The final frontier eps low cost operating model

k kContents Acknowledgments ix Abstract x Chapter 1 Introduction 1 A Vital Industry 2 Industry Evolution 6Ten Reasons to Update Your Operating Model 9E&P Needs a New Agenda 19 Notes 20Ch

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The Final Frontier

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The Final Frontier

E&P’s Low-Cost Operating Model

Justin Pettit

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Copyright © 2017 by Justin Pettit All rights reserved.

Published by John Wiley & Sons, Inc., Hoboken, New Jersey.

Published simultaneously in Canada.

No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording, scanning, or otherwise, except as permitted under Section 107 or 108 of the

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To Krista, Trevor, Maddie, and Teddy, for their laughter, love,

and patience.

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Contents

Acknowledgments ix Abstract x

Chapter 1 Introduction 1

A Vital Industry 2

Industry Evolution 6Ten Reasons to Update Your Operating Model 9E&P Needs a New Agenda 19

Notes 20Chapter 2 The New Agenda 23Upstream Cost Transformation 24

“Cut Costs and Grow Stronger” 30E&P Capabilities 34

Resource-Based Key Capabilities 45Notes 49

Chapter 3 E&P Operating Model Redesign 51Internal Operating Model 55

Business Delineation and Performance Measurement 56Organization Structure, Capabilities, and Workflows 66Operations Management Processes 74

Delegation of Decision Rights 75Informal Social Norms and Corporate Culture 77Implications of Industry Evolution 80

Business Model Considerations 83Notes 85

Chapter 4 PMI and Other Event-Driven Redesigns 87The Search for a Perfect Ownership Model 89Preparing to Go Public 91

Key Success Factors 92Event-Driven Redesign 94

vii

Joint Venture Strategic Intent 122Joint Venture Value and Valuation 124Deal Structure 127

Joint Ventures in Practice—The “How” 132Notes 141

Chapter 7 Financial Implications 143Financial Strategy and Policy 145Hedging and Trading 155

Notes 168

Glossary of Terms 171

Other Useful Links 171

Works Cited 172 About the Author 178 Index 179

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Acknowledgments

I wish to thank the many people with whom I have had the sure of working over the past many years, for kindly providing theimpetus, expertise, and resources to produce this book, especially myformer partners and colleagues from Booz, UBS, and Stern Stewart &

plea-Co I would also like to thank my previous editors, including DavidChampion, Don Chew, Art Klein, and Krista Pettit, for teaching menot to write like a scientist

However, the views expressed herein are solely my own over, any errors or omissions are strictly my own

More-I also wish to thank my More-IHS colleagues, including UlviyyaAbdullayeva, Ruslan Anisimov, Kurt Barrow, Stephen Beck, RyanCarbrey, Andrew Day, Erik Darner, Jean Dugan, Blake Eskew, SteveFekete, Philippe Frangules, Bob Fryklund, Etienne Gabel, MarkGriffith, Tim Hemsted, Mark Jelinek, Ed Kelly, Jerry Kepes, ChrisKiser, Roger Kranenburg, Mike Kratochwill, Nick Lowes, FernandaMachado, Michael Marinovic, Paul Markwell, Michael Muirhead,Gil Nebeker, Charlie O’Brien, Alastair Reid, Darryl Rogers, JameyRosenfield, Senjit Sarkar, Ed Scardaville, Grigorij Serscikov, NickSharma, Curtis Smith, Leta Smith, James Stevenson, Dale Struksnes,Jim Thomas, Rodrigo Vaz, Dan Yergin, and Tim Zoba

Finally, I wish to thank the many clients who have challenged andentrusted me with their needs and encourage them to please continue

to do so!

ix

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Abstract

This book guides the reader through the redesign elements forthe internal operating model of an enterprise in the oil and gassector—including integrated oil companies (IOCs), majors and inde-pendents, national oil companies (NOCs), and services companies inthe upstream supply chain For simplicity, this book references thesecompanies as Exploration and Production (E&P) companies

A culmination of disruptive forces and evolutionary change in theoil and gas industry has conspired together to make the case for anew low-cost operating model The industry has experienced tremen-dous evolution in terms of: our understanding of the underlying globalresource base, the nature of its ownership and principal stakeholders,technologies and methods for resource development, and economicsand business models While companies have been very focused oncost and productivity, beyond incremental accommodations to change,there has been little effort to redesign and transform internal enter-prise operating models Moreover, unlike other industries that haveundertaken operating model transformations in response to disruptiveindustry forces, upstream companies rarely undertake operating modelchange on a systematic or enterprisewide basis, except post-mergerintegrations

The industry has made great strides, but now must sort through:

◾ What different to do

◾ How to do it differentlyOperating models and operational excellence must now be oneveryone’s agenda—changes can yield profound cost savings andoperating efficiencies However, change is much easier to plan than

to implement, and operating model redesign is rarely executed on anorganizationwide basis

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Introduction

1

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Aculmination of disruptive forces and evolutionary change in the

oil and gas industry have conspired together to make the case for

a new, low-cost operating model The industry has experiencedtremendous evolution in terms of our understanding of the underlyingglobal resource base, the nature of its ownership and principal stake-holders, technologies and methods for resource development, and theeconomics and business models

The industry was focused on cost and productivity even beforethe 2014 collapse in oil prices, but beyond incremental accommoda-tions in response to change there has been little effort to redesign andtransform internal enterprise operating models Unlike other industriesthat have undertaken operating model transformations in response todisruptive industry forces, upstream companies rarely undertake oper-ating model change on a systematic or enterprisewide basis

com-In the United States, natural gas and petroleum have played animportant role in our energy mix for more than 100 years.2 With thebenefit of more than $1.5 trillion over the past 10 years, accountingfor about one-third of all new power generation capacity, renewablesnow represent a small but important source of energy (see Figure 1.1)

Wind and solar provide 5 percent of all electricity consumed inthe United States (nuclear power accounts for 63 percent of all

2

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– 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000

Renewables Hydroelectricity Nuclear

Coal

Natural Gas Oil and Liquids

Oil and gas continue to play a vital role

Figure 1.1 World Primary Energy, by Fuel (million tonnes oil equivalent)

Source: BP Energy Outlook 2035

non–carbon-dioxide emitting power sources—the National Reviewestimates that it will take more than 100 years for solar to replacethe electricity currently obtained from nuclear plants).3 Even withthe tailwinds of government support at federal, state, and municipallevels, including regulations, tax credits, and direct subsidy, the USEnergy Information Administration (EIA) expects “fossil fuels” willprovide more than three-quarters of US primary energy in 2040

WHAT NOW?

Oil and gas companies have been focused on cost and productivity sincebefore the 2014 collapse in oil prices Upstream operators have madeenormous efforts through massive vendor concessions, capital projectdeferrals, reductions in force, and “high-grading” drilling and comple-tion activity to the most productive acreage

For example, in 2016, one dollar of US onshore capital yieldedtwice the output (i.e., BOE/D) that it did in 2014, due to lower costsand higher productivity

tech-of big-data analytics and digital solutions within the core operations.

But beyond direct accommodations in response to each of thesechanges, there has been very little effort to redesign and trans-form internal enterprise operating models Moreover, unlike otherindustries that have undertaken operating model transformations inresponse to disruptive industry forces (e.g., retail), the upstream rarelyundertakes operating model change on a systematic or enterprisewidebasis The notable exception has been event-driven situations, such aspost-merger integration (PMI) programs where promises of synergiesmay trigger fundamental reviews of upstream operating models, andmajor divestitures such as a sale or carve-out/spin-off, and initialpublic offering (IPO) preparation

Upstream operators were already struggling to earn adequatereturns before prices fell, but now face difficulties generating sufficientcash flow even to cover their basic needs—they do not generateenough cash flow to cover operating costs, capital projects, overheadexpenses, debt service, dividends, and so on With oil and gas pricesremaining low, hedges rolling off, and sources of cash falling short

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of uses for cash, the upstream requires fundamental gains in costand productivity Many of the largest (and easiest) cuts, like vendorconcessions, will not be sustainable over a full cycle Furthermore,some of the biggest gains thus far are not scalable And the futuresupply gap beyond 2020 requires a significant investment to find,develop, and produce resources that are very likely to be relativelyexpensive barrels

There must be considerably more work, and more difficult work,

to reduce upstream costs The industry has made great strides for sure,but now the more difficult (but more valuable) task is to sort through:

1 What different to do (i.e., setting the strategic agenda)

2 What to do differently (i.e., defining the operating model)The first question (i.e., the “what”) establishes a strategic agenda,and relates to choices in terms of the corporate and business unit strate-gies, asset portfolios, and business models Setting the strategic agendademands choices about what businesses to be in and what assets toown Perhaps more importantly, the strategic agenda must establish inwhich “key capabilities” to invest and which activities to “in-source.”

It is impossible to be “world-class” in every capability—every aspect ofactivity of the business and therefore critical choices must be made

The choices about what not to do are often more important than the choices about what to do Most upstream oil and gas enterprises

have a portfolio of too many businesses, too many assets, too manygeographies, too many resource types, and too many opportunities,all of which are competing for too little capital, not enough expertise,and too limited a talent pool Therefore, the most important strategicchoices are what not to do Moreover, these choices require an iterativeprocess to “reconcile” between the following three critical elements ofthe upstream enterprise:

1 Aspirations, goals, and objectives for the business

2 Opportunities and needs of the underlying resource portfolio

3 Organizational capabilities of the enterprise internal operatingmodel and talent pool

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The second question (i.e., the “how”) sets the enterprise ing model, and relates to the internal architecture of the company, itsoperation, and its governance Defining the operating model—choicesregarding the internal architecture, performance metrics, systems, pro-cesses, and culture has a profound impact on the performance of anenterprise An operating model is effectively the “blueprint” for theinternal architecture of an enterprise, its operation, and oversight

operat-Now, most research and experience with low-cost operations

tends to focus on innovation in business models (rather than enterprise

internal operating models) to lower the costs of acquiring and servingcustomers and enhance the customer experience, often with digitalplatforms.4–6 Where there is research and experience with low-costoperating models, it tends to be in consumer-facing industries,with examples such as Costco, Dell, Southwest Airlines, Walgreens,Wal-Mart, E*Trade, and IKEA rather than “B2B” industries, orspecifically, the upstream oil and gas industry.7,8

INDUSTRY EVOLUTION

Over the past century, the oil and gas industry has experienced a icant evolution in terms of our understanding of the underlying globalresource base, the methods and technologies involved in its develop-ment, and the nature of its ownership and principal stakeholders Inconjunction with this change, there has been considerable evolution

signif-in bussignif-iness models—but so far, the accommodations made to prise internal operating models have been largely incremental (seeFigure 1.2)

enter-What began in the early days of the twentieth century as a largelyentrepreneurial effort quickly evolved into big business, in part due

to the scale of its requirements, in terms of capital and expertise—inthe 1960s, oil supply was safe and abundant and not a constraint

on economic growth, with excess capacity exceeding demand byabout 20 percent of the free world’s consumption.9 This fueled the

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Corporatization and professionalization

Functional technical expertise Field services companies Nonoperated

ventures Joint ventures National oil companies

Mega-mergers and spin-offs Growth in resource

diversity Cost inflation Shared services models

Down/midstream exits

Asset teams, enhanced subsurface technologies, digital and big data analytics Business models and enterprise architecture adapting to our understanding of the global resource base

Figure 1.2 Upstream Evolution

Source: IHS Energy

corporatization and professionalization of the industry and facilitatedtremendous growth in functional expertise, especially geological andgeophysical roles, engineering, and other technical functions Thegrowth era of 1972–1981 drove large-scale expansion While the1980s were characterized by low prices, layoffs, and consolidation,they also gave rise to innovations in 3D seismic, commercial begin-nings for both horizontal and logging while drilling, and many newtechnologies and service companies.10

While the breadth and depth of technical capabilities flourished,

so, too, did the opportunity for specialized field services companies

to provide such expertise on an intermittent or as-needed basis

Similarly, business model adaptations such as nonoperated ventures(NOVs) and joint ventures (JVs) enabled companies to participate

in resource development and production activities beyond the reach

of their core ownership holdings or core capabilities These vehicles

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also facilitated a pooling of financial capital and technical expertise,which were often in short supply, while also syndicating the projectrisk—which was often considerable

As oil and gas became big business, many host countries recognizedthe opportunity to retain a greater share of their resource sector’sbounty and control through the adoption of state-led national oilcompanies (NOCs)—another variation in the sector’s business models

Consolidation among the largest integrated players (mega-mergers)facilitated consolidation—affording large economic gains in thedownstream refining and retail segments of the industry and aconsolidation of conventional upstream business Many companiesadopted corporate shared services models for centralized procurementand other business roles

Consolidation of the world’s lowest-cost conventional resourcesunder NOCs and state ownership caused international oil compa-nies (IOCs) and independent operators to venture further afieldinto new international frontiers and a growing array of resourcetypes—including ultra-deep-water, the arctic, shale gas, tight oil, andthe Canadian oil sands These ventures generally represent muchhigher cost resources and require even more specialized expertise

In the aftermath of the collapse in oil and gas prices, efforts tooffset the effects of cost inflation and capital constraints have includedthe sale of many midstream and downstream assets, with manyupstream operators exiting these parts of the value chain to focustheir efforts (and limited resources) on the needs and opportunities

of the upstream Within the enterprise, this has generally included amigration toward asset team organizations, and investments in keycapabilities such as enhanced subsurface capabilities, with improveddata processing for 3D seismic, greater use of geomechanical modelingand reservoir engineering, enhanced recovery (EOR), and newapplications for digital and big data analytics

Despite this evolution—our understanding of the resource base,methods and technologies for its development, ownership and stake-holders, business models—there has been little effort to redesign and

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transform enterprise operating models beyond incremental dations Unlike industries that have undertaken operating model trans-formations in response to disruptive industry forces (e.g., retail), theupstream rarely undertakes operating model change on a systematic orenterprisewide basis The notable exception is post-merger integration(PMI) programs, where promises of synergies often trigger fundamen-tal reviews of operating models

accommo-TEN REASONS TO UPDATE YOUR OPERATING MODEL

Many factors have conspired together to make the case for change—

reasons to adopt a low-cost operating model A culmination of ruptive forces—including supply gluts in US shale gas and tight oiland growing consensus among world leaders to curb fossil fuelemissions—is reshaping the global energy landscape Despite severalyears of relatively high prices, upstream returns had been low, both

dis-by historical standards and relative to the cost of capital And it hasbeen difficult for the majors to maintain, let alone grow, production

or replenish reserves Nor can we rely on high prices Furthermore,research indicates a major shift in how capital markets value oil andgas companies, with multiyear income, cash flow, and operationalmeasures (including reserves) playing a much more important role instock prices.11,12

Evolving Global Resource Base

Enterprise operating models require a much broader set of keycapabilities, some new, to accommodate our evolving understand-ing of the global resource base (see Figure 1.3) Furthermore, thereplacement challenge facing the industry is formidable—the worldneeds ∼60 million barrels per day of new production by 2040

to offset declining fields and net demand growth This must besourced from an increasingly diverse, and expensive, resource baseamidst choices between enhanced recovery from mature fields,new frontiers, deep-water and ultra-deep-water, unconventional

LNG Export

Coal Seam Gas Brazilian

Pre-Salt Vaca Muerta Shale

Global resource base growing increasingly diverse

Figure 1.3 World Resource Plays

Source: IHS Energy

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resources such as tight oil, shale gas, oil sands, and coal bed methane,and emerging but largely unproven sources, like the arctic, seabedmethane hydrate, and carbonite reservoirs.13The industry is pursuinghigher-cost resources, more technical/lower quality reservoirs, heavyoil, or harder to commercialize gas, and with more above-ground risk

Disruption from the “Ripple Effect” of Unconventionals

Rapid growth in US onshore unconventional liquids production andhigh levels of natural gas production (despite falling rig count andnew well spuds) have contributed to keeping liquids, gas, power,and industrial feedstock prices low This has fueled disruptive changethroughout the economy and altered the competitive landscape forrefiners, petrochemicals companies, and energy infrastructure In theupstream, shorter cycle times and very different subsurface risk andcash flow profiles have challenged strategies with disruptive impactalong several dimensions:

◾ Increased short-cycle supply, reduced prices, increased pricevolatility, and challenged the role of OPEC; there was a west-ward migration in the balance of power and a reorientation ofcrude and product flows and trade patterns

◾ Shifted capital inflows toward US onshore; private capitaldove headfirst into the upstream sector; many exploration andproduction (E&P) companies created separate organizations forunconventionals investment and/or operation

◾ Provided operational blueprint for developing lower ity oil and gas reservoirs internationally

permeabil-◾ Challenges to pricing mechanisms, market liquidity, and petitiveness of global gas/LNG projects

com-◾ Increased cost-competitiveness of US petrochemicals; capacityshifted away from foreign naphtha-based markets toward USethane-based conversion capacity and downstream manufac-turing

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◾ Reduced US carbon footprint and increased cost-competitiveness

of US power-intensive industry; there was more displacement

of coal-fired (and even some nuclear) power generation

Discovery Challenges

The challenges of our evolving resource base are accentuated by adecline in conventional exploration—conventional oil and gas explo-ration is yielding lower volumes of higher-cost, lower-value reservoirs

We are replacing cheaper, high-quality barrels with high-cost/

lower-quality barrels (see Figure 1.4) Accounting for the rise ofunconventionals—a relatively high-cost resource—only makes thispicture worse

The year 2015 marked the lowest point for conventional oiland gas discovery in many years—the absolute number of wellsdrilled generally has not been in decline as much as the volumes beingdiscovered—a smaller number of large fields Nor have there been manybillion-barrel discoveries—the Piri gas field in Tanzania was 1.9 Tcf(i.e., 318 million boe), accounting for 16 percent of total volumes

A growing proportion of discoveries are in the higher-cost deep-water

0 50 100

150

Adjustments to discoveries made

in prior years New discoveries, initial estimate

Note: Fields above 50 MMboe; excludes Canada onshore, L-48 onshore, US shallow water, and Orinoco extra-heavy

Conventional discovery, battling headwinds, eclipsed by field growth

Figure 1.4 Conventional Oil and Gas Discoveries and Field Growth, by Year

Source: IHS Energy

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(i.e., 1000 to 5000 ft) and ultra-deep-water (i.e.,>5000 ft); discoveries

in shallow water (i.e., <1000 ft) and onshore are in decline And

more gas than oil is being discovered, which are lower economicvalue resources

The rise of unconventionals, plus successful openings in placeslike Mexico and Iran, bring great promise but do not address all ofour replacement needs Nor will growth in renewables The globalresource potential remains enormous but appraisal and development

is costly and technologically complex Many new plays still requireeconomically viable fiscal terms, operating structures, and costs Wemust replace “cheap barrels” in the context of an evolving and increas-ingly expensive resource base, disappointing conventional explorationresults, project delays, and rising costs and capital intensity

One bright spot has been the offsetting effect of “field growth”—

upward adjustments made to the volumetric resource estimates ofprior year discoveries—which now often exceeds new discoveries

Roughly 2000 conventional fields have their technical resourcesrevised upward every year based on factors such as more/betterdata, de-risking milestones, and enhanced interpretation Therefore,some companies might opt to focus on existing basins and fields overtraditional frontier exploration in order to reduce costs and mitigatedeclining exploration success rates Others might opt to focus onunconventionals, which carry a very different subsurface risk (andcost) profile than conventional frontier exploration

Fading Production

Upstream operating cash flow is both inadequate and in decline

Despite a period of high prices, returns in the upstream oil and gassector were already down (i.e., both relative to historical returns oncapital and relative to the cost of capital) well before the 2014 collapse

in oil prices Moreover, as illustrated in Figure 1.5, major producersstruggled to grow their production (and to replenish reserves) Pro-duction is fading, operating margins have shrunk, the supply chain ofservices companies has telegraphed that its prices must rise, and theamount of invested capital has soared

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– 1,000 2,000 3,000 4,000 5,000 6,000 7,000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

TOTAL Chevron Shell BP ExxonMobil

Global production by majors flat to declining despite attractive prices

Figure 1.5 Worldwide Oil and Gas Production by Majors (MM boe)

Source: IHS Energy

Many large NOCs, such as Mexico’s PEMEX and Venezuela’sPDVSA, also face fading production Over the past 10 years PEMEX’stotal annual production of gas and liquids declined 35 percent,from 1580 million barrels of oil equivalent (MM boe) in 2006 to only

1159 million boe in 2015 Host governments and state-owned nationaloil companies had grown reliant in their expectations for high returnsand a steady stream of cash flow from royalties or dividends to fundpublic programs and other state initiatives The oil and gas sector hadbecome the proverbial cash cow

But with fading production and massive investment requirements,host governments and national oil companies must take action Forexample, liquids production from PDVSA has gone from 3.3 millionbarrels per day in 2008 (the year before the nationalization of its oilservice companies) to only 2.7 million barrels per day (bpd) in 2015,

an 18 percent decline Venezuela’s Maracaibo-Falcon basin declined

35 percent from producing 1 million bpd in 2008 to 0.7 million bpd

in 2015 Production from the enormous El Furrial field declined anextraordinary 51 percent in seven years from 408,000 bpd in 2008 to

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just 198,000 bpd in 2015 While production does typically decline inmature fields, this rate of decline is unusually severe

Costs and Capital Efficiency

Most of the world’s conventional fields are “mature” and the tional complexities of mature fields grow over time—this puts pressure

opera-on costs We also see cost escalatiopera-on driven by a rising tide of local copera-on-tent requirements, falling yard productivity (e.g., more rework), and insome cases, other factors such as regulatory requirements and highercomplexity

con-The case of UK offshore operators is not unusual—they enced more than a threefold increase in development costs on a perbarrel of oil equivalent (boe) over 10 years, while unit operating costsrose nearly fourfold Meanwhile, production efficiency—how much isactually produced from production facilities compared to what would

experi-be produced if they operate without problems—has dropped over thesame period from around 80 percent to less than 70 percent.14 Theindustry was able to withstand this decline in productivity and esca-lation in costs because oil prices nearly tripled over the same period

But now the economics of North Sea production are very challenging,with negative free cash flow in some fields, and often reliant on thebenefits of a large installed base of infrastructure

Project delays and overruns have damaged IOC reputations foroperational excellence, and much of this comes from the way IOCshave managed uncertainty as projects have become more complex

The real project cost baselines and their uncertainties and risks are ther well estimated nor well managed In the United Kingdom, fivelarge projects accounted for about 30 percent of total spend, whilesmaller fields accounted for the rest As field sizes become smaller, unitcosts rise Oil & Gas UK cited the average unit development cost forfields under consideration at £13.50/boe ($21.75), up from £4.00/boe($6.44) on an inflation-adjusted basis from 10 years earlier; the averageunit operating cost year was £17.00/boe ($27.39), up from £4.50/boe($7.25) 10 years earlier.15 As the unit cost rises, the economic life of

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many fields is shortened; more reserves are stranded as infrastructure

is decommissioned earlier

Technology and Expertise

Enterprise operating models now require a much wider set of ical capabilities to accommodate the growth and evolution of theindustry’s requisite capabilities—combinations of assets, technology,and expertise For example, recent industry-changing innovationsinclude deep-water and ultra-deep-water technologies, productiontechnologies in the oil sands, 3D seismic acquisition and data process-ing, rotary steerable drilling, geo-steering with logging-while-drilling,horizontal drilling coupled with multistage hydraulic fracturing, and ahost of completions techniques for unconventionals involving greateruse of water, proppant, and pressure (aka superfrac), longer lateralsand more stages, sequencing variations (e.g., zipper frac), differentproppants (e.g., ceramic), and more Greater capabilities are required

crit-to enhance primary and tertiary recovery in shale gas and tight oil

Artificial lift for horizontal wells is an evolving science, and recovery

is also managed through reservoir contact, in-fill drilling, trade-offsbetween lateral length frac height, stage spacing, and downspacing,and opportunities for refracturing

Supply Chain and Services

Enterprise operating models also might be reoptimized to acknowledgethe massive growth and evolution of the upstream supply chain foroutsourced services—its size, potential roles, and available capabilities

The upstream supply chain has transformed the industry throughfunctional and geographical unbundling One fundamental trade-off

in this fractionalization is between the gains of capabilities specialization

(and their utilization), versus the costs of coordination and oversight

Growth in the externalization of services has enabled greater tion of specialized capabilities—combinations of assets, technology,and expertise—in novel ways The future of the supply chain will

utiliza-be influenced by: (1) improvements in coordination technology

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that lower the cost of functional and geographical unbundling,(2) improvements in production technology that affect the benefits ofspecialization, (3) narrowing of wage gaps that reduces the benefit ofoffshoring, and (4) the price of oil.16

Fiscal and Regulatory Terms

We have seen a significant evolution in the structure, calibration, andfluidity of host government fiscal and regulatory regimes for natu-ral resources, with immediate implications for enterprise operatingmodels Government receipts may include royalties, local and statetaxes, corporate and special taxes, and direct participation or partic-ipation through an NOC One result of all the competing objectivesfor fiscal and regulatory terms is that this has become an increasinglycomplex and specialized area, demanding specialized expertise both

to navigate strategic choices and also to influence the competitivelandscape

Fiscal regime types fall into two broad categories: (1) concessions,which involve royalties and taxes (R/T), and (2) contracts, such asproduction sharing contracts (PSCs) or service contracts (SCs) How-ever, some R/T regimes are based on contracts, and some SCs lookvery much like PSCs R/T structures prevail in much of the Americas,Western Europe, and Australia PSCs prevail in much of Africa andAsia SCs prevail in Mexico, Saudi Arabia, and Iran Structures inAlgeria, Iraq, Russia, and Kazakhstan might be described as a mix

Norway has long held an R/T regime that captures a relatively hightake in terms of its economic rent from the oil and gas sector whileother advanced, industrialized states with R/T regimes capture less.17

Malaysia and Indonesia are two of many countries that have adoptedPSC structures within the last 30 decades However, the Indonesianfiscal regime tends to be less investor-friendly than Malaysia, whichattracts much more foreign investment in its oil and gas sector After

a disappointing bid round in 2009, Indonesia proposed changes to itsfiscal and regulatory regime in 2010 to attract more investment.18

Neither R/T nor PSC regimes necessarily dictate a high or low

gov-ernment take, but PSCs tend to be more progressive, and progressive

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terms are especially important in a low-price environment—progressivestructures are those that vary with prices or profits, such as taxes andprofit sharing Regressive structures are those that are fixed and notlinked to prices or profitability, such as royalties, export duties, anddomestic market obligations (DMOs) Fiscal regimes (and resource bidrounds) seek to strike a balance between encouraging direct invest-ment and the need for an attractive and politically saleable governmenttake, and a growing interest in methods to promote local economicdevelopment.19Similarly, regulatory frameworks seek to increase inno-vation and competition while also ensuring safety and environmentalconcerns, but must avoid becoming overly burdensome or expensive

Social License and Environmental Costs

Upstream companies today require an enterprise operating model thatinvolves a much greater investment in capabilities that support andpromote their social license to operate than ever before Regardless ofone’s views on climate change and the host of other environmentalissues and concerns that can affect the industry, the inarguable truth

is that environmental issues have grown to become an extraordinaryforce for the E&P sector, manifesting in an extremely wide range

of business costs and challenges These include increased capitalexpenditures and higher operating costs to meet the rise of regulatoryrequirements, major project delays, and lower wellhead prices due

to constraints in take-away capacity, restricted access to federal landsand waters, and outright bans on some practices such as hydraulicfracturing or working in certain environmentally protected areas

One study by the Fraser Institute estimates that delays in pipelineprojects cost several billion dollars per year.20 Barriers to buildingpipelines that restrict Canadian take-away capacity result in pricesthat are 20 to 30 percent below Brent, costing Canada’s economyand governments billions in forgone revenues “Without adequatepipelines to Canada’s coasts, Canadian oil producers are forced to selltheir products at dramatically discounted prices,” said Kenneth Green,

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senior director of Natural Resource Studies at the Fraser Institute and

co-author of The Costs of Pipeline Obstructionism.21

Weak Oil and Gas Prices

Under even the most optimistic outlook for oil and gas prices overthe next several years, upstream oil and gas companies need a newlow-cost operating model now more than ever North Americannatural gas prices had been low since 2009, under surging supplyfrom the boom in domestic shale gas production But now we see thesame story playing out in global liquids, from US tight oil production

as well as both OPEC and non-OPEC production According to Oil &

Gas UK, even at $80, one-third of the UK’s offshore developments areuneconomic.22

E&P NEEDS A NEW AGENDA

The E&P context has changed and while on their own any one of thesechanges might be quite manageable, in aggregate, the change in con-text demands a bold new approach for a low-cost operating model

The industry has experienced tremendous evolution in terms of ourunderstanding of the underlying global resource base, the nature of itsownership and principal stakeholders, technologies and methods forresource development, and the economics and business models Yetbeyond incremental changes, we have not seen efforts to redesign andtransform operating models on a systematic or enterprisewide basis

The upstream has been focused on cost and productivity for severalyears and has made significant gains since the collapse in oil prices

However, operating cash flows remain generally insufficient to coveroperating costs plus the needs for future investment, let alone provide

an adequate return on the capital that is already employed And many

of the cost gains that have been made will not be sustainable over a fullcycle The “low-hanging fruit” has been taken, but still there is muchwork to be done

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Operating models and operational excellence must now be oneveryone’s agenda—changes can yield profound cost savings andoperating efficiencies However, change is much easier to plan than

to implement Furthermore, operating model redesign is rarelyexecuted on an organization-wide basis (notable exceptions includepost-merger integration programs, large-scale cost-transformationprograms, and other event-driven programs that are charged withsignificant cost targets)

Operating model redesign is a time to cut costs while growingstronger—by investing in the most important capabilities, whileleveraging the capabilities of others where it makes sense to do so

Operating model redesign is also a time to harness the entrepreneurialspirit of the talent pool—to align, empower, and enable employees

to drive enterprise improvement, balancing between quick wins thatbuild momentum and longer-term efforts that require major change

(December 2006).

and Stephanie Woerner, “Do Some Business Models Perform Better than Others?”

(May 2006) MIT Sloan Research Paper No 4615-06 Available at SSRN: http://ssrn com/abstract=920667 or10.2139/ssrn.920667.

BCG Perspectives (October 2010).

(September 2012).

A Strategic Approach to What to Cut and What to Keep (Boston: Harvard Press, 2006).

Schuster, 1990).

(October 1, 2005) Available at SSRN:http://ssrn.com/abstract=874915.

13 See also Paul Markwell, Justin Pettit, Andrew Swanson, and Jim Thomas, “The New Frontier for National Oil Companies” (January 1, 2014) Available at SSRN:

18 Granita R Layungasri, “Comparative Study of Indonesian PSC and Malaysian PSC:

Challenges and Solution” (May 14, 2010) Available at SSRN: http://ssrn.com/

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The New Agenda

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Industry leaders face seemingly conflicting imperatives to cut costs in

response to a supply glut with low liquids and natural gas prices, butalso to invest in the needs of the business—facing much higher-costresources, such as deep-water projects, unconventionals, oil sands, anddifficult international frontiers

Companies (and countries) are adjusting to lower oil and gasprices, but many of the actions being taken are not consistent withlonger-term needs for investment and sustainable growth Further-more, sadly, some of these actions are unsustainable, or at best,one-time gains and not scalable across new future production

A new strategic agenda and operating model where cost mation is premised on a capabilities-driven strategy can resolve theseseemingly conflicting imperatives—to cut costs sustainably whileinvesting in the future of a business

transfor-UPSTREAM COST TRANSFORMATION

Upstream project deferrals, spending cuts, and vendor concessionswere the first tools to cut costs and conserve cash, but now we are

in the midst of an important cost transformation with companiesand countries adjusting to “lower-for-longer” prices Cost initiativesthat deliver the greatest impact and bring the most value to anenterprise are not only “large-bucket” spend items but initiatives

that are both sustainable over a full cycle and scalable across each unit

of production—effectively unit costs, rather than period costs (see

Figure 2.1)

Intrinsic Value of Cost Savings

In intrinsic value terms, we can derive a “shortcut” valuation multiple

to approximate the present value of cost savings associated with fully

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Defer capital projects

Vendor concessions

G&A reduction

High grading Cut

Brackish sourcewater

Sourcewater by pipe/hose

Portfolio optimization Tax

optimization

Sub-sea tiebacks Platform de-manning

Sustainability (full-cycle) Greatest impact is sustainable, and scalable, in “large-bucket” spend

Figure 2.1 Illustration of Upstream Cost Initiatives

Source: IHS Energy

sustainable measures, as follows:

Present value of permanent cuts into perpetuity

= Savings × (1 − Tax rate) ÷ Discount rate

PV = Savings × (1 − 40%) ÷ 10%1

PV = Savings × 6 (i.e., a valuation multiple of roughly 6×)

We illustrate, with our framework, the intrinsic value of someefforts, such as a permanent but one-time tax optimization, or thecompletion of an inventory of DUCs Many of the largest gainsthus far—such as vendor concessions that are driving US servicescompanies into bankruptcy—will not be sustainable over a full cycle

Services pricing will need to recover as fleet utilization recovers, in

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order to provide sustainable levels of profitability Unsustainable cuts(i.e., top and bottom left quadrants) cannot be valued as a permanentsavings into perpetuity, and therefore warrant a multiple much lessthan 6×, and in some cases, where they are neither sustainable norscalable, may warrant no multiple at all

To warrant a premium valuation multiple (i.e.,>6×), we require

not only sustainability but also scalability—gains that can continue

to be replicated on a much larger scale with the growth of the ness Generally speaking, scalability is achieved through gains asso-ciated with the unit costs of production, not with period costs In ourfigure, premium multiples are afforded on efforts in the top right quad-rant, such as scalable well cost/productivity initiatives

busi-Some of the greatest gains thus far—such as high grading—aresustainable but less scalable The opportunity for high grading is con-strained by the areal extent of highest quality core acreage and is,therefore, not scalable across the entire portfolio In other cases, likedrastic cuts to exploration or overhead spend, these are period costsrather than unit costs And by their very definition, capital projectdeferrals are neither sustainable nor scalable; while they can play animportant role in preserving cash, they do not warrant a multiplier toapproximate their contribution to intrinsic value

High-Grading

As rig activity plummeted, high-grading emerged to mitigate thesupply impact Much of the US new well spud activity retrenched toWest Texas, especially the well-established and relatively low-costGreater Permian Basin while more rigs were idled in other plays

However, in the Bakken and Eagle Ford, the inventory of drilledbut uncompleted wells (DUCs) was worked down in the core areas

of higher well productivity, leading to considerable growth in newproduction at the cost of very few rigs Just three of the Eagle Ford’s

15 active counties account for most of the top-performing wells

Capital in 2016 is roughly 65 percent more efficient than 2015, due

to this focus on higher quality core acreage and advances in well design

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and completions techniques, which can bring dramatic productivitygains Proppant intensity continues to grow in the better parts ofmost major plays, especially the Haynesville, Permian, and Marcellus

However, operator results are mixed and productivity gains generallylimited to the sweet spots These gains appear to be both sustainableand scalable, but only to the full areal extent of the core acreage

Reprioritizing (to Suit Forward Prices)

Beyond high-grading per se, operators must continually revisit theprioritization of their opportunity set to suit evolving forward pricecurves If West Texas Intermediate (WTI) and Henry Hub prices aredown 50 percent, we face very different well economics Just asthe best strategy depends on the operator, the portfolio, and thecapabilities, so, too, does it depend on the price environment

Under high prices, the most important cost in the field is theopportunity cost of forgone production—well costs and the relativequality of acreage are less important because net present value (NPV)

is positive in all but the worst cases (below) In a high-price ronment, the Bakken’s, Eagle Ford’s, and Utica’s relatively high

envi-initial productions (IPs) are very attractive High prices make well

delivery a key upstream capability, driving widespread interest in lean

manufacturing and directing upstream services to be outsourced with

an eye toward ensuring availability

Under low prices, the economics of different plays, such as thePermian, are more attractive (see Figure 2.2) Stacked benches andshallower depths can reduce drilling and completion costs, while sub-surface risk, established infrastructure, and wellhead price differentialsalso favor some Permian economics Operators in the Permian haveachieved favorable 30-day IP rates that, when combined with drillingand completion (D&C) cost savings, culminate in capital dollars that aremore than twice as productive in 2016 as they were in 2014 The Wolf-camp, Bone Spring, and Spraberry sub-plays also captured the interest

of Wall Street—not just the acreage but also the services and midstreamassets serving these plays

Best 20% Second 20% Third 20% Fourth 20% Worst 20%

Under high prices, the most important cost is “opportunity cost”

Figure 2.2 Permian Break-Even Oil Prices by Sub-play ($/barrel)

Source: IHS Energy

Where services are outsourced, it will be to achieve gains in cost

or productivity (e.g., due to greater expertise through specialization,efficiency gains through economies of scale or through better rates ofutilization) rather than simply to ensure availability Commitments

to leasehold drilling must yield to the efficiencies of multi-well-paddrilling (MWPD) and the productivity of high-grading and, whilesome drilled-but-uncompleted (DUC) inventory is a natural element

in the development process, efforts must be made to lean the balancesheet and minimize any investment in non-cash-generating capital(i.e., despite forward price speculation)

However, the best plays are also the worst plays—while the camp Delaware boasts the best break-evens (roughly $32 per barrel),

Wolf-it also boasts the worst ($316 per barrel) And the Bone Spring is quWolf-itesimilar in this regard; therefore, the Delaware Basin outperforms theMidland basin at both ends of the cost curve

The economics of vertical wells can still be very attractive, with thebest Spraberry vertical wells nearly as attractive as the best horizon-tal wells in the Wolfcamp Delaware Moreover, Spraberry vertical welleconomics seem to offer much lower subsurface risk, with even theworst 20 percent breaking even under $40 per barrel (bbl)

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It is important to note that noncore acreage in the most tive Permian basin sub-plays offers far less attractive economics thanwhat can be achieved from the best acreage in other plays, such asthe DJ basin, Eagle Ford, or Bakken Operators understand this, which

attrac-is why we see very different areas of relative focus between EOG,Pioneer, Encana, and so on And so while Pioneer suspended drilling

in the Eagle Ford to add rigs in the Midland basin, Encana focused inthe Northern Bone Spring of New Mexico

Fiscal Terms

Operator cost structures are heavily dependent on fiscal terms—bothRoyalty/Tax (R/T) and Production Sharing Agreement (PSA) fiscalschemes—and their treatment of cost recovery (i.e., both capex andopex) PSAs typically offer the lowest exposure to development costincreases, but not always They often have the highest recoverybecause incurred costs are recovered in full—an annual productioncost-recovery ceiling determines the period of recovery (e.g., 100 per-cent takes less time to recover costs than 15 percent) R/Ts generallyhave lower cost recovery—costs incurred are usually only partiallyrecovered through tax deduction over a longer period Lower taxesand shorter depreciation periods produce less cost recovery and so acontractor in a low-tax R/T is more exposed to capex increases than

a PSA with full recovery When oil-producing countries face fiscaldifficulties, they consider revisions to keep major projects on trackand attract new investment

Strategy-Led Cost Transformation

Major performance improvement programs can also bring downcosts through changes to operating models, such that organizationalstructures, business processes, and decision rights are optimized tosuit the needs of the asset portfolio managed—early stage assets,late stage assets, and unconventionals may each be suited to its ownoptimal operating model design This can lead to inefficiencies andperformance problems in blended company portfolios

Successful change requires a significant investment in systems andworkforce education, training, and business/economic literacy Edu-cating people on why change is needed, how it can benefit them andother stakeholders, and what they can do to help (i.e., that is withintheir line-of-sight) has a profound impact on program and enterprisesuccess In the pursuit of cost savings, it will be critical for the industry

to reduce health, safety, and environmental risks; many organizationsmay need to increase, not decrease, their spending in this area

“CUT COSTS AND GROW STRONGER”

A few years ago, three of my business partners published a ful book about how companies could simultaneously achieve theseemingly competing needs of near-term cost cutting and longer-terminvestment in growth.2 Based on many decades of working success-fully with fast-moving consumer goods companies, they made the caseagainst across-the-board cuts that “spread the pain” across businessunits and departments and that remain the most common approachtoday The prevalence of this tactic stems from its ability to get results

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quickly with minimal political infighting, as well as its powerful allure

in terms of simplicity and apparent “fairness.” This new approach to

cost cutting is guided by an approach called capabilities-driven strategy,

which involves identifying and reinforcing key capabilities whilepairing those that do not reflect the company’s strengths, needs, andlong-term goals

We can adapt this approach to the E&P context with a somewhatiterative optimization of three critical, but interdependent, elements

in an E&P enterprise: (1) strategy, (2) asset portfolio, and (3) operatingmodel The operating model must follow and support the strategy, andthe strategy must suit the portfolio, and the portfolio dictates the req-uisite needs of the enterprise in terms of the organizational capabilitiespromoted by the operating model

Capabilities-Driven Strategy for E&P

E&P companies can confront the challenge of lower gas and liquidsprices while also strengthening their foundation for the future Thecost challenge is an opportunity to identify and reinforce strategiccapabilities while shedding those that do not reflect key strengths,organizational needs, or business goals This will make the enter-prise more resilient as tough times continue and more robust whenrecovery begins

Unfortunately, when it comes to identifying which key ties to reinforce, our industry has a long-established history of eitherdeclaring lofty but unrealistic aspirations of being “best-in-class” ateverything or buying into the one-size-fits-all solutions pitched by ourindustry bankers, consultants, experts and pundits

capabili-For example, one line of thinking suggests that operator strategies,and their capabilities, must be recast to minimize or exclude costly,high-risk mega-projects (e.g., deep-water, oil sands, Arctic, subsea gashydrates), and that since most of the world’s lowest-cost conventionalresources are controlled by NOCs, the only remaining viable operatorstrategy must be to target onshore unconventionals In today’s priceenvironment, the costs and risks associated with a $100 million well inthe North Sea or Gulf of Mexico that might come up dry is much less

the existing portfolios of the seven largest IOCs (including Statoil),about 65 percent of their new source production in 2020 will beoffshore One-half of this will be deep water This will be difficultwork, but we need someone to do it, and given their portfolios andbalance sheets, the IOCs may be the best suited to this job.

An operator cannot simply sell all less desirable (e.g., high-cost and/or low-IP) assets,and acquire only highly desirable (e.g., low-cost and/or high-IP) assets In a world withmultiple buyers and sellers, good access to information, and widespread competence atdiscounted cash flow modeling, asset desirability should be fully reflected in transactionprices The prices of attractive assets are bid up and the prices of unattractive assets

are discounted Therefore, buying attractive assets can be zero-NPV event that simply affords the opportunity to earn your own money back over time; selling unattractive assets

may just be a chance to accelerate bad news with a balance sheet mark-to-market event

Each asset is worth its most to its natural owners—enterprises that are strongest in terms

of the most relevant capabilities for the asset The challenge for an E&P portfolio is todetermine the requisite capabilities for each asset, a sense of its potential natural owners,

an ideal future state portfolio for the enterprise given reasonable practical constraints ofcapital and capabilities, and a blueprint for building and strengthening the requisitecapabilities for this future state portfolio

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What then, should operators do if they’ve been dealt a bad hand?

Executives routinely face portfolio decisions about which assets todevelop, which assets to starve, and which to sell Conventional

wisdom might be to invest more heavily in stars, or attractive assets, while starving or selling the underperforming or unattractive dogs.

But a few years ago, three of my colleagues published a provocativepaper, based on empirical research, that demonstrated that this isoften wrong In many cases, more value can be created by improvingthe operations of the worst-performing assets, or to “love your dogs.”4This research concluded with the following recommendations:

1 Fixing dogs can yield unexpected levels of shareholdervalue—experience suggests that turning around an undervaluedasset can be analogous to turning around an undervaluedcompany

2 Improving operations is an important lever for adding value

Starving dogs is not a strategy for creating shareholder value;

in aggregate, there is more potential value in helping dogs torealize full potential

3 Buying and fixing dogs often produces more value than buyingstars Adding value to a fully valued asset is a tall order—especiallygiven the premiums paid for attractive acreage It is no wonderthat such a large proportion of corporate acquisitions fail to addvalue for the acquiring shareholders

These findings underscore the need for operators to launch a cess to identify and reinforce key capabilities while cutting those that

pro-do not reflect their strengths, needs, and long-term goals

Operating Model and Organizational Capabilities

Organizational capabilities are the lifeblood of an enterprise In theE&P sector, this includes positional assets such as the acreage—

the portfolio of subsurface resources is obviously a critical piece of thepuzzle Ideally, these would be “advantaged” positional assets, close

to the sweet spots of core plays, but as previously discussed, this is