents

Risk allocation & handling Risks are generally shared by all participants May be handled to some degree by understanding concerns and legal requirements and

setting up structures to monitor and deal with them ahead of time Shared operating philosophy NOC/governmental assistance Force majeure HSEQ programs In-country education and involvement

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Unconventional Development Outside the U.S. (How) Is the U.S. Experience Relevant (?)

Different licensing/fiscal regimes may complicate risk allocation structure Mandatory relinquishments Host government “take” Nonmarket price regimes

NIMBYism/Political risk Politicization of hydraulic fracturing in the U.S. may exacerbate issues outside the U.S. Lack of perceived benefit to holder of surface rights may erode support

G&G Not all unconventional plays are created equal Projects may be more sensitive to lower production rates, steeper decline curves, and higher

costs

Infrastructure and equipment concerns Lack of physical infrastructure Lack of regulatory infrastructure Lack of large-scale service company presence

Don’t assume that what has worked in the U.S. will work outside the U.S. 15


Part 2 − China Unconventional Oil & Gas Lian Yok Tan Singapore

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China Shale Gas/Oil

Source: U.S. EIA/ARI World Shale Gas and Shale Oil Resource Assessment Report – June 2013

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China Unconventional Oil & Gas Production − Overview

China gas consumption 162 bcm in 2013 Estimated to increase in the next 10 years to ~400 bcm per

annum Rising demand due to host of factors including push for cleaner

energy Shale production falls short

In August 2014, shale gas production revised from 60 − 100 bcm to 30 bcm

Supply and demand targets too ambitious

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China Unconventional Oil & Gas Production – Challenges (1)

Technological, geological, technical, and topological hurdles Sichuan, most promising basin, but in a

deeply faulted region and mountainous Water issues

China is increasingly subject to water scarcity Significant challenge to secure water supply

for water-intensive shale gas exploration Lack of sufficient transport

China’s existing pipeline network insufficient to effectively and efficiently transport gas to domestic demand centers

Requirement for enormous capital investment Lack of financial resources by most interested

developers─coal producers and provincial energy firms

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"Shale gas reserves in the United States are like a flat plate,

but in China that plate fell to the ground and

broke and then someone stomped on

it again."

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Discouragement of investment by low domestic prices Prices are controlled by National Development and Reform Commission (NDRC) and local

governments, resulting in a lower price in China than international markets

Much higher than break-even price of US$ 3.5 − 5.0/mmBtu in the U.S. due to combination of: Low regulated domestic price Low production rate from test wells Higher drilling costs─2 or 3 times U.S. costs

More incentives needed Higher subsidies Tax incentives including tax deductions for shale gas development costs and tax breaks on

imported equipment Extend effective period for firms to commercialize shale gas production

Environmental concerns Bringing additional environmental damage to a country with existing environmental problems

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Regulation Jointly undertaken by NDRC, Ministry of Land Resources (MLR), Ministry

of Finance (MOF), Ministry of Environmental Protection (MEP), Ministry of Science and Technology (MOST), and the State Administration of Taxation (SAT)

Difficulty is getting regulators on the same page Have to address legal issues with overlapping shale gas blocks with

traditional oil and gas blocks To date, China has issued only two or three rules about shale gas Uncertainty around a short -term subsidy program

National and local government subsidies (± CNY 0.4 per cubic meters) are only available for shale gas produced between 2012 and 2015

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Partnership with Foreign Companies (as of November 2013)

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Chinese Firms’ Overseas Acquisitions in Shale Gas (Oct 2010 to Dec 2012) (1)

Date Buyer Seller Deal Value Shale Gas-Related Assets

Oct 2010

CNOOC Chesapeake US$2.16 billion One-third interest in 600,000 acres in the Eagle Ford Shale

Dec 2011

CNOOC & Sinopec

Frac Tech US$2.2 billion Both firms expressed interest to acquire 30% state of the firm specializing in hydraulic fracturing technology

Feb 2011

CNOOC Chesapeake US$1.27 billion One-third stake in 800,000 acres in northeast Colorado and southeast Wyoming

Jan 2012

Sinopec Devon Energy US$2.5 billion One-third interest in 265,000 acres in the Tuscaloosa Marine Shale; 350,000 acres in Michigan; 235,000 Utica Shale acres in Ohio; 215,000 acres in Oklahoma; and 320,000 acres in Wyoming

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Source: Company announcements

Chinese Firms’ Overseas Acquisitions in Shale Gas (Oct 2010 to Dec 2012) (2)

Date Buyer Seller Deal Value Shale Gas Related Assets

Feb 2012

CNPC Shell US$1 billion (reported)

20% stake in Shell’s 100%-owned land and shale assets in Groundbirch of northeast British Columbia

July 2012

CNOOC Nexen US$15.1 billion (for the entire company)

300,000 acres of shale gas lands in northeast British Columbia, estimated to hold 9−38 Tcf of shale gas resource

Dec 2012

CNPC Encana US$2.2 billion 49.9% stake in the Duvernay shale gas formation (224,000 acres) holding an estimated 31 Tcf of gas resources

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Source: Company announcements

Conclusion Great demand for shale gas but many challenges and

risks Fresh water, clean air, and a healthy environment are

significant political issues Remains to be seen whether Chinese government will

give more incentives and address regulatory issues to entice Chinese and foreign companies including Chinese oil majors to invest in unconventional oil and gas

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Part 3 − UK Shale Gas − Making It Happen James Green London, UK

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Overview of Shale Gas in the UK Long history of onshore oil & gas

1851− first onshore UK-oil produced in Scotland 1960s − major discoveries in the North Sea 1980s − hydraulic fracturing of conventional onshore oil and gas wells 2011 − Cuadrilla Resources (Preese Hall, Lancashire)

Major political and media issue Growth in national and local lobbying groups Example of the U.S. Local regeneration and employment Declining North Sea conventional reserves Fears over energy security Technically recoverable resources─up to 130 Tcf

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UK Shale Gas/Oil

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The Risks We Don’t Have Infrastructure

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The Risks We Don’t Have Gas prices

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The Risks We Don’t Have UK energy mix

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Licensing/ Access Rights

Licensing Petroleum Exploration and Development License (PEDL), issued by the

Department of Energy and Climate Change (DECC) DECC’s consent required to drill a well, plug and abandon a well, or flare any gas Hydraulic fracturing plan required − “traffic light monitoring system” Environmental Risk Assessment

Access Rights

Trespass – consent/ Court process Draft Infrastructure Bill − statutory right of access

Contribution of £20,000 by the operator to the community for each horizontal well UK Onshore Operators Group − Community Engagement Charter − £100,000 for each well site; 1% of

revenues following production Follows a 12-week public consultation

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Environmental/ Planning UK is densely populated – NIMBYs/BANANAs Planning permission from the Minerals Planning Authority (MPA)

Wide discretion Environmental Impact Assessment (EIA)

DECC − Environmental Risk Assessment (ERA) Environmental Risk Assessment (ERA) Application to drill

Health and Safety Executive (HSE) Well design and construction, well integrity during operations, and the operation of

surface equipment on the well pad Well design verified by the HSE and by an independent third party

Environment Agency Disposal and treatment of flow-back fluids Air emissions Management of naturally occurring radioactive materials

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Tax

Finance Act 2014 – new rules for shale gas Ring-fenced corporation tax – 30%

Shale gas and conventional oil profits are within a single ring fence Ring fence expenditure supplement (RFES)

Supplementary charge − 32% Pad allowance − specific deduction against profits for supplementary charge

purposes Investment incentive – may eliminate supplementary charge

Proposed sovereign wealth fund

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Future for the Industry

Material changes to planning process unlikely Appeals and judicial reviews will establish precedents Better understanding of environmental impacts of exploratory

operations may mean scope of EIAs can be scaled back Increasing public confidence As projects enter production, communities will see the economic

benefits

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Part 4 − Australia Unconventional Oil & Gas Simon Salter Perth, Australia

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Australia Shale Gas/Oil

Source: U.S. EIA/ARI World Shale Gas and Shale Oil Resource Assessment Report – June 2013

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Overview of Shale Gas in Australia Industry Background

One of the world’s largest shale gas reserves, with technical recoverable resources estimated at 437 trillion cubic feet (Tcf) according to various reports

Asia’s increasing demand for clean energy driving Australia’s gas exploration & production

Cooper Basin straddling South Australia and Queensland: One of the few regions outside the U.S. commercially producing

shale gas Has existing infrastructure for conventional oil and gas, which will

facilitate construction of facilities and transportation of shale gas to market

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Legal Framework (1) Regulation

Subject to the same regulatory framework as conventional gas Legislation operates on Federal, State, Territory, and local council

level Exploration and extraction are primarily regulated at the State and

Territory level, or at the Federal level in the case of offshore developments

Federal laws affect gas activities in all States, including those relating to taxation, native rights, environmental protection, and occupational health and safety

Local council laws apply in respect of development and planning approvals

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Legal Framework (2) Ownership of hydrocarbon resources

Federal, State, and Territory governments own all hydrocarbon reserves

Rights to explore and produce hydrocarbons are granted through various petroleum titles and approvals from relevant government authority

Landholders therefore do not have ownership to gas resources, although they may be entitled to compensation for loss of use of land due to gas exploration and extraction activities

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Legal Framework (3) Administration

As shown in the schematic below, shale gas activities are governed by the various Petroleum Act equivalents and relevant Regulations in each State

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Key Considerations for Shale Gas Projects in Australia (1)

Exploration stage A permit is required from the relevant State and Territory authority Exploration permit will cover a defined area and have an initial

term of five to six years with a right to renew the permit or progress to an exploitation lease

Permit will grant holder the right to enter land and conduct test drilling and surveying activities

Terms of permit vary according to each State, but all are subject to meeting certain criteria

It also specifies minimum annual expenditure and development levels to ensure that holders continue to invest in the permit area

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Production stage Extraction and sale of shale gas requires a production license

from the relevant regulating authority Term of production license varies in each jurisdiction but is

typically for at least 21 years License entitles license holder to extract gas and retain economic

benefit of gas produced, subject to payment of royalty to the State Like exploration permits, production licenses generally specify

minimum annual expenditure and development levels

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Water resources rights State and Territory legislation governs access to and use of water Water rights are administered through legal instruments, property

titles, or contracts with a water service infrastructure operator Management of environmental risk associated with contaminated

wastewater is usually a condition of production license

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Fracking Significant political issue Concerned with use of certain chemicals in fracking process and

associated risks to environment and groundwater Most jurisdictions have implemented regulations on fracking

process and use of certain chemicals Western Australia has recently released draft regulations for

consultation to closely monitor fracking process associated with shale gas production

In Queensland and the Northern Territory, laws are in place that restrict use of certain chemicals in fracking

In Victoria, currently a moratorium prohibiting all fracking until June 2015

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Fracking (Cont’d) In June this year, a bill was passed through federal parliament to

protect groundwater resources in every state except Western Australia

Western Australia was not included because the legislation was limited to areas where coal seam gas is found, and Western Australia’s reserves hold shale gas

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Other General Regulatory Considerations (1) Environmental and planning considerations

Shale gas exploration and production operations are subject to significant laws and regulations governing environmental protection

Violation may result in issuance of injunctions limiting or prohibiting operations, as well as administrative, civil, and even criminal proceedings

Regulators may require operator to prepare and implement a plan to improve environmental performance of a project, and may amend the conditions on an existing environmental approval

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Other General Regulatory Considerations (2) Native Title considerations

Native Title is the term used to describe certain rights held by indigenous Australians in respect of traditional land and water

Native Title can only exist where the claimant group has and maintains a traditional connection with the land or waters

If Native Title rights exist, they must be taken into account and certain procedures must be complied with, including in some cases, payment of compensation

A register of Native Title interests is kept, and searches may be obtained from relevant courts and National Native Title Tribunal to establish whether a parcel of land is subject to a Native Title claim or interest

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Other General Regulatory Considerations (3) Royalty considerations

There are 3 mains types of royalties levied in Australia: Unit-based – a fixed monetary rate is applied on a physical rather

than financial basis, for example, a set amount of dollars per cubic meter of gas extracted

Value-based (ad valorem) – a uniform % of value of the resource is charged as royalty, for example, 10% of the post-wellhead value of gas extracted

Profit-based – a % is applied to profit realized, e.g., 10% of profits achieved

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Other General Regulatory Considerations (4) Fiscal regime and tax incentives

Petroleum Resource Rent Tax (PRRT) is a profit based tax that is levied on petroleum projects

From 1 July 2012, the PRRT is applied to all Australian onshore and offshore gas and LNG projects

Previously relevant was the carbon pricing mechanism; however the Australian government abolished the carbon tax with effect from 1 July 2014

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These slides are for informational purposes only and do not contain or convey legal advice. The information herein should not be used or relied upon in regard to any particular facts or circumstances without first consulting with a lawyer.


FPSOs, FLNG, and Offshore Oil and Gas Structures Legal Risks in the Construction Phase

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Legal Risks in the Construction Phase Why do they arise? What are they?─a practical example How does the law treat them? What can be done to minimize them?

Legal Risks in the Construction Phase Why do they arise?

Why Do Legal Risks Arise? Mismatch between allocation of risks and the parties’

respective commercial bargaining powers Performance requirements are not a guide to

construction Joint responsibility for production of a working design

specification Cutting-edge technology Time pressure to reach ‘first oil’

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Why Do Legal Risks Arise? Inadequate engineering Extensive changes to the design specification during

the project Underbid/under-priced Key critical path items supplied by buyers’ chosen

subcontractors Inadequate manning, quality, supervision Political unrest and financial uncertainty

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Legal Risks in the Construction Phase A Practical Example

Legal Risks – A Practical Example

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Legal Risks – A Practical Example EPC contract for the conversion of a vessel into

an FPSO Project in delay: Multiple change order requests Industrial action at fabrication yard Problems with supply of material

Scheduled date for mechanical completion will be missed

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Legal Risks – A Practical Example Contractor claims: Entitled to an extension of time and additional

payment because of change orders and delays in Company-supplied materials

Entitled to an extension of time because of force majeure

Entitled to additional payment because of disruption

Legal Risks – A Practical Example Company claims: Change Order requests misconceived work was in

Contractor’s scope Contractor caused delays through failure to mobilize No FM because strike by Contractor’s own employees No entitlement to an extension of time No notification given within required time Company entitled to deduct liquidated damages

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Legal Risks in the Construction Phase How does the law treat them?

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How Does the Law Treat the Legal Risks? Relevant issues: Scope of change orders Force majeure Notice provisions Concurrent delay Extensions of time Liquidated damages

Scope of Change Orders Will depend upon the wording of the Contract Generally, the key issue will be:

Is the work within the Scope of Work? Can be difficult in practice:

1. Will depend upon the details of the specification 2. What work can be reasonably inferred? 3. What is the Contractor’s overall obligation?

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Force Majeure Events FM typically excludes a party from performing their

obligations Most Contracts define FM events as Acts of God Wars Strikes

What about: Economic changes Financial crisis

Do they prevent performance

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Notice Provisions Notice provisions The basic rationale Often a condition precedent to bringing claims What happens if the Contractor does not comply?

Notice provisions and the prevention principle The basic tension How can it be resolved?

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Concurrent Delay True concurrent delay is the occurrence of two or more

delay events at the same time ─one an Employer Risk Event and the other a Contractor Risk Event─the effects of which are felt at the same time

True concurrent delay will be a rare occurrence The term “concurrent delay” is often used to describe the

situation where two or more delay events arise at different times, but their effects are felt at the same time

More accurate to refer to the “concurrent effect” of sequential delay events

Concurrent Delay Historically, different approaches adopted Arguably, the correct way to deal with concurrent

delays in extension of time claims under English law is as follows: “If there are two concurrent causes of delay, one of

which is a relevant event and the other is not, then the contractor is entitled to an extension of time for the period of delay caused by the relevant event notwithstanding the concurrent effect of the other event”

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Extensions of Time It is all about the contract Fair and reasonable? Fair determination? Must affect the critical path? Concurrent delay carve out?

How do you establish an EoT? Schedule analysis Depends upon the records available

Delay vs. disruption?

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Liquidated Damages The benefit of LDs to: To the Contractor To the Company

Can they be challenged: A Penalty Void for uncertainty Will depend upon the local law

klgates.com

Legal Risks in the Construction Phase What can be done to mimimize them?

klgates.com

Minimizing Legal Risks Understand the relevant contract, legal and technical aspects

before project starts Follow the contract terms in light of this understanding –

flexible and consistent Create and preserve written materials at every stage

klgates.com

Our Proposed Approach Support during contract negotiation – legal and

technical Risk assessment to identify and evaluate risks

during project Risk management during project Part of project execution team Routine support for Project Manager Confidence to make decisions

Low cost, extremely cost-effective

klgates.com

Project Support Service Use your lawyers little and often, as part of a risk

management strategy: Liaise with project team Draft key correspondence Advise on contractual provisions Provide ongoing legal support

Modest cost during project OR millions of dollars to arbitrate?

The Criminalization of Maritime Accidents since the Exxon Valdez

Exxon Valdez Prince William Sound, Alaska March 24, 1989

klgates.com 79

klgates.com 80

The Valdez oil spill was the largest ever in United States waters until the 2010

Deepwater Horizon spill.

Cleanup costs exceeded $2 billion. In response to the disaster, Congress passed

the Oil Pollution Act of 1990 (OPA). Exxon pleaded guilty to violations of the Clean Water Act, Refuse Act, and Migratory Bird Act, and as a result was fined $100 million and was required to pay $500 million in compensatory

damages. Exxon also set up a $1 billion restoration fund.

Capt. Joseph Hazelwood March 22, 1990 Acquitted on one felony and two misdemeanor charges. Convicted of one misdemeanor count of negligence.

klgates.com 81

klgates.com 82

Though Capt. Hazelwood was acquitted, the Valdez spill led to a new era of criminalization of maritime accidents.

Barge Bouchard 155 • Freighter Balsa 37 • Barge Ocean 255 August 1993 Three-vessel collision off Tampa Bay, spilling 336,000 gallons of fuel oil. $82.5 million cleanup and third-party claims; $8.5 million claim under Natural Resources Damage Assessment (NRDA). Pilot Thomas Baggett on the Balsa 37 at the time of the collision pleaded guilty to a Clean Water Act violation and was given 20 months’ probation and a six-month license suspension.

83

Morris J. Berman Hit a reef off Puerto Rico on January 7, 1994. First oil spill in U.S. waters after the enactment of OPA. Three corporations controlled by the Frank family were convicted of criminal violations of OPA and the Clean Water Act and fined $75 million.

klgates.com 84

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Rivera was acquitted of failing to notify the Captain of the Port that a hazardous condition existed on board. 33 U.S.C. § 1232(b)(1).

He was convicted of knowingly sending the Emily S. to sea in an unseaworthy condition likely to endanger life. 46 U.S.C. § 10908.

A Federal Court of Appeals overturned this conviction, finding that there was insufficient evidence to establish that Rivera knew the vessel’s condition was likely to endanger the

life of an individual.

Pedro Rivera, general manager of the Bunker Group, directed the crew of the tug Emily S. to transport the Morris J. Berman from San Juan, Puerto Rico to Antigua, despite

warnings that the towing wire was in a seriously deteriorated condition.

North Cape/Scandia The tug Scandia caught fire on January 19, 1996, off the coast of Rhode Island. This caused the barge it was pulling to spill more than 800,000 gallons of home heating oil into Block Island Sound. The U.S. Attorney brought criminal charges under OPA, the Migratory Bird Treaty Act, and the Refuse Act against the corporations that owned the tug and barge, the president of Eklof Marine, and the skipper of the Scandia. All parties pleaded guilty, paying $12.2 million in cleanup costs, $21 million in third-party claims, $8 million under NRDA, and $8 million in criminal fines.

klgates.com 86

Nissos Amorgos Sank in Venezuela’s Maracaibo Channel in 1997. Led to a legal dispute that is still ongoing.

klgates.com 87

New Carissa February 1999 Ran aground off the coast of Oregon. The ship’s owners paid a $22.1 million settlement to the state of Oregon and a $10 million settlement to the federal government.

klgates.com 88

MV Erika December 1999 Sank off the coast of France, spilling fuel oil. Total Oil paid €375,000 in fines and more than €400 million in cleanup costs.

klgates.com 89

Prestige November 2002 20 million gallons of oil spilled off the coast of Spain and Portugal.

klgates.com 90

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Captain Apostolos Mangouras convicted in 2013 of failure to obey authorities’ orders, sentenced to 9 months in prison.

Barge Bouchard 120 April 2003 Struck rocks off the coast of Cape Cod, spilling more than 90,000 gallons of fuel oil. Bouchard Transportation reached a criminal plea agreement with DOJ prosecutors, and paid a $9 million fine for Clean Water Act violations.

klgates.com 92

Tasman Spirit July 2003 Ran aground near Karachi, Pakistan. The Pakistani government fined the ship owners $200,000. Eight crew members were arrested and charged with conspiring to ground the tanker with criminal intent to cause pollution and injury. They were detained for eight months in Pakistan awaiting criminal charges. After compensation agreements were negotiated, prosecutors dropped the criminal charges and the men were released.

klgates.com 93

Selendang Ayu December 2004 Ran aground off the Aleutian Islands, spilling 350,000 gallons of oil. The shipping company paid $112 million in cleanup costs related to the spill, including an $800,000 fine to the state of Alaska, and a $10 million fine for criminal violations of the Migratory Bird Act and Refuse Act.

klgates.com 94

klgates.com 95

Capt. Kailash Bhushan Singh pleaded guilty to a single felony count of making false

statements to federal officials.

ZIM Mexico III March 2006 Collided with a crane while executing a 180° turn near Mobile Bay.

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Captain Wolfgang Schroeder (center) was convicted of criminal negligence under the Seaman’s Manslaughter Act and spent four months in prison awaiting sentencing at

which time he was sentenced to time served. The vessel owner, Rickmers Reederei, was also charged under the Manslaughter Act on

a vicarious-liability theory and paid a $375,000 fine.

Cosco Busan November 2007 Struck tower of San Francisco Bay Bridge in a thick fog. Fleet Mgmt., the operator of the vessel, pleaded guilty to criminal violations of APPS and obstruction of justice and paid $10 million in criminal fines and a further $44 million in cleanup costs. In addition, Fleet was required to implement an ECP.

klgates.com 98

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Captain John Cota agreed to plead guilty to violating the Clean Water Act and the Migratory Bird Act. He was sentenced to 10

months in prison.

Hebei Spirit December 2007 South Korea’s largest oil spill.

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Captain Jasprit Chawla and Chief Officer Syam Chetan were detained for more than 18 months by

South Korean authorities.

Deepwater Horizon April 2010 Explosion on a semi-submersible drilling rig causes oil spill. 4.9 million barrels of oil leak into the Gulf of Mexico over five months.

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The spill—the largest maritime oil spill ever—caused an estimated $23 billion in

economic loss. In addition to facing billions in civil claims,

BP pleaded guilty to 11 felony counts under 18 U.S.C. § 1115 (the Seaman’s

Manslaughter Act) related to the deaths of 11 workers, as well as one count of

obstruction of Congress, one misdemeanor violation of the Clean Water Act, and one

misdemeanor violation of the Migratory Bird Treaty Act. It paid a $4 billion fine.

Halliburton, the rig operator, pleaded guilty to an obstruction of justice charge for

destroying documents. The company paid a $200,000 fine and made a $55 million

contribution to the National Fish and Wildlife Foundation as part of the criminal

penalty.

MV Rena October 2011 Hit the Astrolabe Reef off the New Zealand coast, spilling over 1,700 metric tons of fuel oil.

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Two crewmen—Second Officer Leonil Relon (left) and Master Mauro Balomaga (right)—were charged under the Maritime Transport Act 1994 for “operating a

vessel in a manner causing unnecessary danger or risk” and under the Resource Management Act 1991 for “discharging a harmful substance from a ship.”

The two men pleaded guilty to all charges and were sentenced to seven months’ imprisonment.

Costa Concordia January 2012 Cruise ship sank off the coast of Italy, killing 32 passengers, 1 salvage member. Costa Cruise Lines, a Carnival subsidiary, paid a €1 million fine and avoided criminal liability.

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klgates.com 107

Captain Francesco Schettino was charged with multiple counts of

manslaughter and abandoning ship.

Domnica Cemortan, a dancer romantically linked to the captain, was allegedly on the bridge at the time the

ship ran aground.

MV Sewol April 2014 Passenger ferry sank off of South Korea, leading to nearly 300 deaths.

klgates.com 108

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Captain Lee Joon-seok (pictured) and 3 other crew members have been charged with murder.

Eleven other crew members have been charged with abandoning ship. Yoo Byung-eun, whom prosecutors believed was the real owner of the ferry company, was

found dead on June 12, 2014. An investigation into his death is ongoing. South Korean Prime Minister Jung Hong-won announced his resignation in the aftermath

of the disaster.

112



US Exports of Oil, Condensates, and Gas


America’s Energy Renaissance – Imports to Exports How U.S. Policy Is Evolving as America Becomes More Energy Independent Darrell Conner K&L Gates Washington D.C.

U.S. Policies Governing Exports

klgates.com 115

From Imports to Exports: Dramatic Shift in U.S. Landscape

klgates.com 116

America’s Energy Revolution: Growing Domestic Production

klgates.com 117

U.S. crude oil production is up 49% since 2008 Predicted to rise by 2.1 – 4.0 MMBPD by 2020 Lower 48 growth more than offsetting ANS declines U.S. predicted to surpass Saudi Arabia in crude oil

production by 2015 U.S. dry gas production is up 20% since 2008 From 20.2 Tcf annually to 24.3 Tcf annually Projected to grow to 29.1 Tcf annually by 2020

U.S. Surge in Production – Related Developments DOE has issued 3 final approvals, 6 conditional approvals

for LNG exports to non-FTA countries – what volume of exports will the U.S. permit?

BIS letter rulings permitting exports of processed condensates – are more “me too” rulings coming?

Refineries seeing high utilization because of access to cheaper crude oil – is there a crude refining wall?

Transportation and logistics network has been stood on its ear – where will the investment flow?

Political risk premiums minimized – can it stabilize consumer pricing for gas and related products?

klgates.com 118

Major Policy Drivers for Export Debate

klgates.com 119

Mid-term Elections Energy & Natural Resources Committee Pro-export Sen. Lisa Murkowski (R-AK) Pro-export Sen. Mary Landrieu (D-LA) Renewables champion Sen. Maria Cantwell (D-WA)

Size of Majority Importance of budget reconciliation Gridlock or compromise

What does 2016 bring? Republicans defend 2x as many seats as Democrats

klgates.com 120

Executive Branch Administration position evolving More LNG export terminal applications processed Evaluating impacts of crude oil exports Permitted processed condensate exports

Executive action to permit crude exports BIS condensate letter rulings Broader rule changes

Trade negotiations TTIP TPP

klgates.com 121

Public Debate

klgates.com 122

Studies / Reports to Frame Debate DOE study Think Tank studies Stakeholder studies

Public relations campaigns Lobbying campaigns

Price of gasoline!

Challenges to More Permissive Export Environment

Major structural change = greater political risk Complex economic considerations Impacted by decisions outside of U.S. control, e.g.,

OPEC pricing Potential loss of jobs in key sectors (even if offset by

more jobs in other sectors) National Security / Geopolitical ramifications Middle East destabilization?

Legislative vs. Administrative changes

klgates.com 123

Predictions for the Future Incremental change more likely in the near term Measured approvals of LNG export terminals Creative legal interpretations (e.g., condensates)

Robust public debate about export pros/cons Consumer impacts Economic impacts National security implications

More exports likely to be permitted …question is when and in what volumes

klgates.com 124


Evolving Issues for LNG Players in North America and Africa Steven Sparling Washington, D.C.

Overview Rapid development of North American LNG projects Snapshot of the market Key drivers for LNG exports Challenges

Evolving African LNG opportunities Traditional African LNG players Emerging LNG actors Recent developments and challenges

klgates.com 126

U.S. LNG Market: A Snapshot

klgates.com 127

0100000200000300000400000500000600000700000800000900000

1985

1987

1989

1991

1993

1995

1997

1999

2001

2003

2005

2007

2009

2011

2013

U.S. Liquefied Natural Gas Imports (MMcf)

U.S. Net Imports of Natural Gas to 2040 (Tcf)

Source: EIA

Source: EIA

Existing North American LNG Projects

klgates.com 128

Proposed North American LNG Projects

klgates.com 129

U.S. LNG Projects Proposed

klgates.com 130

Source: U.S. Department of Energy

Canadian LNG Projects Proposed

klgates.com 131

KEY Drivers for U.S. LNG Exports

klgates.com 132

U.S. Net Exports of Natural Gas to 2040 (Tcf)

Source: EIA

Challenges for North American LNG Exports

Volatility of Henry Hub pricing Oil index pricing of Western

Canadian and Pacific Northwest projects

Limited gas pipeline infrastructure for Pacific Coast projects

Project costs Panama Canal Active secondary markets and

competing projects

klgates.com 133

Regional LNG Pricing

Source: Poten & Partners, Inc.

African LNG Opportunities

klgates.com 134

African LNG Projects

Source: Centre for Global Energy Studies

Traditional African LNG players

klgates.com 135

1970 1971 1973 1981 1999 2000

Traditional African LNG Players

klgates.com 136

2002 2013 2007 2004 2005

Emerging LNG Actors in Mozambique and Tanzania

klgates.com 137

2005 2006 2008 2010 2011 2012

African LNG: Recent Developments Expanding offshore resource bases

Mozambique’s offshore territories could hold more than 100 Tcf of natural gas Anadarko, Mitsui, and others are leading a consortium to build an LNG liquefaction

facility Eni has proposed an FLNG facility for the Coral South Development project Goal for first LNG exports: 2018

Tanzania’s offshore reserves estimated at 53 Tcf BG, Statoil, ExxonMobil, and Ophir Energy plan to build a two-train LNG facility

Aiming for FID: 2016 Aiming for commercial operations: Early 2020s

Recent test wells by Statoil and BG support positive outlook for Tanzanian gas exports

Statutory and regulatory infrastructure under development Mozambique amended its oil and gas law in August 2014 to require international

E&P bidders to partner with state-owned ENH Tanzania revising its oil and gas laws

klgates.com 138


Demand in Asia for U.S. Exports of Gas Lian Yok Tan K&L Gates Singapore

Market Outlook (1) – LNG Supply Landscape Evolving

klgates.com

Will the market be

oversupplied?

Will supply

flexibility increase?

Will LNG contract pricing change?

Rapid emergence of United States, Canada & East Africa as

potential large-scale suppliers raises 3 key questions

Market Outlook (2) – Gas Demand Growth Driven by Asia/Middle East

klgates.com

klgates.com

Market Outlook (3) – High Growth Expected

klgates.com

Market Outlook (4) − Forecast LNG Supply & Demand 2015

Asia-Pacific LNG Regasification Capacity: New Importers 2015

klgates.com 144

klgates.com

World LNG Estimated August 2014 Landed Prices

Gas and LNG Prices

klgates.com 146

Asian Owners of North American Gas Assets (as of Oct 2012) (1)

klgates.com

Source: Company press releases

Foreign participant

Asset Location

Asset Description

PetroChina Canada Groundbirch Shale 20% interest in shale gas assets in partnership with Shell

Sinopec Canada U.S.

Daylight Energy Devon Energy fields

Acquisition of Canadian refiner with shale oil and gas assets in 2011 33% of five fields in Ohio, Michigan, and Oklahoma

CNOOC U.S. Canada

Eagle Ford Shale Colorado & Wyoming shale Nexen Energy

Purchase of 33% stake in Chesapeake assets for $1.1bn Purchase of 33% stake in oil-rich Chesapeake assets for $1.3bn Bid to purchase company with significant shale assets made in July 2012

Sumitomo U.S. U.S.

Marcellus Shale Barnett Shale (Texas)

30% of assets owned by Rex Energy 30% of oil and gas shale assets owned by Devon Energy

Mitsubishi Canada Canada

Cutbank Ridge Cordova Basin

40% interest in Encana shale gas assets 30% of JV with Penn West Exploration, Kogas, and a Japanese consortium

Mitsui U.S. U.S.

Eagle Ford Shale Marcellus Shale

12.5% interest in SM Energy gas assets in Texas 32.5% interest in Anadarko gas assets in Pennsylvania

Marubeni U.S. U.S.

Eagle Ford Shale DJ Basin

35% interest in Hunt Oil shale oil and gas assets 30% interest in Marathon shale oil assets in Wyoming

Asian Owners of North American Gas Assets (as of Oct 2012) (2)

klgates.com

Foreign participant

Asset Location

Asset Description

Itochu U.S. Samson Resources 25% interest in U.S. shale gas explorer and producer on partnership with KKR

Inpex Canada Horn River, Cordova & Liard Basins

JV with Nexen Energy to develop shale gas assets (Inpex to have 40$ stake)

Osaka Gas U.S. Perasall Shale 35% of Cabot Oil & Gas Corp assets in Texas

KNOC U.S. Eagle Ford Shale 55# of Anadarko assets in Texas

Kogas Canada Cordova Basin 5% of JV with Penn West Exploration, Mitsubishi, and a Japanese consortium

GAIL U.S. Eagle Food Shale 20% interest in Carrizo assets in Texas

Reliance U.S. Marcellus 40% interest in Atlas Energy gas assets

Japan Consortium Canada Cordova basin JOGMEC, Tokyo Gas, Chubu Electric, and Osaka Gas each have 3.75% of project with Mitsubishi and PWE

Source: Company press releases

klgates.com 149

Australian LNG Projects

klgates.com 150

LNG Pricing Revolution

Asian buyer mind-set is changing – costs and flexibility

HH introduced into the mix in recent deals

Equity participation in upstream and midstream

New markets will have new requirements

klgates.com

Asia gas hubs unlikely for some time

LNG markets will remain regionalized

Oil indexation will remain a key part of the mix

Asia remains the premium market

Yes, the market is evolving...

…but fundamentals will

continue to drive markets

klgates.com

Drivers Currently Affecting Global/Asian LNG Trade (1)

Unconventional production U.S. shale gas resources Non-U.S. unconventional gas discoveries Australia China South America Europe

New discoveries—East Africa

klgates.com

Drivers Currently Affecting Global/Asian LNG Trade (2)

Asia Japan—Fukushima China and Korea—increased demand Indonesia and Malaysia—changing from exports to

imports Panama Canal expansion

Generally increased demand and potential for supply-demand imbalance in next decade

klgates.com

Singapore as LNG Trading Hub (1)

Availability of LNG supplies Increase in numbers of LNG exporters and importing

countries and LNG portfolio players and traders Price arbitrage opportunity between Atlantic and

Pacific Basins Decline in destination restriction clauses Increasing number of older LNG facilities Availability of spot and short-term charters of LNG

vessels Large network of LNG-receiving terminals in Asia

klgates.com

Singapore as LNG Trading Hub (2) Singapore LNG terminal:

3 tanks, total of 6 MTPA By 2018 upon completion of 4th tank, capacity increased to 11

MTPA Asia’s 1st multi-user, open-access terminal with re-export

capability Strategic location Q-Max capacity

Concessionary tax rate of 5% on LNG trading income Zero boil-off losses

Boil-off from traders’ cargoes absorbed for domestic consumption

158


additional materials

LONG-TERM U.S. LNG EXPORTS MATRIX October 29, 2014

Long-Term U.S. LNG Exports Matrix

LONG-TERM U.S. LNG EXPORTS MATRIX

October 29, 2014

1 ©2014 K&L Gates LLP. All Rights Reserved.

U.S. LNG Export Terminals SABINE PASS LIQUEFACTION, LLC ....................................................................................................................................................................... 3 CAMERON LNG .......................................................................................................................................................................................................... 5 FREEPORT LNG EXPANSION, LP AND FLNG LIQUEFACTION, LLC ............................................................................................................... 7 CORPUS CHRISTI ....................................................................................................................................................................................................... 9 DOMINION COVE POINT ........................................................................................................................................................................................ 10 JORDAN COVE .......................................................................................................................................................................................................... 11 OREGON LNG ............................................................................................................................................................................................................ 12 EXCELERATE ............................................................................................................................................................................................................ 13 SOUTHERN LNG ....................................................................................................................................................................................................... 14 TRUNKLINE ............................................................................................................................................................................................................... 15 MAGNOLIA LNG ....................................................................................................................................................................................................... 17 CE FLNG ..................................................................................................................................................................................................................... 18 GULF LNG .................................................................................................................................................................................................................. 19 GULF COAST LNG .................................................................................................................................................................................................... 20 GOLDEN PASS........................................................................................................................................................................................................... 21 CARIB ENERGY ........................................................................................................................................................................................................ 22 SB POWER SOLUTIONS .......................................................................................................................................................................................... 23 WALLER LNG SERVICES ........................................................................................................................................................................................ 24 PANGEA LNG ............................................................................................................................................................................................................ 25 GASFIN ....................................................................................................................................................................................................................... 26 FREEPORT McMORAN ............................................................................................................................................................................................ 27 VENTURE GLOBAL .................................................................................................................................................................................................. 28 ADVANCED ENERGY SOLUTIONS ....................................................................................................................................................................... 30 BARCA ........................................................................................................................................................................................................................ 31


October 29, 2014


EOS .............................................................................................................................................................................................................................. 32 DELFIN ....................................................................................................................................................................................................................... 33 TEXAS LNG ............................................................................................................................................................................................................... 34 ARGENT MARINE ..................................................................................................................................................................................................... 35 ANNOVA LNG ........................................................................................................................................................................................................... 36 LOUISIANA LNG ....................................................................................................................................................................................................... 37 ALTURAS LNG .......................................................................................................................................................................................................... 38 STROM INC. ............................................................................................................................................................................................................... 39 SCT&E LNG ............................................................................................................................................................................................................... 40 DOWNEAST LNG ...................................................................................................................................................................................................... 41 ALASKA LNG ............................................................................................................................................................................................................ 42 Note: This matrix only covers LNG export proposals that have filed an application either for exports to free trade agreement countries (FTA) or exports to non-FTA countries with the U.S. Department of Energy, Office of Fossil Energy (DOE). It does not include proposals to export compressed natural gas or natural gas by pipeline.


October 29, 2014


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APPLICANT (OWNER) LOCATION PLANNED IN

SERVICE DATE IMPORT CAPACITY HOLDERS EXPORT CAPACITY HOLDERS

Sabine Pass Liquefaction LLC (Cheniere Energy)

Cameron Parish, Louisiana

2015 Brownfield on existing import facility

Chevron Total Cheniere Marketing, Inc.

BG Gulf Coast LNG Gas Natural Fenosa KOGAS Gail (India) Total Gas & Power Centrica

DO

E PR

OC

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NFTA APPLICATION NFTA APPLICATION STATUS

NFTA APPLICATION VOLUME

FTA APPLICATION FTA APPLICATION STATUS

FTA APPLICATION VOLUME

Dkt. 10-111-LNG Sept. 7, 2010

Approved May 20, 2011 -Conditional on FERC Review Aug. 7, 2012 - Final Order

2.2 Bcf/d (non-additive of FTA)

Dkt. 10-85-LNG Aug. 11, 2010

Approved Sept. 7, 2010

2.2 Bcf/d (non-additive of NFTA)

Dkt. 13-30-LNG (Train 5) Feb. 27, 2013

Pending


Dkt. 13-30-LNG Feb. 27, 2013

Approved July 11, 2013


Dkt. 13-42-LNG (Train 6) Apr. 2, 2013

Pending


Dkt. 13-42-LNG Apr. 2, 2013



Dkt. 13-121-LNG (Trains 5 and 6 remainder volumes) Sept. 10, 2013

Pending


Dkt. 13-121-LNG Sept. 10, 2013

Approved Jan. 22, 2014


Dkt. 14-92-LNG July 11, 2014

Pending 0.56 Bcf/d


October 29, 2014


SABINE PASS LIQUEFACTION, LLC FE

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FERC FILING DATE FERC STATUS NEPA REVIEW NOTES

Dkt. CP11-72 Application filed Jan. 31, 2011

Approved Apr. 16, 2012

EA

Dkt. CP14-12 Application filed Oct. 25, 2013

Approved Feb. 20, 2014

Not Applicable - Application to amend Sabine Pass LNG’s Section 3 authorization to increase LNG production capacity from 2.2 Bcf/d to 2.76 Bcf/d - FERC denied request for rehearing on Sept. 18, 2014

Dkt. CP13-552 and CP13-553 Application filed Sept. 30, 2013

Pending

EA

- Expansion project for Trains 5 and 6 and Cheniere Creole Trail Pipeline application - EA delayed from planned Aug. 1, 2014 issuance due to Cheniere’s proposed design modifications


October 29, 2014


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Cameron LNG, LLC (Sempra Energy)

Cameron Parish (Hackberry), Louisiana

Train 1 - July 2017 Train 2 - Jan 2018 Train 3 - July 2018 Brownfield on Existing Import Facility

Sempra ENI

GDF Suez Mitsubishi Mitsui &Co

DO

E PR

OC

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Dkt. 11-162-LNG Dec. 21, 2011

Approved Feb. 11, 2014 - Conditional on FERC Review Sept. 10, 2014 - Final Order Oct. 10, 2014 - Sierra Club filed Request for Rehearing


Dkt. 11-145-LNG Dec. 21, 2011




October 29, 2014


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Dkt. CP13-25 Application filed Dec. 7, 2012

Approved June 19, 2014

EIS - PHMSA approved design spill methodology Nov. 18, 2013 - Final EIS issued Apr. 30, 2014 - FERC Order approving project issued June 19, 2014

- Sierra Club, et al. requested rehearing out of time and FERC rejected; FERC’s rejection of the request for rehearing included its own rehearing period - Sierra Club et al., requested rehearing of the rejection on Aug. 8, 2014 - FERC denied rehearing request on Sept. 26, 2014

- Sierra Club filed timely petition in U.S. Court of Appeals for DC Circuit to appeal FERC orders approving project


October 29, 2014


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IMPORT CAPACITY HOLDERS EXPORT CAPACITY HOLDERS

Freeport LNG Development (multiple partners, including Osaka Gas, Dow Chemical)

Quintana Island (Freeport, Texas area)


Dow ConocoPhillips

Osaka Gas Co. Chubu Electric Power Co. BP SK E&S (Korea) Toshiba Corp.

DO

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OC

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Dkt. 10-161-LNG Dec. 17, 2010

Approved May 17, 2013 -Conditional on FERC Review


Dkt. 10-160-LNG Dec. 17, 2010



Dkt. 11-161-LNG Dec. 19, 2011

Approved Nov. 15, 2013 -Conditional on FERC Review

1.4 Bcf/d ** (non-additive of FTA) ** DOE only authorized 0.4 Bcf/d due to capacity of facilities

Dkt. 12-06-LNG Jan. 12, 2012




October 29, 2014


FREEPORT LNG EXPANSION, LP AND FLNG LIQUEFACTION, LLC FE

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Dkts. CP12-509 and CP12-29 Application filed Aug 31, 2012


EIS - PHMSA approved design spill modeling Dec. 31, 2013 - Final EIS issued June 16, 2014 - FERC Order granting conditional approval issued July 30, 2014

- Sierra Club and Galveston Baykeeper filed a request for rehearing on Aug. 29, 2014 - On Sept. 29, 2014, FERC issued tolling order granted itself unlimited additional time to consider the request for rehearing

- General Conformity Determination Report filed on Sept. 15, 2014


October 29, 2014


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Corpus Christi Liquefaction, LLC (Cheniere Energy)

Corpus Christi Bay, Texas

2017 To be built on the FERC approved, but never constructed import site

N/A - PT Pertamina - Endesa - Iberdrola - Électricité de France (EDF) - Woodside Energy Trading Singapore Pte Ltd - Gas Natural Fenosa LNG (GNF)

DO

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Dkt. 12-97-LNG Aug. 31, 2012 Filed request to amend application to include Corpus Christi Liquefaction, LLC as an additional applicant

Pending 2.1 Bcf/d (non-additive of FTA)

Dkt. 12-99-LNG Aug. 31, 2012

Approved Oct. 16, 2012 Filed request to amend authorization to include Corpus Christi Liquefaction, LLC as an authorized exporter


FER

C

PRO

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Docket: CP12-507 Application filed Aug. 31, 2012

Pending

EIS - PHMSA approved design spill methodology Feb. 10, 2014 - Draft EIS issued on June 13, 2014 - Final EIS published on Oct. 8, 2014

- KLG estimate: FERC Order likely by Dec. 18, 2014


October 29, 2014


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Dominion Cove Point LNG LP (Dominion Resources)

Calvert County, Maryland


BP Energy Shell NA LNG Statoil Natural Gas

Sumitomo GAIL

DO

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ESS NFTA APPLICATION NFTA APPLICATION

STATUS NFTA APPLICATION VOLUME



Dkt. 11-128-LNG Oct. 3, 2011

Approved Sept. 11, 2013 - Conditional on FERC Review

1.0 Bcf/d** (non-additive of FTA) **authorized for 0.77 Bcf/d

Dkt. 11-115-LNG Sept. 1, 2011

Approved Oct. 7, 2011


FER

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S


Dkt. CP13-113 Application filed Apr. 1, 2013


EA - PHMSA approved design spill modeling Feb. 27, 2014 - EA issued May 15, 2014 - Applicant provided documents under seal to Patuxent Riverkeeper per FERC order; comments were due July 11, 2014 - FERC issued order approving project on Sept. 29, 2014 - Sierra Club and other environmental intervenors

submitted a request for rehearing and motion for stay on Oct. 15, 2014


October 29, 2014


JORDAN COVE G

ENER

AL

INFO

RM

ATI

ON



Jordan Cove Energy Project, LP (Veresen)

Coos Bay, Oregon Projected 2017 To be built on FERC-approved, but never constructed import site

N/A None at this time

DO

E PR

OC





Dkt. 12-32-LNG Mar. 23, 2012

Approved Mar. 24, 2014 - Conditional on FERC review

0.8 Bcf/d Dkt. 11-127-LNG Sept. 22, 2011

Approved Dec. 7, 2011

1.2 Bcf/d

FER

C P

RO

CES

S


Dkt. CP13-483 and CP13-492 Applications filed May 21, 2013 and June 5, 2013

Pending

EIS - PHMSA approved design spill modeling methodology on June 18, 2014 - Final EIS scheduled to be released Feb. 27, 2015

- FERC memorandum released Aug. 28, 2014, notes that the schedule for the draft EIS has “slipped” due to vapor dispersion modeling, which may in turn delay the release of the final EIS - FERC stated that failure to submit vapor dispersion modeling is delaying publication of the DEIS - Jordan Cove LNG submitted additional vapor

dispersion modeling on Sept. 23, 2014


October 29, 2014


OREGON LNG G

ENER

AL

INFO

RM

ATI

ON



LNG Development Company, LLC

Warrenton, Oregon 2017 (unlikely) Greenfield


DO

E PR

OC

ESS NFTA APPLICATION

NFTA APPLICATION STATUS




Dkt. 12-77-LNG Jul. 16, 2012

Approved July 31, 2014 - Conditional on FERC review


Dkt. 12-48-LNG May 3, 2012

Approved May 31, 2012


FER

C

PRO

CES

S


Dkt. CP09-6 Application filed June 7, 2013

Pending

EIS - On Oct. 2, 2014, PHMSA issued a “no objection” letter signing off on proposed design spill methodology - Schedule of Environmental Review not issued yet


October 29, 2014


EXCELERATE G

ENER

AL

INFO

RM

ATI

ON



Excelerate Liquefaction Solutions I, LLC

Calhoun County (Lavaca Bay), Texas

2017 New Floating Facility


DO

E PR

OC

ESS





Dkt. 12-146-LNG Oct. 5, 2012

Pending


Dkt. 12-61-LNG May 25, 2012

Approved Aug. 9, 2012


FER

C

PRO

CES

S


Docket: CP14-71 Application filed Feb. 6, 2014

Pending

EIS - PHMSA has not yet given approval of design spill modeling - Schedule of Environmental Review not issued yet


October 29, 2014


SOUTHERN LNG G

ENER

AL

INFO

RM

ATI

ON


SERVICE DATE IMPORT CAPACITY HOLDERS

EXPORT CAPACITY HOLDERS

Southern LNG Company (Kinder Morgan)

Savannah, Georgia Phase I - Dec 2015 Phase II - Dec 2016 (highly unlikely given current timing) Brownfield on existing import facility

BG LNG Services Shell NA LNG

Shell US Gas & Power (through JV LLC formed with Kinder Morgan)

DO

E PR

OC

ESS



FTA APPLICATION

FTA APPLICATION STATUS


Dkt. 12-100-LNG Aug. 31, 2012

Pending


Dkt. 12-54-LNG May 15, 2012



FER

C P

RO

CES

S FERC FILING DATE FERC STATUS NEPA REVIEW NOTES

Docket: CP14-103 Application filed Mar. 10, 2014

Pending

EA - PHMSA has not yet given approval of design spill modeling - Schedule of Environmental Review not issued yet - Southern LNG submitted a series of Optimization Update Packages that include project modifications on Sept. 13, 2014


October 29, 2014


TRUNKLINE G

ENER

AL

INFO

RM

ATI

ON



Lake Charles Export LLC (Jointly owned subsidiary of Energy Transfer Equity and BG Group)

Lake Charles, Louisiana


BG LNG Services BG

DO

E PR

OC

ESS





Dkt. 11-59-LNG May 6, 2011

Approved Aug. 7, 2013 - Conditional on FERC Review

2.0 Bcf/d (non-additive of FTA) ** for BG

Dkt. 11-59-LNG May 6, 2011



Dkt. 13-04-LNG Jan. 10, 2013

Pending

2.0 Bcf/d (non-additive of FTA and previous authorization) ** for any other offtaker

Dkt. 13-04-LNG Jan. 10, 2013

Approved Mar. 7, 2013

2.0 Bcf/d (non-additive of NFTA and previous authorization)


October 29, 2014


* * Total volume requested for export is 2.0 Bcf/d - Trunkline’s requests are non-additive

TRUNKLINE FE

RC

PR

OC

ESS FERC FILING DATE FERC STATUS NEPA REVIEW NOTES

Dkt. CP14-120 Application filed Mar. 25, 2014

Pending EIS - On Sept. 19, 2014, PHMSA issued a “no objection” letter signing off on proposed design spill methodology - Schedule of Environmental Review not issued yet


October 29, 2014


MAGNOLIA LNG G

ENER

AL

INFO

RM

ATI

ON



Magnolia LNG LLC (subsidiary of Liquefied Natural Gas Limited (Australia))

Port of Lake Charles, Louisiana

2018 Greenfield

N/A Gas Natural Fenosa Gunvor Group LNG Holdings AES Corp.

DO

E PR

OC

ESS





Dkt. 13-132-LNG Oct. 12, 2013

Pending


Dkt. 12-183-LNG Dec. 18, 2012



Dkt. 13-131-LNG Oct. 15, 2013



FER

C P

RO

CES


Dkt. CP14-347 Application filed Apr. 30, 2014

Pending EIS - On Sept. 15, 2014, U.S. Coast Guard issued a Letter of Recommendation approving Magnolia LNG’s Waterway Suitability Assessment - On Sept. 17, 2014, PHMSA issued a “no objection” letter for Magnolia LNG’s design spill methodology - Schedule of Environmental Review not issued yet


October 29, 2014


CE FLNG G

ENER

AL

INFO

RM

ATI

ON



CE FLNG, LLC (Cambridge Energy Holdings, LLC)

Plaquemines Parish, Louisiana

Unclear New Floating Facility

N/A

None at this time

DO

E PR

OC





Dkt. 12-123-LNG Sept. 21, 2012

Pending


Dkt. 12-123-LNG Sept. 21, 2012

Approved Nov. 21, 2012


FER

C P

RO

CES


Dkt. PF13-11 Pre-filing initiated Apr. 1, 2013

In pre-filing EIS - PHMSA has not yet given approval of design spill modeling - Developer indicates Draft RR13 will be submitted to FERC on or about Nov. 15, 2014, and will submit its FERC application approximately May 15, 2015 - FERC requested status update on Aug. 1, 2014, to be submitted within 30 days - CE FLNG submitted a status report on Aug. 29, 2014


October 29, 2014


GULF LNG G

ENER

AL

INFO

RM

ATI

ON



Gulf LNG Liquefaction Company, LLC (Primary Owners are Kinder Morgan and GE Energy Financial Services)

Pascagoula, Mississippi

Unclear Brownfield on Existing Import Facility

Angola LNG

None at this time

DO

E PR

OC





Dkt. 12-101-LNG Aug. 31, 2012

Pending


Dkt. 12-47-LNG May 2, 2012



FER

C P

RO

CES


Dkt. PF13-4 Pre-filing initiated Dec. 5, 2012; approved for pre-filing May 21, 2014

In pre-filing EA - PHMSA has not yet given approval of design spill modeling - Draft RR 13 not yet filed


October 29, 2014


GULF COAST LNG G

ENER

AL

INFO

RM

ATI

ON

Applicant (Owner) Location Planned In Service Date

Import Capacity Holders Export Capacity Holders

Gulf Coast LNG Export, LLC

Port of Brownsville, Texas

2018 Greenfield


DO

E PR

OC

ESS





Dkt. 12-05-LNG Jan. 10, 2012

Pending


Dkt. 12-05-LNG Jan. 10, 2012



FER

C

PRO

CES

S


Not yet applied N/A N/A N/A


October 29, 2014


GOLDEN PASS G

ENER

AL

INFO

RM

ATI

ON



Golden Pass Products, LLC (Owners are affiliates of ExxonMobil and Qatar Petroleum)

Sabine Pass, Texas

Unclear Brownfield on Existing Import Terminal

Qatar Gas Exxon-Mobil

Qatar Gas ExxonMobil (Joint venture partners)

DO

E PR

OC

ESS





Dkt. 12-156-LNG Oct. 25, 2012

Pending


Dkt. 12-88-LNG Aug. 17, 2012



FER

C

PRO

CES

S


Dkt. CP14-517 Application filed July 7, 2014

Pending EA - PHMSA has not yet given approval of design spill modeling


October 29, 2014


CARIB ENERGY G

ENER

AL

INFO

RM

ATI

ON



Carib Energy LLC

Variety of locations -- small scale liquefaction via ISO tanks for export to Caribbean

2012 N/A None at this time

DO

E PR

OC

ESS





Dkt. 11-141-LNG Oct. 20, 2011


0.01 Bcf/d Dkt. 11-71-LNG June 2, 2011


0.03 Bcf/d (additive of NFTA)

FER

C

PRO

CES

S


N/A N/A N/A - No new facilities proposed; potentially no FERC application required


October 29, 2014


SB POWER SOLUTIONS G

ENER

AL

INFO

RM

ATI

ON



SB Power Solutions Inc. (Seaboard Corporation)

Locations on the Gulf and Atlantic Coasts

2014 N/A None at this time

DO

E PR

OC

ESS





None N/A N/A Dkt. 12-50-LNG May 7, 2012


0.07 Bcf/d

FER

C

PRO

CES


N/A N/A N/A - No new facilities proposed; potentially no FERC application required


October 29, 2014


WALLER LNG SERVICES

GEN

ERA

L IN

FOR

MA

TIO

N APPLICANT (OWNER) LOCATION PLANNED IN


Waller LNG Services, LLC (Waller Marine, Inc.)

Cameron Parish, Louisiana (multiple small-scale locations along Gulf Coast

Unclear Greenfield


DO

E PR

OC

ESS





Dkt. 13-153-LNG Nov. 26, 2013

Pending

0.19 Bcf/d Dkt. 12-152-LNG Oct. 12, 2012

Approved Dec. 20, 2012

0.16 Bcf/d

FER

C

PRO

CES

S


Not yet applied


October 29, 2014


PANGEA LNG G

ENER

AL

INFO

RM

ATI

ON



Pangea LNG (North America) Holdings (Majority shareholder is Daewoo Shipbuilding & Marine Engineering)

Near shore Ingleside, Texas

Unclear Greenfield

N/A None at this time (Originally Statoil was slated to be a partner, but has since withdrawn)

DO

E PR

OC

ESS





Dkt. 12-184-LNG Dec. 19, 2012

Pending


Dkt. 12-174-LNG Nov. 29, 2012



FER

C

PRO

CES

S


Not yet applied


October 29, 2014


GASFIN G

ENER

AL

INFO

RM

ATI

ON



Gasfin Development USA, LLC

Cameron Parish, Louisiana

Unclear


DO

E PR

OC

ESS





Dkt. 13-161-LNG Dec. 24, 2013

Pending


Dkt. 13-06-LNG Jan. 11, 2013



FER

C

PRO

CES

S


Not yet applied


October 29, 2014


** This is the same project as the Main Pass Energy, which was withdrawn on Sept. 18, 2014.

FREEPORT McMORAN G

ENER

AL

INFO

RM

ATI

ON



Freeport-McMoRan Energy LLC (subsidiary of McMoRan Exploration Co.)

Main Pass Energy Hub, Offshore Louisiana Main Pass Block 299

Unclear Brownfield at Existing Platforms used for Sulfur Mining at the Main Pass Energy Hub

N/A Petronet LNG, Ltd.

DO

E PR

OC

ESS





Dkt. 13-26-LNG Feb. 22, 2013

Pending


Dkt. 13-26-LNG Feb. 22, 2013

Approved May 24, 2013


FER

C

PRO

CES

S


Would be permitted by the US Maritime Administration, not FERC


October 29, 2014


VENTURE GLOBAL G

ENER

AL

INFO

RM

ATI

ON



Venture Global LLC Cameron Parish, Louisiana

Unclear


DO

E PR

OC

ESS





Dkt. 13-69-LNG May 13, 2013 Filed request to amend application to include Venture Global Calcasieu Pass, LLC as an additional applicant

Pending


Dkt. 13-69-LNG May 13, 2013 Filed request to amend authorization to include Venture Global Calcasieu Pass, LLC as an authorized exporter



Dkt. 14-88-LNG May 13, 2014 Filed request to amend application to include Venture Global Calcasieu Pass, LLC as an additional applicant

Pending 0.67 Bcf/d (additive to initial application)

Dkt. 14-88-LNG May 13, 2014 Filed request to amend authorization to include Venture Global Calcasieu Pass, LLC as an authorized exporter


0.67 Bcf/d (additive to initial application)


October 29, 2014


VENTURE GLOBAL FE

RC

PR

OC

ESS


Dkt. PF15-2 Pre-filing initiated Oct 7, 2014; approved for pre-filing Oct. 10, 2014

In Pre-filing EIS

- PHMSA has not yet given approval of design spill modeling - No draft resource reports filed yet


October 29, 2014


ADVANCED ENERGY SOLUTIONS G

ENER

AL

INFO

RM

ATI

ON



Advanced Energy Solutions, LLC

Martin County, Florida (export via ISO containers from various ports)

End of 2015 (for liquefaction)


DO

E PR

OC

ESS





Not applied Dkt. 13-104-LNG Aug. 23, 2013


0.02 Bcf/d

FER

C

PRO

CES

S


- No new facilities proposed; potentially no FERC application required


October 29, 2014


BARCA G

ENER

AL

INFO

RM

ATI

ON



Barca LNG, LLC Port of Brownsville, Texas

Unclear N/A None at this time

DO

E PR

OC

ESS





Dkt. 13-118-LNG Aug. 23, 2013

Pending


Dkt. 13-117-LNG Aug. 23, 2013



FER

C

PRO

CES

S


Not yet applied


October 29, 2014


EOS G

ENER

AL

INFO

RM

ATI

ON



Eos LNG, LLC Port of Brownsville, Texas


DO

E PR

OC

ESS





Dkt. 13-116-LNG Aug. 23, 2013

Pending


Dkt. 13-115-LNG Aug. 23, 2013



FER

C

PRO

CES

S


Not yet applied


October 29, 2014


DELFIN G

ENER

AL

INFO

RM

ATI

ON



Delfin LNG, LLC West Cameron Block 167 offshore Cameron Parish, Louisiana


DO

E PR

OC

ESS





Dkt. 13-147-LNG Nov. 12, 2013

Pending


Dkt. 13-129-LNG Oct. 7, 2013



FER

C

PRO

CES

S


- Would be permitted by the US Maritime Administration, not FERC - FERC approved Enbridge sale of UTOS offshore pipeline system to Delfin LNG on Sept. 17, 2014


October 29, 2014


TEXAS LNG G

ENER

AL

INFO

RM

ATI

ON



Texas LNG, LLC Port of Brownsville, Texas


DO

E PR

OC

ESS





Dkt. 13-160-LNG Dec. 31, 2013

Pending


Dkt. 13-160-LNG Dec. 31, 2013



FER

C

PRO

CES

S


Not yet applied


October 29, 2014


ARGENT MARINE G

ENER

AL

INFO

RM

ATI

ON



Argent Marine Management, Inc.

ISO containers from any port

N/A N/A None at this time

DO

E PR

OC

ESS





Dkt. 13-105-LNG Aug. 29, 2013


0.003 Bcf/d

FER

C

PRO

CES

S




October 29, 2014


ANNOVA LNG G

ENER

AL

INFO

RM

ATI

ON



Annova LNG, LLC (Exelon)

Port of Brownsville, Texas


DO

E PR

OC

ESS





Not applied Dkt. 13-140-LNG Oct. 19, 2013


0.94 Bcf/d

FER

C

PRO

CES

S


Not yet applied


October 29, 2014


LOUISIANA LNG G

ENER

AL

INFO

RM

ATI

ON



Louisiana LNG Energy, LLC

Plaquemines Parish, Louisiana


DO

E PR

OC

ESS





Dkt.14-29-LNG Feb. 18, 2014


Dkt. 14-19-LNG Feb. 5, 2014

Approved Aug. 28, 2014

0.28 Bcf/d (non- additive of NFTA)

FER

C P

RO

CES


Dkt. PF14-17 Pre-filing initiated July 11, 2014; approved for pre-filing July 18, 2014

In pre-filing - On Oct. 3, 2014, FERC issued a Notice of Intent to prepare an environmental impact statement

- Scoping period closes Nov. 3, 2014 - Draft Resource Reports 1 and 10 submitted Aug. 18, 2014 - Draft Resource Reports 2-9 and 12 submitted Oct. 15, 2014 - Project developer reports that it now projects its Section 3 application will be filed in Feb. 2015, not Jan. 2015


October 29, 2014


ALTURAS LNG G

ENER

AL

INFO

RM

ATI

ON



WesPac Midstream Port Arthur, Texas N/A None at this time

DO

E PR

OC

ESS





Dkt. 14-55-LNG Apr. 18, 2014

Pending

0.2 Bcf/d

FER

C

PRO

CES

S




October 29, 2014


STROM INC. G

ENER

AL

INFO

RM

ATI

ON



Strom, Inc. Starke, Florida N/A None at this time

DO

E PR

OC

ESS





Dkt. 14-57-LNG Apr. 18, 2014

Pending

0.02 Bcf/d (additive of FTA)

Dkt. 14-56-LNG Apr. 18, 2014


0.08 Bcf/d (additive of NFTA)

Dkt. 14-58-LNG Apr. 18, 2014

Pending

0.02 Bcf/d (additive of FTA and previous NFTA)

FER

C

PRO

CES

S




October 29, 2014


SCT&E LNG G

ENER

AL

INFO

RM

ATI

ON



SCT&E LNG Lake Charles, Louisiana


DO

E PR

OC

ESS





Dkt. 14-98-LNG July 24, 2014


Dkt. 14-89-LNG July 9, 2014

Pending


FER

C

PRO

CES

S


Not yet applied


October 29, 2014


DOWNEAST LNG G

ENER

AL

INFO

RM

ATI

ON



Downeast Liquefaction, LLC Downeast LNG, Inc.

Robbinston, Maine 2019 None at this time None at this time

DO

E PR

OC

ESS





Dkt. 14-176-LNG Oct. 15, 2014


Dkt. 14-172-LNG Oct. 15, 2014

Pending

0.46 Bcf/d (non-additive of non-FTA)

FER

C P

RO

CES

S


Dkt. CP07-52 [Import] Application filed Dec. 22, 2006 Dkt. PF14-19 [Bi-directional] Initiated on July 22, 2014

Original import docket suspended In pre-filing for bi-directional terminal

EIS EA or EIS

- PHMSA approved design spill methodology Jan. 1, 2014 - Final EIS for import project issued May 15, 2014 - FERC approved bi-directional pre-filing request on August 11, 2014 - Timing of FERC Order dependent on duration of pre-filing process for bi-directional proposal, whether FERC prepares an EA or EIS for the revised project, and complexity of the bi-directional proposal and attendant modifications to the import proposal - FERC suspended schedule for environmental review of original import terminal on Aug. 7, 2014 - On Oct. 3, 2014, FERC issued on Notice of Intent to prepare an environmental impact statement

- Scoping period closes Nov. 3, 2014


October 29, 2014


ALASKA LNG G

ENER

AL

INFO

RM

ATI

ON



Alaska LNG Project LLC

- ExxonMobil Alaska LNG LLC

- ConocoPhillips Alaska LNG Co.

- BP Alaska LNG LLC Other project partners

include: - TransCanada Alaska

Midstream LP - Alaska Gasline

Development Corp.

Nikiski, Alaska 2024-2025 None at this time None at this time

DO

E PR

OC

ESS





Dkt. 14-96-LNG* * July 18, 2014

Pending 2.55 Bcf/d Dkt. 14-96-LNG July 18, 2014

Pending 2.55 Bcf/d

FER

C P

RO

CES


Dkt. PF14-21 Pre-filing initiated Sept. 5, 2014; approved for pre-filing Sept. 12, 2014

Pre-filing EIS - Project proposes three liquefaction trains with a combined processing and export capacity of 20 million metric tons per annum

- Project also includes an 800-mile pipeline to transport natural gas from Alaska’s North Slope to the liquefaction facility

* * In the Federal Register Notice of its final revised procedures for processing non-FTA LNG export applications, DOE explains that the revised procedures only will apply to LNG export projects in the lower-48 states, not projects in Alaska. DOE explicitly stated that it will consider whether to issue a conditional LNG export authorization for the Alaska LNG application, or any future application to export from Alaska, in the context of those proceedings.


October 29, 2014


For LNG-related questions, please contact one of these members of the K&L Gates LNG Team

LNG Team Leaders

John King Partner, Perth +61.8.9216.0952 [email protected]

Clare Power Partner, Perth +61.8.9216.0902 [email protected]

Steven Sparling Partner, Washington, DC / Houston +1.202.778.9085 [email protected]

David L. Wochner Partner, Washington, DC +1.202.778.9014 [email protected]

Clive Cachia Special Counsel, Sydney +61.2.9513.2515 [email protected]

Louisiana W. Cutler Partner, Anchorage +1.907.777.7630 [email protected]

Brian K. Knox Partner, Seattle +1.206.370.6791 [email protected]

Sergey Milanov Partner, Tokyo +81.3.6205.3604 [email protected]

James A. Sartucci Government Affairs Counselor Washington, DC +1.202.778.9374 [email protected]

Matthew Smith Partner, London +44.20.7360.8246 [email protected]

Lian Yok Tan Partner, Singapore +65.6507.8105 [email protected]

Stephen Thompson Partner, Sydney +61.2.9513.2399 [email protected]

Grace Fan-Delatour Counsel, Beijing +86.10.5817.6105 [email protected]

Lindsey A. Greer Associate, Charleston +1.843.579.5641 [email protected]

Jonathan L. Hoff Counsel, Houston +1.713.815.7303 [email protected]

Christine A. Jochim Associate, Washington, DC +1.202.778.9222 [email protected]

Amy M. Matschekowski Special Projects Attorney, Washington, DC +1.202.778.9118 [email protected]

Mike O’Neill Associate, Washington, DC +1.202.778.9037 [email protected]

Allyson Pait Associate, Houston +1.713.815.7311 [email protected]

Sandra E. Safro Associate, Washington, DC +1.202.778.9178 [email protected]

http://www.klgates.com/john-king/

http://www.klgates.com/clare-power/

http://www.klgates.com/steven-c-sparling/

http://www.klgates.com/david-l-wochner/

http://www.klgates.com/clive-laurence-cachia/

http://www.klgates.com/louisiana-w-cutler/

http://www.klgates.com/brian-k-knox/

http://www.klgates.com/brian-k-knox/

http://www.klgates.com/sergey-j-milanov/

http://www.klgates.com/james-a-sartucci/

http://www.klgates.com/matthew-e-smith

http://www.klgates.com/lian-yok-tan/

http://www.klgates.com/stephen-thompson/

http://www.klgates.com/grace-fan-delatour/

http://www.klgates.com/grace-fan-delatour/

http://www.klgates.com/lindsey-a-greer/

http://www.klgates.com/jonathan-l-hoff/

http://www.klgates.com/christine-a-jochim/?nomobile=temp

http://www.klgates.com/amy-m-matschekowski/

http://www.klgates.com/michael-l-oneill/

http://www.klgates.com/michael-l-oneill/

http://www.klgates.com/allyson-pait/

http://www.klgates.com/sandra-e-safro/

http://www.klgates.com/sandra-e-safro/


October 29, 2014


DOCUMENT2 5/27/2014 1:27 PM

FRACTURING RELATIONSHIPS: THE IMPACT OF RISK AND RISK ALLOCATION

ON UNCONVENTIONAL OIL AND GAS PROJECTS*

DAVID H. SWEENEY, PRESTON CODY, SUSAN LINDBERG, MICHAEL P. DARDEN**

I. INTRODUCTION ................................................................................. 290 II. RISK AND RISK ALLOCATION IN CONVENTIONAL PROJECTS ..... 292

A. Conventional Phases and Risks ............................................... 293 B. Risk Allocation in Conventional Projects .............................. 294

III. HOW ARE UNCONVENTIONALS DIFFERENT? ............................... 296 A. Phases of an Unconventional Project ...................................... 297

1. Concept Phase ..................................................................... 297 2. Pilot Phase ............................................................................ 298 3. Ramp-Up .............................................................................. 299 4. Exploitation Phase .............................................................. 300

B. Unconventional Risk Profile .................................................... 301 1. Exploration Risks ................................................................ 301 2. Operational Risks ................................................................ 303 3. External Risks ...................................................................... 304

C. Impact on Joint Development ................................................. 305 IV. CONTRACTUAL ALLOCATION OF UNCONVENTIONAL RISK ....... 306

A. Exploration: Concept Risk ....................................................... 308 B. Exploration: Acreage Prospectivity Risk and Well

Variability ................................................................................... 311 1. Sub-Areas ............................................................................. 312 2. Step-Down Premium Matrix .............................................. 313 3. No Non-Consent Permitted................................................ 314

* This Article was first published by the Institute for Energy Law on February 20, 2014 as

part of the proceedings of its 65th Annual Oil & Gas Law Conference in Houston, Texas. ** David H. Sweeney is Of Counsel in the Houston, Texas office of K&L Gates LLP.

Michael P. Darden is a Partner in the Houston office of Latham & Watkins LLP and is the Chair of Latham’s Oil & Gas Transactions Practice and Co-Chair of the global Oil & Gas Industry Team. Susan Lindberg is General Counsel of Eni US Operating Co. Inc. Preston Cody is a Senior Managing Consultant with Wood Mackenzie in Houston. The contents of this Article reflect the individual opinions of the authors and not the positions of Wood Mackenzie, Eni Petroleum US LLC, Latham & Watkins LLP, or K&L Gates LLP (or any of their respective affiliates).

DOCUMENT2 5/27/2014 1:27 PM

290 TEXAS JOURNAL OF OIL, GAS, AND ENERGY LAW [Vol. 9

4. Under-Development and the CAPL Challenge of Operator Procedure ............................................................ 314

C. Operational Risks ...................................................................... 315 D. External Risks ............................................................................ 317

V. CONCLUSION ..................................................................................... 318

I. INTRODUCTION

Some commentators have suggested that unconventional1 oil and gas projects are akin to manufacturing.2 While there is some truth in this analogy, it is misleading. Unconventional plays are indeed different than conventional plays, but they do not represent the riskless manufacture of barrels or Btus. Unconventional projects have the same basic set of risks—from geological failure to commodity prices—as their conventional counterparts, and in some cases, additional risks that do not materially affect conventional projects. However, these risks apply differently during a project’s lifecycle and are typically different in degree and source. Thus, the de-risking process is necessarily different—in this case, more gradual. This Article focuses on exploration risks, operational risks, and external risks that have proven to be the most relevant to the development of unconventional oil and gas projects through their unique lifecycle and suggests an alternative analytical and contractual framework to more effectively evaluate and deal with them.

Unconventional oil and gas resources, specifically oil and gas extracted from geological systems of low porosity and/or permeability, such as shale, have changed the face of the United States’ domestic exploration and production business. From an economic perspective, “[o]ngoing improvements in advanced technologies for crude oil and natural gas production continue to lift domestic supply and reshape the U.S. energy economy.”3 These “advanced technologies” (which might be more appropriately labeled novel combinations of existing production techniques—namely, horizontal drilling and hydraulic fracturing)

1. “Unconventional” has many meanings in the oil and gas industry. In the context of this

Article, however, it refers solely to hydrocarbon-bearing formations of low porosity and/or permeability that must be drilled horizontally and hydraulically fractured in order to produce economically. “Unconventional” specifically does not refer to coalbed methane, deepwater or deep gas operations, oil sands, or the like, although the manner in which agreements governing these types of assets differ from agreements governing “normal” accumulation-type assets may be instructive, as described below.

2. See, e.g., Emily Pickrell, Moody’s: Risk of a Dry Hole Has Fallen Nearly to Zero, FUELFIX (June 13, 2013), http://fuelfix.com/blog/2013/06/14/moodys-risk-of-a-dry-hole-has-fallen -nearly-to-zero/ (“The risk of drilling a dry hole has fallen nearly to zero, and E&P companies are developing a repeatable, manufacturing-style approach to unconventional resources.”).

3. U.S. ENERGY INFO. ADMIN., ANNUAL ENERGY OUTLOOK 2014: EARLY RELEASE OVERVIEW 1 (2014), available at http://www.eia.gov/forecasts/aeo/er/pdf/0383er(2014).pdf.

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No. 2] FRACTURING RELATIONSHIPS 291

required to economically produce hydrocarbons from shale necessitate equally novel ways of looking at the risks associated with each phase in the lifecycle of these projects. Novel contractual structures are arguably required to deal with this difference in risk profile.

Specific joint venture transactions among large, sophisticated oil and gas companies have provided, in some respects, innovative solutions to the risk profile problems posed by unconventional projects.4 In general, however, the domestic exploration and production industry has been, and continues to be, rooted solidly in norms that are more appropriate for, and evolved to deal with, conventional assets. There are numerous examples of the legal and commercial sectors of the oil and gas industry attempting to adapt entrenched ways of doing things to evolving physical realities,5 but on the whole, these seem to be just that—adaptations to the way that these assets are physically developed without a fundamental (re-)analysis of the risks that parties take in developing them. Large joint venture transactions have utilized interesting risk-sharing mechanisms, but, innovative as these might be, their lessons and concepts do not seem to have effected fundamental change on an industry-wide scale. The “rock doctors” and engineers have effectively adapted. Commercial negotiators and lawyers generally have not.

With this in mind, the purpose of this Article is not to propose the definitive solution to these issues or to (purposefully) tread on the sacrosanct. Rather, we seek to show potentially different ways to conceptualize certain risks common to most unconventional projects and suggest means of dealing with these risks from a contractual perspective that are more closely tailored to the issues they are trying to address. We propose that unconventional projects are conceptually just as risky from a profitability perspective as their conventional counterparts.6 The subject

4. Representative deals include Eni’s Barnett Shale transaction with Quicksilver Resources

in 2009, Reliance’s Marcellus Shale transaction with Atlas in 2010, Exco’s Marcellus Shale and Haynesville Shale transactions with BG Group in 2009 and 2010, Statoil’s Marcellus Shale deal with Chesapeake in 2008, Range Resources’ transaction with Talisman in 2010, Chesapeake’s Barnett Shale transaction with Total in 2010, Chesapeake’s Eagle Ford transaction with CNOOC in 2010, and NiSource and Hilcorp’s Utica Shale deal in 2012, as well as a number of private transactions, the existence and terms of which cannot be disclosed publicly.

5. See, e.g., Jeff Weems & Amy Tellegen, The New Horizontal Agreement and the Prospect of an Entirely New Form, 31 ST. B. TEX. ADVANCED OIL, GAS & ENERGY L. COURSE, ch. 3 (2013); Mark Matthews & Christopher S. Kulander, Additional Provisions to Form Joint Operating Agreements, 33 ST. B. TEX. OIL, GAS & ENERGY RESOURCES L. SEC. REP., no. 2, Dec. 2008; Mark D. Christiansen & Wendy S. Brooks, A Different “Slant” on JOAs: New Developments in Shale Plays and Recent Court Rulings, 57 ROCKY MTN. MIN. L. INST., ch. 25 (2011); Lamont C. Larsen, Horizontal Drafting: Why Your Form JOA May Not Be Adequate for Your Company’s Horizontal Drilling Program, 48 ROCKY MTN. MIN. L. FOUND. J. 51 (2011). Issues with unconventionals were recognized by some commentators long before the shale “revolution.” See, e.g., ANDREW B. DERMAN, THE NEW AND IMPROVED 1989 JOINT OPERATING AGREEMENT: A WORKING MANUAL 3 (1991).

6. “Risk,” from the perspective of a lawyer—even a transactional lawyer—can refer to almost anything. In this Article, the term is used only in the sense of the risk of not making a

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matter of many of these risks is the same, regardless of the project; however, the unique combination of exploration risks, operational risks, and external risks, together with how, and how long, they apply over the course of a project, and how they are eliminated, gives unconventionals fundamentally different asset profiles.

The resulting difference in risk profile makes traditional methods of risk management potentially unsuitable for an unconventional project. We suggest that the “concept/pilot/ramp-up/exploit” framework identified by Wood Mackenzie may be more useful than the traditional “exploration/(appraisal)/development/production” project cycle frame-work.7 As has been implicitly recognized by the now-common joint venture8 structure for the development of shale assets, the inherent conflicts between parties caused by extended de-risking timeframes and the lack of discrete dividing lines among project lifecycle stages can be better managed through contractual mechanisms that keep parties together instead of affording them maximum autonomy. This, we believe, should hold true to some extent regardless of the specific contract at issue—be it joint venture, farmout, joint operating agreement, or otherwise.

II. RISK AND RISK ALLOCATION IN CONVENTIONAL PROJECTS9

A conventional oil and gas project generally progresses through the following relevant phases: (i) exploration (is there anything there?); (ii) appraisal (how much is there?); (iii) development (how do we produce and sell what is there?); and (iv) production (how much do we produce and sell?).10 The risk of a lack of commercial viability generally drops significantly upon the progression from one phase to the next, as

profit (or as much profit as modeled).

7. Preston Cody, Shale vs. Big Exploration: What Sorts of Risks Are You Taking?, E&P (Jan. 1, 2013), http://www.epmag.com/item/Shale-vs-big-exploration_111180.

8. The term “joint venture” is used in this Article as shorthand for the type of transaction described infra in Section IV. It is not meant to imply a legal partnership, which is not commonly used (outside of, perhaps, the tax context) for joint oil and gas development in the United States.

9. Much of the following discussion has been adapted or reproduced from a forthcoming training module on worldwide joint operating agreements to be published by the Institute for Energy Law. See DAVID H. SWEENEY, TRAINING MODULE: JOINT OPERATING AGREEMENTS (forthcoming 2014) (manuscript at 96–102) (on file with the Institute for Energy Law).

10. This Article focuses on risk in the exploration, development, and production phases and thus omits a discussion of plugging and abandonment as a distinct phase. Treatment of these phases varies widely depending on the specific agreement. In the United States, at least with respect to onshore assets, these phases are generally not expressed in as many words; however, the general framework still conceptually applies. By way of example, each version of the AAPL 610 operating agreement form contains a contractual requirement that the parties to the agreement participate in the first (initial) well in the contract area. Non-consent is not permitted in this case because, among other things, this first well, to a large extent, “de-risks” the contract area. Thus, allowing non-consent parties to participate in subsequent wells would allow them to benefit from the risks taken by the participating parties solely at the cost of a portion of the production from the initial, “exploratory” well.

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exploration risk (which can end a project entirely) gives way to other risks which can reduce the ultimate value of the project (though not necessarily cancel it). Thus, predictably, the further along a project is, the greater the freedom allowed to a party to participate or not participate in any given operation.

A. Conventional Phases and Risks

Most oil and gas projects begin with exploration—the search for a commercially viable accumulation of hydrocarbons.11 Exploratory operations can include geological and geophysical studies (including seismic shoots) and the drilling of exploratory wells.12 There is generally some doubt during this period about whether (and in what quantities) hydrocarbon deposits exist. Thus, exploratory operations are generally considered to be technically and economically riskier than most other types of operations. Decisions regarding whether to conduct these operations are made under uncertainty and are time sensitive, since a failure to conduct sufficient exploratory operations within a given timeframe may cause rights to terminate under almost any granting instrument.13 Consequently, participation in exploratory operations is generally mandatory and the consequences for failure to participate are severe.14

The exploration phase, and many of its attendant risks, typically ends with the drilling of an exploration well, which either definitively proves or disproves the existence of hydrocarbons. However, the mere existence of a discovery does not mean that hydrocarbons are present in quantities that make them worth producing, or that they can be produced economically. Further operations may be required “to verify the size, shape and nature of petroleum reserves and resources and to carry out an economic analysis”—in other words, to appraise the commercial viability of the discovery.15

Appraisal programs will improve the parties’ understanding of the size and quality of the reservoir and establish whether or not the reservoir achieves a minimum economic field size. At this point, the parties must make a final decision regarding investment in the substantial cost of

11. WILLIAM & MEYERS, MANUAL OF OIL AND GAS TERMS 380 (12th ed. 2003). 12. Id. 13. RICHARD W. HEMMINGWAY, THE LAW OF OIL AND GAS §§ 6.2 et seq. (3d ed. 1991). 14. E.g., AAPL FORM 610-1989: MODEL FORM OPERATING AGREEMENT arts. VI.A, VII.D

(1989) [hereinafter AAPL FORM 610]. 15. CLAUDE DUVAL ET AL., INTERNATIONAL PETROLEUM EXPLORATION AND

EXPLOITATION AGREEMENTS: LEGAL, ECONOMIC & POLICY ASPECTS § 9.10 (2d ed. 2009). As noted above, U.S. onshore agreements typically do not expressly delineate this phase. However, conceptually, it still exists, even if on a scale much larger than a single contract area. This phase becomes conceptually important in unconventional projects, and thus it has been specifically mentioned here.

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developing the project.16 If the parties are confident that a project can be developed economically, subsurface risk will generally no longer be applied as a risk factor to the entire project.17 The project will then proceed to the development phase, in which the parties create a plan to construct the infrastructure and drill the wells that are necessary to efficiently produce hydrocarbons from the discovery. Development is generally the most expensive and procurement-intensive part of a project. It typically involves the drilling and completion of multiple wells and may require the construction of substantial infrastructure, such as treatment facilities, tank batteries, gathering and transportation lines, and marketing facilities. Thus, it is typically in this development phase that the lion’s share of capital investment must take place. Primary risks include the cost and availability of, and delays in obtaining, materials, together with increased cycle times between initial capital expenditures and first commercial production.

The development phase terminates when all production infrastructure needed for production has been built and installed and all wells necessary for optimal production have been drilled and completed. Once this is complete, the parties generally proceed to extract hydrocarbons from the contract area (the production phase). Work performed during this phase is generally concerned with optimizing the production and gathering, marketing, and selling hydrocarbons from the contract area. Initially, operations during this phase are concerned primarily with keeping equipment running and production flowing. However, as the reservoir is depleted and its pressure drops, the parties may eventually consider reworking wells, installing artificial lift equipment, injecting gas to maintain or increase pressure, and even conducting enhanced recovery operations.18 Risks once a project has been brought online include fluctuations in commodity prices and breakdown of facilities and equipment; however, these (and the accompanying costs to mitigate them) are minimal relative to risks through completion of the development phase and are more relevant to the value of the asset than its viability.19

B. Risk Allocation in Conventional Projects

Conventional projects are thus typically characterized by discrete lifecycle stages, with a definite transition and distinct reduction in risk at the conclusion of each stage. In the context of a conventional project, the first few wells typically carry the most geological risk and may effectively

16. Id. §§ 9.14, 9.15. 17. Cody, supra note 7. 18. DUVAL ET AL., supra note 15, § 9.17. 19. Cody, supra note 7.

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prove or disprove a particular project or area (at least as to a given formation). In contracts, these risks are typically allocated to the parties as a whole. Exploratory activities, such as drilling an initial well on a project, are generally either contractually mandatory or carry such a high non-consent premium (frequently relinquishment) that they become effectively so. This is generally true regardless of the type of agreement. For example, in an obligation farmout agreement, failure to drill a well results in breach of contract and loss of acreage.20 Similarly, the commonly encountered AAPL form 610-1989 joint operating agreement makes mandatory the “Initial Well” on the contract area covered by the joint operating agreement.21 Were it otherwise, taking exploration risk would be a losing proposition when compared to waiting to make an investment decision after exploration risks have been minimized or eliminated.

However, once an area has been explored and any discovery appraised to determine if it can be produced economically, these risks drop considerably. The valuation of a conventional project is certainly affected by uncertainties in volumes, commodity prices, and costs during later phases, but, as discussed below, generally not to the same extent as even a successful unconventional project.22 Consequently, conflicts between parties regarding continued capital outlays can be offset by greater freedom of action for each individual party. If a company does not wish to participate in an operation, it need not do so, and the effect on the remaining parties is minimal relative to the effect in an unconventional project. This is typically reflected in governing agreements. Risks of any particular operation can be entirely allocated to one party or the other, often on a well-by-well or operation-by-operation basis. In the context of a joint operating agreement, participation is typically determined on a

20. See, e.g., John S. Lowe, Analyzing Oil and Gas Farmout Agreements, 41 SW. L.J. 759,

809–11, 812–14 (citing Martin v. Darcy, 357 S.W.2d 457, 459–60 (Tex. Civ. App.—San Antonio 1962, writ ref’d n.r.e.), as an example of the measure of damages for failure to drill an exploration well under an “obligation” farmout). This, and not what Professor Lowe terms an “option” farmout, is likely the most common farmout variety, as “the most common motivation for a farmor to farm out is to preserve a lease . . . .” Id. at 793. However, even in a farmout that does not contractually require operations, the result of a failure to drill is typically forfeiture of acreage and/or forfeiture of the right to earn.

21. See DERMAN, supra note 5, at 45. Derman notes that, in the model form AAPL 610-1989 Joint Operating Agreement, the drilling of the “Initial Well” is ostensibly mandatory, both under the JOA and frequently under granting instruments and/or farmouts, though some courts have limited the obligation of an operator to actually commence operations in a timely fashion. Id.; see, e.g., Argos Res., Inc. v. May Petrol. Inc., 693 S.W.2d 663, 665 (Tex. App.—Dallas 1985, writ ref’d n.r.e.) (holding that time was not of the essence in an operating agreement for the drilling of a well when an agreement was not part of a lease arrangement). Equivalents exist in most forms of the joint operating agreement, including Rocky Mountain Mineral Law Foundation Form 2 (§ 9.1, et seq.), Rocky Mountain Mineral Law Foundation Form 3 (§ 8.1, et seq.), Rocky Mountain Mineral Law Foundation Form 1 (§ 12.1, et seq.), AAPL Form 710 (§ 10.1, et seq.), and AAPL Form 810 (§ 10.1, et seq.).

22. Cody, supra note 7.

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well-by-well basis. Failure of a party to participate in one well would not preclude the same party from participating in the next.23 In the context of a farmout, failing to conduct or participate in operations (subsequent to any obligation work) generally results only in a failure to earn acreage.24 The farmee generally keeps acreage on which it has drilled and completed producing wells.25 Infrastructure and midstream assets, if they are required to be built by the jointly-developing parties at all, are generally handled with separate agreements.26 Because each well in a successful conventional project is generally more productive over a longer period of time, less infrastructure (and thus infrastructure expenditure) is typically needed.

III. HOW ARE UNCONVENTIONALS DIFFERENT?

Unconventional resources, by contrast, are characterized by, among other things, low porosity and permeability, requiring horizontal drilling and hydraulic fracturing. Each well has a generally lower estimated ultimate recovery per successful well over a shorter period of time (despite high initial production rates), and thus a greater number of required wells and accompanying infrastructure.27 This results in a higher breakeven factor for most shale plays and thus heightened sensitivity to costs and prices.28 In addition, shale plays have turned out to be somewhat riskier from an exploration perspective than many have previously considered. Even where a play is conceptually viable, it is generally not geologically homogeneous, increasing the risk that a particular area, or even wells within an area, may not be viable. Finally, the developmental framework and discrete beginning and end of

23. See AAPL FORM 610, supra note 14, art. VI.B.2(b) (“[E]ach Non-Consenting Party shall be deemed to have relinquished to the Consenting Parties . . . all of such Non-Consenting Party’s interest in the well and share of production therefrom . . . .”) (emphasis added). Note, however, that, in some circumstances, subsequent operations in the same formation may be prohibited unless state law spacing and density rules permit them.

24. Lowe, supra note 20, at 795. 25. Id. 26. See Arthur J. Wright & Craig A. Haynes, Building Infrastructure—Gathering Systems

and Central Facilities, OIL AND GAS AGREEMENTS: THE PRODUCTION AND MARKETING PHASE, 4-1 (ROCKY MTN. MIN. L. FOUND. 2005) (noting that modifying a joint operating agreement to handle gathering lines and central infrastructure is not an optimal approach compared to ownership of these facilities in a separate entity, in part because “[t]he JOA is not designed to construct and operate pipelines—much less . . . account for non-consent issues and requires 100% consent to proceed in most instances”). Many shale joint ventures, by contrast, utilize separate, often quite complex, agreements related solely to midstream assets.

27. See Renato T. Bertani, Geologic Characterization and Exploration Concepts Applied to Conventional and Resource Base Exploration Plays, OIL & GAS AGREEMENTS: THE EXPLORATION PHASE, 1-1, 1-12 (ROCKY MTN. MIN. L. FOUND. 2010).

28. See Cody, supra note 7 (noting a “break-even” price for a top-performing Bakken Shale project of approximately $50 per barrel versus a “break-even” price for a very large, discovered Gulf of Mexico field of $15 per barrel.). Successful breakevens for deepwater Gulf of Mexico fields often range from $20–$45 per barrel and $50–$70 per barrel for successful breakevens onshore in unconventional tight oil projects.

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different phases of development that characterize conventional projects do not lend themselves to unconventionals. The result has been, in many cases, confusion in the evaluation of potential projects and a struggle to adapt existing rules for conventionals to unconventionals. We suggest that the alternative, four-stage unconventional development lifecycle is a useful tool for (re-)analyzing the risks inherent in a shale project. Using this framework highlights specific exploration, operational, and external risks not necessarily present (or present to the same degree and with the same effect) in a conventional project. Reconsidering these risks in a different context, in turn, makes it more apparent why shale joint ventures to date have typically been structured in the way that they have and suggests a framework for evaluating and papering future projects.

A. Phases of an Unconventional Project

From the perspective of a transactional attorney or commercial negotiator, recognizing the revised lifecycle concept for an unconventional project is a necessary step in understanding the risks involved in an unconventional project as compared to a conventional project. Wood Mackenzie has identified four typical phases in the life of an unconventional project that replace the “exploration-appraisal-development-production” framework of a conventional asset: (i) concept, (ii) pilot, (iii) ramp-up, and (iv) exploitation.29 The primary purpose of this alternative shale worldview is to give operators a new vocabulary to more accurately describe and evaluate a given potential investment compared to its conventional counterpart.30 However, it is also useful in understanding risk allocation between multiple parties within the same project. As with the conventional project framework, different risks are present during each of these phases. Unlike the framework of a conventional project, the line between each phase is not necessarily distinct or predictable, and a project may seem to be in more than one phase at any time.31

1. Concept Phase

During the concept phase of a project, a company attempts to “identify prospective unconventional resource targets that do not have any production history.”32 Implicitly, the greatest risk in this phase is play concept risk—that is, the risk that a play will not yield any commercially

29. Cody, supra note 7. 30. Id. 31. Thus, by way of example, a pilot program as described below can be ongoing during the

“ramp-up” process and can continue into the “exploitation” phase, as the operator continues to learn the geology of the play and optimize well design.


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viable acreage. By way of example, the Mississippian-age, black shale concept is present in different basins along the Ouachita Fold Thrust Belt and has undergone concept testing in five distinct plays: the Black Warrior Basin (Floyd Shale), the Arkoma Basin (Fayetteville and Woodford Shale), the Fort Worth Basin (Barnett Shale), and the Delaware Basin (Barnett/Woodford Shale). This play concept has proven commercially viable in the Fort Worth Basin and the Arkoma Basin. In the Black Warrior Basin and the Delaware Basin, it has not. In the Black Warrior Basin, the Floyd or “Neal” formation is too high in clay content to be effectively stimulated with current hydraulic fracturing techniques. In the Delaware Basin, the Barnett/Woodford formations can be over twice as deep as in the Fort Worth Basin, leading to well costs that are too high to make the play economic.

The most obvious analogy to play concept risk is exploration or dry hole risk in a conventional project. However, this analogy has not been consistently drawn because these two risks are conceptually different. The risk of a dry hole in a conventional, accumulation model reservoir can be quite high. The risk of a dry hole in a shale play is practically non-existent. This has led to a misperception that there is no exploration or, more generally, finding risk for shale. There is. The geological reasons behind a dry hole and a failed shale concept are different, but the result is the same—no project.

2. Pilot Phase

To de-risk a concept, an operator must conduct a pilot program. During the pilot phase of a project, the parties will drill multiple wells and experiment with technologies in an effort to understand the geology of a play well enough to be able to deliver repeatable and economic results.33 Play concept risk is, of course, present in this phase; however, two additional risks begin to impact a play as the pilot program is conducted: acreage prospectivity risk and well variability risk. The unfortunate manufacturing analogy that has attached itself to shale plays in general is founded, in part, on the idea that all shale acreage is created equal. It is not.

Even within a proven play concept, there is substantial risk that unproven acreage will have geology that differs substantially enough from proven areas that production from wells is insufficient to economically recover well costs (let alone be a better allocation of capital when compared to a conventional project, even if well costs can be recovered). This typically occurs due to well productivity or composition of production (that is, whether the formation is more productive of

33. Id.

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liquids or gas). These geological variations produce distinct sub-plays within the overall play that have different production characteristics. By way of example, variations in thermal maturity and thickness of the Marcellus Shale causes it to be subdivided into twelve sub-plays, with just two core areas that are highly productive.34 Value is concentrated in these core areas, but they represent only a small portion of the play extent. The Marcellus has had a smaller percentage of acreage that is economically viable (20%) than conventional prospects in a major Gulf of Mexico deepwater play (30%).35

Even successful shale play pilot programs (and exploitation programs) have typically had a large variation in early well performance. That is, during the pilot program, and even an exploitation program, early well performance (and lack of performance) tends to put a wide range around expected ultimate overall well performance. Early wells can suggest stronger or weaker performance than may ultimately be achieved. Eventually, wells will begin to demonstrate a statistically significant central tendency within a range of variability that suggests that future expected well performance will be at an economic (or non-economic) level, thus confirming the prospectivity or non-prospectivity of the acreage. But, this generally takes time and a material number of wells—frequently more than are planned.

Acreage prospectivity risk and well variability risk, working together symbiotically, are most analogous to appraisal risk in a conventional project—that is, a hydrocarbon-bearing reservoir is present, but it is not commercially developable. However, acreage prospectivity and well variability risks extend much further into the life of an unconventional project and at a greater level than any exploration risk normally associated with a conventional prospect. De-risking, from a geological perspective, is a more gradual and incremental process in an unconventional project and can continue into the final phases of the project’s lifecycle.

3. Ramp-Up

After the conduct of a successful pilot program, the operator frequently begins a ramp-up phase in which (if necessary) financing is

34. See Marcellus Expected to Dominate U.S. Gas Supply, WOOD MACKENZIE (Nov. 6, 2013), http://www.woodmacresearch.com/cgi-bin/wmprod/portal/corp/corpPressDetail.jsp?oid=1 1670428.

35. Estimates of commercial success rates derive from Wood Mackenzie’s “Key Play Service,” which analyzes well performance for shale plays and Wood Mackenzie’s “Upstream Service,” which maintains a database of exploration wells and discovered fields. Based on these data sources, the 20% figure used for the Marcellus Shale equates to the percentage of acreage located within either the Bradford/Susquehanna core areas or the Southwest rich-gas extent of the play. For the Deepwater Gulf of Mexico, there are at least 87 wells that have targeted the Miocene play, from which at least 26 discovered fields proved commercially viable.

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secured, rigs and other materials are procured, and midstream and other infrastructure is built out.36 This phase typically heralds the beginning of a significant increase in capital expenditures compared to the pilot. Operators have not typically thought of final investment decisions in terms of shale, since, among other things, the line between the pilot and ramp-up phases may not be especially distinct. However, a decision to enter the ramp-up stage of a shale project represents a shift in emphasis for the drilling program, from understanding and delineating the commerciality of acreage to achieving an efficient scale of operations and building production quickly, such that operating cash flows can cover ongoing capital requirements.

During this phase, operational risks come into play. These include problems that (i) cause higher than expected well costs, typically due to operational inefficiencies, unplanned non-productive time, and difficulty procuring the rigs, equipment, and services necessary for development at an acceptable cost, or at all (cost risk); (ii) cause a lower than anticipated rate of completing new producing wells due to supply chain limitations, permitting, operational inefficiencies, and intentionally slowing down project plans to avoid extended cycle times between capital expenditure on a well and its initial production (delay risk); and (iii) extend the period between capital expenditure on a well and its initial production, typically due to logistical issues, backlogs of well completions, or insufficient infrastructure capacity (cycle-time risk).37 As noted, each of these risks is present to some extent in a conventional project; however, in an unconventional project, they persist, by and large, until the end of the project.

4. Exploitation Phase

After sufficient resources are mustered during the ramp-up phase, an unconventional project moves into the exploitation phase. This terminology will likely be familiar to practitioners experienced with international granting instruments and joint operating agreements. However, in the context of a shale play, it is more analogous to a combination of development and production and represents a continuous process that frequently extends until the end of the project. During this stage, development drilling continues in order to maintain production until all viable well locations are exhausted.38 Risks during this stage are an amalgam, to varying degrees, of the risks present during each of the previous phases, other than play concept risk, which presumably has been

36. Cody, supra note 7. 37. Id. 38. Id.

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eliminated prior to a decision to spend the money fully developing the project. Supply chain difficulties (if a procurement decision was not taken to lock in supply and price during ramp-up) can significantly increase costs and decrease margin. Likewise, most operators continue to carry exploration risk during this period, as reflected by estimates of a developable percentage of its acreage.

B. Unconventional Risk Profile

Unconventional project risks can be broadly placed into three categories: (i) exploration, (ii) operational, and (iii) external.

1. Exploration Risks

Exploration risks include play concept risk, acreage prospectivity risk, and well variability risk. Shale plays are frequently, and erroneously, thought to not involve these risks. This assumption is presumably based (at least in part) on the low chances of a true dry hole. Adapting this concept from the conventional project paradigm may cause a company to overvalue the de-risking properties of initial work. The initial39 well in a conventional project may have a significant de-risking effect, but the first well, or even the first few wells, in a pilot program do not de-risk an unconventional project to nearly the same degree. In fact, these factors are likely to be present throughout the life, or most of the life, of an unconventional project.

A pilot program should, if properly conducted, prove or disprove the viability of a play concept. However, while one or two exploration wells and two or three appraisal wells will generally prove or disprove a conventional project, an unconventional pilot program can involve dozens of wells. These pilot program wells typically involve a greater amount of “science” and experimentation as the operator learns the geology of the play, but do not involve cost efficiencies due to economies of scale. Thus, they are generally much more expensive than later wells drilled as part of the exploitation phase.40 As with conventional exploration and appraisal wells, pilot program wells are linked to, and have a significant impact on, later exploitation wells.

Even if a play concept is proven, it may not generally be clear whether the particular acreage being developed is, as a whole, economic. Well performance variability may add significant uncertainty to the planning of pilot programs, as it will not be clear how long the pilot will last. Even if

39. The word “initial” was chosen purposefully here as a reference to the “initial well”

exploration concept in most U.S. joint operating agreements. 40. Pilot well costs depend on the play, with a typical range of five million dollars to fifteen

million dollars per well.

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the play and parts of the specific acreage under consideration are proven, and well performance has stabilized to some degree, exploration risks will likely continue into the later stages of a project, making ramp-up and exploitation difficult and expensive:

During these later stages, the ‘percent developable’ acreage and well performance deviations represent the major remaining subsurface risk that unconventionals face that conventional fields do not. Percent developable is a direct determinant of the number of well locations (hence remaining value) of the undeveloped portion of the acreage. These later-stage risks can be quite substantial. For example, a leading US operator of shale plays has applied factors of 30% to 75% developable to its established positions.41

Failure to account for these exploration risks can make a project appear to be economic when it ultimately is not. By way of example, an operator may estimate that acreage capture costs and the conduct of a pilot will cost approximately two hundred fifty million dollars. Based on expected well performance and costs and a projected well schedule, this might yield one and one half billion dollars in net present value. Without considering exploration risk, this project is clearly economic. However, on a risked basis, project economics are likely to be much more sensitive to the amount of capital deployed in the early risk stages. Well variability risk may cause the pilot stage to extend past the original plan, and the amount of risk capital to be increased (say, to four hundred million dollars instead of two hundred fifty million dollars). At the end of the pilot phase, this project may still be strongly positive. However, as noted above, there is no guarantee that all or any of the acreage on which the pilot program was conducted will prove commercially viable. To evaluate the merits of conducting a pilot project, companies should consider applying a risk factor to the value of the expected ramp-up and exploitation phases. Based on the Marcellus example above, one might apply a twenty percent risk factor at an early stage, such that the risked project value may only be three hundred million dollars. In this case, exploration risk will have effectively resulted in participants spending more money capturing and proving up acreage than the project is ultimately worth.

The foregoing example uses the twenty percent expected chance of success number for illustrative purposes only. There is no one right number to use, as the ultimate chance of success will be driven by widely different subsurface characteristics. However, up-front technical work on understanding the geology of a play can focus companies on areas with better subsurface characteristics, which will presumably be more likely to


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prove commercial. As new information comes in from the pilot program, the assessment of risk must be continuously updated. Over time, this twenty percent chance of success should rise significantly.

Careful planning and execution of each well should reduce this geological risk gradually over time (as opposed to suddenly in the conventional context), but this does not happen quickly. As noted below, this should be taken into account in both the evaluation of, and the contracts governing, an unconventional project.

2. Operational Risks

Operational risks include (i) cost risk (the risk of costs to procure services, rigs, and other equipment being higher than anticipated or budgeted), (ii) delay risk (the risk that rigs, services, and other equipment may not be available at all), and (iii) cycle time risk (the risk that a longer than expected period of time will elapse between capital expenditure on any particular well and first production from that well). These risks should be familiar to any student of the exploration and production industry in the United States (and elsewhere); that is, anybody who has been in the industry for more than a few years, or anybody who has ever read H.G. Bissinger’s Friday Night Lights.42 When in demand, rigs, services, and other equipment cost more and are less readily available. As of January 7, 2000, the Baker Hughes rotary rig count for North America was 786.43 As of May 16, 2014, it was 1861.44 The surge of unconventional development in the United States has resulted in higher costs and less availability.45 However, operational risks have a disproportionate impact on unconventional projects.

Project economics during the pilot, ramp-up, and exploitation phases (post-discovery) are challenged by low net margins per barrel for unconventional projects. Unconventionals began as gas plays because gas is easier to extract from tight formations. Even with the move to liquids,

42. H.G. BISSINGER, FRIDAY NIGHT LIGHTS: A TOWN, A TEAM, AND A DREAM 227

(HarperPerennial 1991): There may not have been a more awesome graveyard in the country than the old MGF lot off Highway 80—thirty acres filled with equipment that had cost $200 million and in the fall of 1988 might have fetched $10 million—with three hundred thousand feet of new and used drill pipe up on metal stilts like pixie sticks, four hundred drill collars, and the guts of nineteen rigs.

43. BAKER HUGHES, NORTH AMERICA ROTARY RIG COUNTS THROUGH 2013 (2013), available at http://phx.corporate-ir.net/External.File?item=UGFyZW50SUQ9NTI4OTY4fENoa WxkSUQ9MjE2NDc2fFR5cGU9MQ==&t=1.

44. BAKER HUGHES INC., NORTH AMERICA ROTARY RIG COUNT (2014), available at http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-reportsother.

45. See, e.g., Chris Newton, Preston Cody, & Rick Carry, Sourcing Critical Oilfield Services for Shale Plays in a Tightening Supply Market, 231 WORLD OIL, Aug. 2010, available at http://www.worldoil.com/Sourcing-critical-oilfield-services-for-shale-plays-in-a-tightening-supply-market.html.

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the most successful plays generally rely on gas drive mechanisms. Unconventionals tend to have higher gas-to-oil ratios and natural gas liquid content with their production stream. In current market conditions, this generally results in a lower per-barrel of oil equivalent revenue realization. Costs related to unconventional projects tend to be higher as well: the costs for rigs and crews (including frac crews), equipment, services, and operating generally tend to be much higher than in a conventional project, due (among other things) to high demand and scarcity nationally, and frequently, in the geographical location of the play itself. These costs are generally required throughout a project to even maintain production. As a play is de-risked, acquisition costs such as lease bonuses and royalties generally increase significantly. The result is low net margins per barrel relative to, for example, a successful deepwater Gulf of Mexico project, that make the value of an unconventional project highly sensitive to costs. Delays in unconventional projects are common as well. These, coupled with relatively long drilling programs, cause the time value of money to further erode value through longer cycle times for capital (as, for example, wells wait for the availability of hydraulic fracturing equipment and crews).

3. External Risks

External risks, such as market, political, and regulatory risk, affect unconventional projects throughout their lifecycle. These risks are nothing new to the oil and gas industry; however, their effects on unconventional projects are magnified due, among other things, to the marginal nature of these projects and their perceived environmental effects. By way of example, typical unconventional tight oil projects with breakevens in the range of $50–$70 per barrel are more sensitive to changes in commodity prices than development of deepwater Gulf of Mexico fields with typical breakevens of $20–$40 per barrel. For these projects, a 20% fall in commodity prices may reduce project net present value by up to 50% percent for a deepwater Gulf of Mexico field, but could cause the net present value of an unconventional tight oil project to decrease by 125%, causing it to fall below the breakeven price (into negative territory).46

Likewise, unconventional projects have brought the oil and gas industry back onshore (and in the United States) on a greater scale than ever before, and frequently in urban areas. Fleets of equipment and armies of workers motivate environmentalism, and the media is geared to magnify the impact of almost any incident. The result has been federal, state, and, most recently, local, regulatory action that makes operations

46. Cody, supra note 7. Value sensitivity analysis conducted by Wood Mackenzie.

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more difficult and/or expensive, along with regulatory uncertainty in some areas.47

C. Impact on Joint Development

Each of the risk factors outlined above has created, and exacerbated, conflicts between parties jointly developing a project. The carrying of the operator’s costs that typically accompanies a shale joint venture may incentivize the carried partner to take more exploration risk than is justified by the underlying project economics—for example, by drilling carried wells on highly speculative acreage. In such a case, if the land proves up, the operator captures the upside without putting its own (or putting little of its own) capital at risk. As described above, continuing exploration risks create a strong linkage between each part of a shale project.48 Thus, it makes less sense to allow one party to conduct its own program or elect to not participate in49 the costs of, for example, a late-stage pilot well, when it will reap the benefits of this well by virtue of fact that future wells are more likely to be drilled on good acreage and at a lower cost.

Likewise, operational risks may create or exacerbate differences between parties. An operator might, for example, seek to offset cost risk by committing to the procurement of goods and services in advance. A non-operator—especially one that is carrying the operator—might desire to maintain flexibility instead of paying for future services up front in order to secure their availability. Budgeting for a forward-looking contracts and procurement strategy is likely to be difficult (especially with relatively low project margins) if a party does not know whether its counterparty will participate in any given operation. Similar conflicts can arise regarding attempts to maximize ultimate recoveries versus well profitability (through tradeoffs in well and completion designs, well spacing, restricted flow programs, and the like); the desire to drill multiple wells from pads to increase efficiencies, reduce costs, and minimize surface disturbance versus single wells to hold the maximum

47. Examples include the New York state moratorium on hydraulic fracturing,

Environmental Protection Agency requirements for Barnett shale facilities to reduce emissions under the Clean Air Act, and the Arkansas moratorium on injection wells for disposal of flowback and produced water. During the fourth quarter of 2013, the Parliament of the European Union became one of the latest governmental authorities to follow suit, requiring environmental reports even for exploratory drilling. See Seth McLernon, Euro Fracking Rule Spells Trouble for Shale Development, Law360 (Oct. 16, 2013), http://www.law360.com/articles/ 480484/euro-fracking-rule-spells-trouble-for-shale-development.

48. Supra Section III.B.1. 49. While “sole risk” and “non-consent” are flip sides of the same coin (and are generally

subsumed within the term “non-consent” in the U.S. domestic industry), the difference is relevant here. The ability of a party to propose (and carry out) operations in which it knows its counterparty will elect not to participate (sole risk) is as problematic as allowing a party to elect not to participate in a necessary de-risking operation (non-consent).

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amount of acreage; and/or the desire to drill ahead of any necessary infrastructure versus at such time as capacity is available.

With respect to external risk, non-operating partners are likely to desire material input into operations, not only because they are sharing costs but because they may share the blame for the operator’s perceived sins. This is especially relevant given how controversial hydraulic fracturing has become and the differing health, safety, and environmental standards and organizations that incumbent emerging-play shale operators generally must deal with. Similarly, commodity price risk coupled with high costs and low margins may cause conflicts between partners with different overall asset portfolios. A company with little or no cash flows outside of shale projects or late-stage, cash producing conventional projects may be more inclined to focus capital on an unconventional project. Conversely, a party that requires near-term capital outlay for a conventional project or is struggling with financing might desire the flexibility to divert capital to a more attractive play.

The typical U.S. scheme of joint development emphasizes autonomy of action.50 Except for relatively minimal initial operations, a party may frequently opt out on an operation-by-operation basis. In a conventional world, this might be an appropriate method of allocating risk. However, unconventionals are risky, and it is this continuing risk that results in shale development operations being more interconnected than may be currently realized. For this reason, persons working with documents governing unconventional joint development should consider taking account of the project as a whole and focus on continuity of the participants’ commitment to a project. Unconventional joint venture agreements have, to some extent, attempted to address this. However, due to the nature of the risks involved in an unconventional project, it is useful to revisit the conflicts that may have arisen between parties in existing agreements and consider how these might have been resolved, and unconventional risks more appropriately allocated, through use of a modified contractual framework.

IV. CONTRACTUAL ALLOCATION OF UNCONVENTIONAL RISK

The traditional tools of joint development in the oil and gas industry have included some form of operating agreement (joint, unit, or otherwise) and the farmout agreement (and derivations thereof),

50. See generally Andrew B. Derman & James Barnes, Autonomy Versus Alliance: An

Examination of the Management and Control Provisions of Joint Operating Agreements, 42 ROCKY MTN. MIN. L. INST. 4-1 (1996) (noting the level of autonomy commonly found in U.S. joint venture control structures and arguing for a more collaborative approach to joint development).

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frequently working in concert.51 In terms of joint operations, the hallmark of these agreements, and indeed, the U.S. onshore domestic exploration and production business generally, is independence. A party has the right to pursue its own interests with respect to any particular operation, with minimal interference, or even input, from counterparties.52 A party may generally participate, or not participate, in a particular operation following minimal initial required work, such as an initial well in the context of a joint operating agreement.53 Conversely, a party may generally propose any operation and carry it out regardless of the wishes of its counterparties, so long as it has full subscription of the costs.54 This structure has served for conventional projects with relatively low cost and moderate technical complexity, though it has not been without its critics.55

With the advent of the shale revolution, the industry has realized, to some extent, that these traditional agreement structures do not fit the requirements of an unconventional resource play.56 From a commercial perspective, the capital-intensive nature of shale projects makes them prime candidates for joint development. However, simple farmouts, or divestitures with a series of smaller joint operating agreements, have tended to not be satisfactory. The early companies that were (or became) proficient with shale projects were eager to keep the upside from their work, but were in need of capital for ramp-up and exploitation stages of projects. Thus, a farmout was a logical structure to adopt, albeit with substantial changes. These changes typically include (substantially) more elaborate control procedures, (much) larger carried interests, longer and more complex mandatory work, more control by, and the operatorship of, the carried party, and a holistic view of a play as a whole (and not smaller individual areas). Basic contractual structures typically included an acquisition agreement, a joint development agreement, an area of mutual interest agreement, an agreement covering midstream assets and facilities, and innumerable joint operating agreements governing smaller

51. What follows is a generalization of control structures in agreements governing

conventional joint operations onshore in the United States. We recognize that not all structures conform to this description—notably, even within the world of formalized structures, the AAPL’s coalbed methane addenda to its onshore Form 610, and, to a limited extent, some of the Rocky Mountain Mineral Law Foundation unit operating agreement forms; however, in terms of absolute number, these are the exception and not the rule.

52. See generally Derman & Barnes, supra note 50. 53. E.g., AAPL FORM 610, supra note 14, art. VI.B. 54. See, e.g., id. at art. VI.B.2.(a). 55. See generally, Derman & Barnes, supra note 50. 56. See, e.g., DERMAN, supra note 5, at 45; Larsen, supra note 5; Matthews & Kulander,

supra note 5; Christiansen & Brooks, supra note 5; Michael J. Wozniak, Horizontal Drilling: Why it’s Much Better to “Lay Down” than to “Stand Up” and What is an “18° Azimuth” Anyway?, 57 ROCKY MT. MIN. L. INST. 11-1, 11-8 (2011).

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groups of wells.57 This contractual structure has been, in many respects, an innovative

and efficient solution to the problems posed by unconventionals. However, even recent shale joint venture transactions have rarely, if ever, expressly identified or dealt with the phase of development of a particular play or the relevant risks going forward. Not surprisingly, there has been some dissatisfaction with certain aspects of these deals after the fact by their participants. Conflicts between parties have resulted from how these joint venture structures handle the risks of unconventional joint operations—specifically those described in more detail in Section II.C.3. In addition, though shale is “going mainstream” through revisions to traditional documents such as joint operating agreements,58 there has been no move to adopt similar frameworks as an industry. This failure has the potential to lead to further conflicts and decreased efficiency, as parties turn away from standardized forms.59

The risks inherent in unconventional projects necessarily interconnect a given set of operations, even if the wells are not linked by pressure communication. A successful late-stage exploitation well carries in it the lessons learned (and costs) of marginal, or even uneconomic, pilot program wells. A stronger relationship between individual operations suggests that parties should remain more closely aligned through the life of the project. Thus, we suggest that requiring closer alliance between parties in both large joint venture structures and other smaller versions of joint development governance documents might more appropriately deal with risks and conflicts that arise from them in the context of an unconventional operation. The following paragraphs discuss how risks are currently handled (if they are handled at all) and suggest potential solutions for more appropriately allocating these risks in the shale context.

A. Exploration: Concept Risk

Exploration risk in a conventional project is generally handled by contractually requiring that a party participate in exploratory operations,

57. See, e.g., James McAnelly & David Sweeney, Unconventional Resource Plays: Legal

Lessons Learned in Buying, Selling & Joint Venturing Shale Assets, U. OF TEX. ENERGY L. SYMP., Feb. 2011.

58. See generally Weems & Tellegen, supra note 5 (discussing the new AAPL 610H-1989 joint operating agreement). The Canadian Association of Petroleum Landmen was one of the first organizations to propose industry standard terms specific to unconventional operations in Section 8 of its 2007 model form. In addition, the AIPN committee that is creating an Unconventional Resources Operating Agreement is nearing completion of its project. In this respect, it is worth noting that governing documents for many U.S. shale joint ventures seem to borrow concepts from AIPN model forms quite heavily.

59. See Weems & Tellegen, supra note 5, at 3 (“The proliferation of these custom forms defeats a key function of the Model Form, which is to provide certainty and uniformity.”).

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and/or causing it to relinquish its interests in the project if it does not.60 Once exploration operations have been completed, however, a party gains significant operational freedom. Thus, in a U.S. onshore joint operating agreement, if a party fails to participate in the initial well in a contract area, it generally will have breached the joint operating agreement, leading (potentially) to liability for damages.61 Once this well has been drilled, however, each party is, for the most part, free to propose or not propose or to participate in or not participate in subsequent operations.

This allocation of exploratory and appraisal dry hole risk to all of the parties, with relative freedom afterwards, makes some sense when the geological de-risking process is largely complete after the first few wells. However, as noted above, a few wells do not (necessarily) a successful play concept make.62 A well-run pilot program may encompass dozens of wells—both vertical and horizontal—drilled in several potential sub-areas within a play, as well as test production. Allowing concept risk to be placed on one consenting party after an initial well or two may result in under-investment in play de-risking and science, as even parties that have an interest in developing a play may be disincentivized to spend money overcoming initial well variability and determining whether a play will be commercially viable.

Conversely, joint development agreements specifically tailored to shale have sometimes resulted in over-expenditures on exploration. These transactions have typically (although not always) involved payment of the operator’s costs by a non-operating party seeking entry into a specific play, or U.S. shale generally.63 This carry is generally subject to only minimal restrictions, such as time and total dollar amount. An initial work program and budget is usually agreed to as part of the joint development agreement governing the transaction; however, this is frequently quite general, prescribing, for example, minimum and maximum footage or number of wells, or a general area for the acquisition of new leases. The result is that the carried partner will be incentivized to take on more exploration risk than may be justified. A party whose capital is not at risk may, for example, acquire leases in non-core areas and drill wells on this acreage in an effort to capture value using the non-carried partner’s risk capital.64 While the deployment of

60. See, e.g., AAPL FORM 610, supra note 14, at VI.A; Lowe, supra note 20, at 793 (failure to

earn in the context of a farmout). 61. DERMAN, supra note 5, at 3. 62. Supra Section III.B.1. 63. See, e.g., Exco Res., Inc., Current Report (Form 8-K) (Aug. 11, 2009). 64. In addition, the sharing of information may be a problem. One of the most common

complaints of non-carried partners is that they have no idea whether their funds are being well spent. They receive a check and a bill in the mail each month and any request for an explanation

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risk capital may not be economically justified by the risk-adjusted expected value of the land, if it proves successful, the carried party does not suffer the loss of risk capital. This creates a free option for them to attempt to conduct pilot programs on land. On the other hand, though less common, there have been instances in which a carried party does not spend the entire carried amount and thus under-explores an area, potentially because it has written off the project too soon in the pilot. Other than the loss of the carry, this frequently carries no adverse consequence for the carried party.

A major goal of a pilot program should be to eliminate, to the extent practicable, play concept risk, and the contractual allocation of risk between parties should support this. Adoption of the traditional, conventional, autonomy-based risk allocation method will likely result in under-exploration. On the other hand, shale-specific joint ventures have tended to encourage over-exploration and expenditures in highly speculative areas. Arguably, the goal of an agreement governing joint operations during the concept and pilot phases of a shale project should be to keep the parties aligned. Just as non-consent is not permitted for initial wells in a joint operating agreement, so should it be prohibited (or, if not prohibited, disincentivized) during the pendency of an entire pilot program. To allow a party to fail to participate during the period in which well variability may create uncertainty, but then participate in future wells, is akin to allowing a party in a conventional project to view the results of an exploration well (drilled at other parties’ cost) before deciding whether to participate in future wells on a non-promoted basis. However, this methodology requires parties to carefully define where the pilot program will begin and end, what operations (and additional lands) it will encompass, and how they will adjust the program to changing circumstances—especially when only one party has capital at risk.

Thus, the details of pilot programs should be agreed to “up front.” In the context of a shale joint development agreement, this would likely take the form of a more detailed required work program. In a document governing a smaller venture, such as a joint operating agreement, this could take the form of the replacement of the initial well concept with a pilot program.65 If a non-participation right is desirable during the pilot program, the parties could add an acreage relinquishment provision. However, relinquishment of a single operating agreement contract area but not a play as a whole could result in the non-participating party still is met with a flood of paper (or recourse to any relevant accounting procedure audit provisions).

65. For example, in the AAPL 610-1989 form of operating agreement, Article VI.A could be revised to reference multiple wells on multiple tracts with a single formation with conforming changes to the definition of “Initial Well” and throughout the document. A section could then be added forbidding “subsequent operations” under Article VI.B unless and until the pilot program is completed.

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obtaining some of the benefit of the pilot program through its participation in other contract areas. In this case, breach of contract damages might be a better approach. Conversely, the parties should consider defining a procedure whereby modifications to the initial plan can be discussed and agreed upon, as the uncertain nature of unconventional pilots requires flexibility in response to new and evolving information.

This first approach would likely cause controversy in that it would (i) increase the complexity of agreements and the time required to negotiate them, causing delay, and (ii) deprive the operator of the flexibility that it needs to make adjustments to the pilot program.66 Both of these issues could presumably increase project costs. In the latter case, reduced flexibility could mean that the operator will have to obtain consent from its partners to deviate from the agreed-to pilot program, introducing uncertainty and complexity into the decision-making process. These are fair points. However, the relevant question is not whether these changes potentially increase costs. Rather, it is how much they increase costs relative to the risks of having a pilot program that is unsuccessful, not due to geology, but because there is an incentive on the part of one party to either over-explore or under-explore the contract area. In any event, these issues could potentially be mitigated, at least to some extent, by keeping non-operators and/or non-carried parties “in the loop” about operational decisions, either through formal committees, informal information sharing arrangements, or other arrangements, such as secondments.67

B. Exploration: Acreage Prospectivity Risk and Well Variability

Acreage prospectivity and well variability risk (or their nearest equivalents) in a conventional project are typically handled by allowing parties to determine their participation after an initial work program on an operation-by-operation basis. Failure to participate in any one well does not necessarily determine participation in subsequent wells or affect ownership of previous wells in which a party did participate.68 Thus, a party that elected not to participate in the drilling of a well would typically not lose its rights to previous wells or subsequent wells (or even the well at issue, after the participating parties recover their costs plus a premium).69 As illustrated in Section III.B.1, above, acreage prospectivity

66. See, e.g., DERMAN, supra note 5, at 59. 67. Secondments have been relatively common in unconventional projects, though this is

usually attributed to a desire by the non-operator to “learn” the shale business from its more experienced partner.

68. See, e.g., AAPL FORM 610, supra note 14, at VI.B.1–2. 69. But see id. art. VI.B.7 (placing limits on the ability of the parties to drill additional wells

into a formation already producing from a well in the contract area, unless the proposed new

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is determined, and well variability risk decreases, only gradually over time and through the execution of operations. Thus, allowing a party to elect not to participate in early (even if non-pilot) wells and participate in later wells would allow that party to benefit from the experience gained and science conducted from and on the early wells, without paying its share of costs and taking the geological risk of those wells. This would disincentivize parties to drill wells necessary to prove or disprove acreage and eliminate well variability.

Shale joint venture agreements have typically addressed this issue by requiring participation (and even a carry) long after a pilot program has finished and/or mandating a work program and budget and an operating committee. While this may solve the problem posed by the traditional conventional methodology, it results in the same conflicts between carried and non-carried parties described in Section IV.A, above. That is, the carried party is incentivized to either drag out the pilot program, carry out too much exploration, or conduct the wrong type of exploration. Four possible types of contractual solutions are the creation of sub-areas, a non-consent matrix, prohibiting non-consent, and challenge-of-operator provisions.

1. Sub-Areas

A balance of interests is required to align the interests of the parties in proving up acreage and to eliminate well variability without doing so at the sole cost of one party or encouraging the acquisition and drilling of highly speculative acreage. Combined with a detailed and well-conceived pilot program, one potential solution to this issue would be the creation of sub-areas within the larger project area. Each sub-area would be subject to a mini-pilot project in which participation would be mandatory (for example, in a joint venture, where the carry of one party’s costs would constitute part of the purchase price) or failure to participate would result in relinquishment of rights to the sub-area.

This is not without precedent in both previous shale joint ventures and in conventional exploration and production contracts.70 Where this has occurred in large-scale shale joint ventures, it has typically been accomplished among distinct plays, either through separate suites of contracts that apply independently once finalized but were nevertheless part of the same overall transaction, or through the ability of parties within a single joint development agreement to reallocate capital

well “conforms to the then-existing well spacing pattern” for the relevant zone). In addition, some “drill to earn” farmouts provide that a failure to participate in ongoing drilling operations results in a forfeiture of the right to earn acreage going forward. See Lowe, supra note 20, at 795.

70. Indeed, at the time of this Article, this concept is under consideration by the committee that is drafting the AIPN Unconventional Resources Operating Agreement.

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expenditures from one area to another. Sub-units have been used as well with federal exploratory units and in coalbed methane joint venture documents. Both the U.S. federal unit agreement form71 and its accompanying joint operating agreement, typically based on the Rocky Mountain Mineral Law Foundation Form 1 or 2, allow a much larger area to be subdivided into semi-independent “drilling blocks” and “participating areas” that function as independent units. A party that does not participate in the initial well in such a sub-unit is effectively out of the sub-unit, but not the remainder of the larger unit.72 Similarly, the model coalbed methane revisions to the AAPL Form 610-1989 (and 1982) joint operating agreement contains an option to group wells and infrastructure into “pods.”73 Failure to participate in the development of a pod is sometimes deemed to be an election not to participate in subsequent operations with respect to the pod. For example, a party that does not participate in a well proposed as part of a pod relinquishes its interest in production from the pod as a whole and is not entitled to participate in the drilling of subsequent wells in the pod (at least until the non-participating party’s rights revert).74

One of the challenges to this approach would likely be the difficulty in determining, before operations begin, where one sub-area begins and another ends. As with, for example, a unit in the Gulf of Mexico or outside of the United States, some level of educated guess would likely be required absent subsurface data. This is a valid criticism. However, it would presumably be possible to draft around this issue, potentially by delaying the creation of sub-areas until the end of the initial pilot program (or a predetermined point in time that approximates the end of the initial pilot program), when the parties know more about play geology.

2. Step-Down Premium Matrix75

Another potential solution to acreage prospectivity and well variability

71. See 43 C.F.R. 3186.1 (2013) (statutory model form of federal units). 72. E.g. ROCKY MTN. MIN. L. FOUND., FORM 2 § 6.1 (1995). 73. Coalbed methane operations are generally more interdependent than most onshore

operations. Groupings of wells (pods) and infrastructure—specifically for dewatering (reducing hydrostatic pressure within the coal seam so that gas will no longer be bonded to the coal matrix), disposing of this produced water, and compression of what is typically very low pressure gas—are required for a development to “work.” Thus, there is a need to “package” certain operations with respect to coalbed methane projects. See Frederick M. MacDonald, The AAPL Form 610 JOA Coalbed Methane Checklist, OIL AND GAS AGREEMENTS: JOINT OPERATIONS, 11-1, 11-2 (ROCKY MTN. MIN. L. FOUND. 2007) (“The defining difference between conventional and CBM development is therefore the required infrastructure.”). The same thing might be said of shale.

74. AAPL FORM 610-1989 COALBED METHANE CHECKLIST § VI.B.2(b)1 (Option 2). 75. Many thanks to Ilya F. Donsky, Manager, Drilling Operations, of LUKOIL Overseas

Offshore Projects Inc. for bringing this concept to the authors’ attention.

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risk would be to create a non-consent matrix that applies a reducing back-in premium the further along in the drilling program the non-consent occurs. Thus, for example, failure to participate during the pilot might result in relinquishment, while failure to participate in the sixtieth well in a program might only result in a two hundred percent cost-recovery premium. The viability of the concept would depend entirely on the cost recovery premiums chosen, which is difficult to discuss (other than conceptually) in a legal paper. As with the sub-area solution, however, one potential criticism of this approach is that it arbitrarily draws a line after which penalties become less severe before any real subsurface information is gathered.

3. No Non-Consent Permitted

Some would argue that a non-consent election should not be permitted at all in the context of an unconventional project. Given the interdependence of each well in an unconventional program, this is certainly a viable point of view. In this case, decisions would be made by the parties and would be binding on the group. However, this solution does not really deal with the risk that is (arguably inappropriately) allocated to the carrying partner in a joint venture and in any event would not be likely to be generally accepted by the exploration and production industry.

4. Under-development and the CAPL Challenge of Operator Procedure

As a final word regarding exploration risks, non-operating parties should consider an operator that does not conduct enough exploration operations. While a non-operator (especially one that is carrying the operator) would obviously be concerned about over-spending, under-spending can also result in a project never becoming commercial. In addition, failure to drill acreage in order to maintain it will ultimately result in its loss. In a typical joint operating agreement, the non-operating party is likely to be protected against this by its right to propose operations.76 This option may not be available to parties to a farmout or a joint venture. In this case, one potential solution is found in the “challenge of operator” provisions of the Canadian Association of Petroleum Landmen (CAPL) 2007 form of operating procedure.77 Under these provisions, a non-operator may, in some circumstances, offer to act as operator on better terms than the current operator. If such an offer is made, the operator is then put into a position of “put up or shut up.” It

76. See, e.g., AAPL FORM 610, supra note 14, at VI.B.1. 77. CANADIAN ASS’N OF PETROLEUM LANDMEN, FORM OF OPERATING PROCEDURE

§§ 2.03 et seq. (2007).

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may either match or exceed the non-operator’s proposed terms, in which case it remains the operator (but based on those revised terms), or resigns. The winner of the challenge becomes the operator, but must operate in accordance with its proposals and bear all costs in excess of what was set out in its winning the challenge. In addition, the successful challenger may not resign for two years after becoming the operator. Challenges may only be brought after the current operator has been operating for a continuous period of two years.78 This procedure is an unlikely candidate for standardized inclusion in U.S. documents, but it is a potentially interesting tool to keep an operator honest and give a non-operator that has “learned the ropes” of unconventional development (especially a carrying party in a joint venture) an opportunity to operate, if it can add value.

C. Operational Risks

Operational risks are typically either dealt with in a cursory manner or not directly dealt with at all in conventional governing documents in the United States. Many companies would consider these risks part of the cost of doing business. Thus, cost risk is an accepted part of the oil and gas industry. A party’s right to be reimbursed by its partners for their respective shares of operating costs is generally not susceptible to challenge solely on the basis that the costs are too high.79 The commonly used 2005 edition of the COPAS (Council of Petroleum Accountants Societies, Inc.) accounting procedure permits rejection of a charge only in very specific circumstances, such as the charge being based on an incorrect cost-bearing interest, or an Authorization for Expenditures (AFE) that was not properly approved.80 In addition, under most conventional accounting procedures, the accumulation of surplus stock that is charged to the joint account (and that might be used to hedge against future cost increases for, or scarcity of, this equipment) “shall be avoided.”81 Most joint ventures do not have significant provisions designed to mitigate cost risks, other than limits on the amount of a carry. Thus, an operator is incentivized to save costs to some extent in order to preserve its right to be carried for as many wells as possible.

Delays and cycle time issues, likewise, are dealt with in joint operating agreements only in the requirement that a party re-propose an operation that has not commenced within ninety days.82 In farmouts, delay typically

78. Id. §§ 2.03, 2.05. 79. This assumes that the operator was not grossly negligent and excludes certain provisions

requiring competitive rates, such as Article 5 of the AAPL Offshore (Deepwater) Form (2007). 80. COPAS ACCOUNTING PROCEDURE § I.4.B (2005). Note that there are no cost overrun

provisions in a typical U.S. joint operating agreement and accounting procedure. 81. Id. § II.3. 82. AAPL FORM 610, supra note 14, at VI.B.1. But see Weems & Tellegen, supra note 5, at

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leads to forfeiture of a right to earn or breach of contract, but is otherwise not generally expressly handled. In a shale joint venture, delay is controlled, if at all, through a time limit on carry obligations.

As noted above, unconventional projects are sensitive to changes in costs as well as delays. That carried interests are common in shale joint ventures is in part a result of high and unpredictable development costs. Issues and decisions that might cause increased costs, delays, and increased cycle times are the very matters with respect to which U.S. non-operators usually are not afforded much input or influence.83 Some conflicts can be avoided before a project begins by ensuring that the parties have similar operating philosophies with respect to the project. By way of example, if an operator prefers to utilize early, multi-well pad drilling to gain efficiencies in lieu of early de-risking and holding (potentially) more acreage and then later switching to pad-based drilling, the non-operator should determine that this approach is acceptable prior to entering into any agreement. Many shale joint ventures have attempted to mitigate this by using operating committee concepts borrowed from international agreements.84 However, it is unlikely that any U.S. operator that is not at a severe bargaining disadvantage would allow an operating committee (either through its contractual power or voting control by the non-operator) to micro-manage operations. Thus, even the best operating committee provisions will probably not alleviate the effects of operational conflicts. Further, more complex decision-making structures may be, at some level, counterproductive in that the time that it takes to make a decision may leave the operator unable to take advantage of opportunities, such as buying another operator’s surplus equipment to alleviate its own shortages.

With respect to increasing cost and equipment scarcity issues, potential shale investors should consider including a specific recognition of when a pilot ends and a final investment decision (of sorts) is to be made. Though these phase lines are frequently indistinct, and have not traditionally been considered at all, setting a point—even if it is artificial—at which the parties must make an in-or-out decision would allow the operator’s procurement procedures to alleviate cost and delay

12. The new horizontal modifications to the AAPL 610 form (and presumably the forthcoming revised form itself) will contain provisions designed to protect an operator against what is apparently one of the most common sources of delays—the inability to move a horizontal rig into position after a “spudder rig” has left the drillsite until after the time period allotted in the relevant AFE.

83. In fact, under the AAPL Form 610-1989 joint operating agreement the operator actually acts as an independent contractor and is “not subject to the control or direction of the Non-Operators except as to the type of operation to be undertaken . . . .” AAPL FORM 610, supra note 14, at V.A. Shale joint ventures are typically not an exception to this rule.

84. See, e.g. AIPN MODEL FORM INTERNATIONAL JOINT OPERATING AGREEMENT arts. 5 et seq. (2012); see also Exco Res., Inc., supra note 63 (BG/Exco Joint Development Agreement).

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risk and to achieve economies of scale. This would result in increased up-front commitments for all parties and potential surpluses of equipment, but with lower overall costs and a reduced risk of delay due to unavailability. However, without a definite final investment decision and commitment from a non-operator to bear its share of these costs, an operator will be unlikely to budget for or be willing to bear all of the risk of ramping-up, building infrastructure, and otherwise preparing for production.85 Effectively mitigating operational risks, as with exploration risks, requires that parties surrender some of their freedom in favor of certainty.86

D. External Risks

External risks, such as changes in law, politics, and commodity prices, are difficult to mitigate, and will almost certainly affect projects, both conventional and unconventional, throughout their lifecycles. However, unconventional projects are especially sensitive to these risks due to their operation-intensive nature and the political controversy that has surrounded hydraulic fracturing. Effectively mitigating them (to the extent possible) requires, again, a shared operating philosophy, some input regarding operations for non-operators, and a commitment to the project regardless of its sensitivity to commodity prices.

These risks are rarely specifically addressed in U.S. joint operating documents. Commodity price risk can be seen as effectively handled by the ability of a party to refuse to participate further in operations and re-allocate capital to other projects. Other than this, it cannot be effectively jointly mitigated unless the joint venture structure is an incorporated stand-alone entity that hedges its production. Some shale joint ventures afford the parties the ability to jointly agree to cease spending money on one play to focus on another that falls within the same document; however, the alternative project is usually not a higher-margin conventional project. Provisions relating to health, safety, and environmental (HSE) programs are almost entirely absent from traditional U.S. agreements, though shale joint venture documents have, from time to time, included requirements for HSE programs and allowed for HSE audits.87 However, the impact of external political and legal issues can potentially be lessened through the adoption of effective

85. If this occurs, parties that participate in the acquisition of goods and services may be able

to offset losses to some extent by selling surplus, as scarcity tends to affect all operators. 86. The CAPL “challenge of operator” procedures, discussed supra § IV.B.iv, could

potentially find application here as well. If the problem is the operator (and this is generally what non-operators will, to some extent, believe), these provisions allow the non-operator a mechanism to become the operator.

87. These provisions are frequently borrowed from AIPN documents.

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policies, procedures, and programs.88

V. CONCLUSION

Ultimately, unconventional projects are risky—in some respects more so than conventional projects. However, the purpose of this Article is not to imply that they are not worth it or to deny the impact that unconventionals have had on the U.S. energy industry, and indeed, the United States as a whole. But by ignoring or failing to understand the risks inherent in an unconventional oil and gas project, investors do their own projects a disservice. An unconventional risk profile can be dealt with to a large extent via contractual risk allocation, just as can that of a conventional asset. However, applying conventional risk sharing mechanisms to an unconventional project can be just as counterproductive as believing that producing oil from shale is like producing widgets from a factory.

The purpose of this Article, in that respect, has not been to provide a definitive solution. Rather, by suggesting different ways of conceptualizing the lifecycle of an unconventional project and offering general solutions, we hope to join our voices in the discussion that has already begun regarding how best to adapt over one hundred fifty years of drilling and production experience to a new world. Luckily, the shale boom is just beginning and has yet to finally settle into its proper place in the portfolios of oil and gas companies and in the industry as a whole.

88. See Weems & Tellegen, supra note 5, at 15 (citing Denbury Resources’ decision to

employ pad-based drilling in its 2011 Corporate Responsibility Report as an example of a company’s response to the need to “minimize surface disruption when drilling in sensitive areas”).

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