The State of the Energy Industry

Copyright © 2013 by ScottMadden. All rights reserved.

The State of the Energy Industry

ScottMadden-Energy Central Webcast

March 27, 2013


Today’s Agenda and Your Presenters

Welcome and Introduction

1

Energy Infrastructure

Efficiency, Demand, and Rate Regulation

Electric Transmission

Gas-Power Interdependence

Fossil Generation

2012 Election and Policy Developments

NERC’s Latest View

Coal Plant Retirement Risks

Supply Chain Issues for Retrofit and Replacement

Natural Gas

Price Predictions

Shale Gas

The United States as the “Saudi Arabia of Natural Gas”

New Pipeline Capacity Needs

Stu Pearman

Partner and Energy Practice

Leader

Cristin Lyons

Partner and Transmission,

Distribution, and Smart Grid

Practice Leader

Todd Williams

Partner and Fossil

Generation Practice Leader

Ed Baker

Partner and Natural Gas

Practice Leader

Greg Litra

Partner and Energy, Clean

Tech, and Sustainability

Research Leader

Questions and Answers

Energy Infrastructure

Cristin Lyons

Partner and Transmission, Distribution, and

Smart Grid Practice Leader

Cristin Lyons is a partner with ScottMadden where she

leads the firm’s transmission, distribution, and Smart Grid

practice. Her areas of expertise include T&D operations,

mergers and acquisitions, and organization design. She

joined the firm in 1999 and has been a partner for more

than six years.


Energy Infrastructure Issues and Trends

Key Trends

Energy efficiency continues to drive year-over-year growth in energy demand lower; utilities are seeking alternative recovery mechanisms in this slow demand growth environment—sometimes also entailing lower allowable ROEs

While the outlook for transmission remains positive, there are many factors that could impact the speed and length of this build out

As power generation becomes increasingly dependent upon natural gas as a baseload or swing fuel source, federal and reliability officials are turning their attention to infrastructure adequacy and coordination of the gas and electric industries, increasingly important issues

Discussion Overview

Efficiency, Demand, and Rate Regulation

Electric Transmission

Gas-Power Interdependence

3


Efficiency, Demand, and Rate Regulation Shifting the Utility Model?

4

Revenue Decoupling Mechanism (Elec. Utils.)

Lost Revenue Adjustment Mechanism (Elec. Utils.)

Pending

Lost Revenue Adjustment and Revenue Decoupling Mechanisms

for Electric Utilities (as of July 2012)

Even without direct mandates like energy efficiency resource standards, indirect effects from federal mandates, building codes, and improved materials and technologies, continue to reduce energy intensity

Fitch considers energy efficiency “a significant threat to the credit profile of the electric utility sector and the first major challenge to the otherwise monopolistic utility franchise”

Increasingly, utilities will have to develop business and regulatory models that provide a return on investment in demand-side energy infrastructure

Some utilities contemplate partial decoupling mechanisms or similar strategies; many jurisdictions have these in place

Sources: DSIREUSA; Institute for Electric Efficiency; FitchRatings; SNL Financial

0

10

20

30

40

50

60

70

9.0

9.5

10.0

10.5

11.0

11.5

12.0

12.5

Nu

mb

er

of

Rate

Cases S

ett

led

Retu

rn o

n E

qu

ity (

%)

Allowed ROEs

No. of Electric Rate Cases

Electric Rate Cases Settled

and Median Allowed Returns on Equity (by Year)

Amid the ongoing low interest rate environment, allowed returns on equity (ROE) continue to fall

In an effort to rein in rate awards, some commissions are requiring more frequent rate cases, while utilities continue to seek automatic adjustment mechanisms to combat regulatory lag

There is continuing divergence of transmission and other utility businesses with regard to regulatory construct and returns. Transmission ROEs generally remain in the 10%–12% range in many regions, formula rates remain commonplace, and FERC recently reaffirmed its transmission incentive ROE policy

On the horizon, further activity to recover increasing costs of system hardening, infrastructure upgrades, and pension and benefits

Alternative rate structures can impact allowed ROEs because of the perceived reduced revenue risk for the utility and complicated peer comparisons


Electric Transmission: Some Driving and Restraining Forces

5

Driving Forces Restraining Forces

FERC recently reaffirmed and clarified its incentive rate policy

Continues to provide solid returns (>12% ROE) when compared to distribution (~10%)

Aging infrastructure presents ongoing opportunities

Coal retirements are driving the need for new projects

Renewables driven both by economics (read production tax credit) and renewable portfolio standards will require interconnection

Load growth has slowed due to the recession and weak recovery

Energy efficiency and demand response continue to impact load growth and peak loads

Energy intensity is increasing

Distributed energy resources are proliferating in certain regions

Siting and lack of federal backstop authority slow development

Retail rate pressure continues, exacerbated by the weak economy

Recent challenges to ROEs (MA, MD, others…)

Complicating

Factors

Compliance filings suggest that elimination of the right of first refusal will require significantly more work; no clear path to new development by non-incumbents in many regions

Timing of implementation of EPA standards limiting coal will challenge transmission development; lack of clarity has cascading effects

Electric and gas convergence presents new contingencies in the planning process and reliability concerns in certain regions

Timelines for deployment of supply side alternatives are significantly shorter than for transmission (distributed energy resources, demand response, energy efficiency, gas-fired generation), further complicating planning

Sources: ScottMadden analysis


Gas-Power Interdependence: Implications of the “Dash to Gas”

6

For Power, Natural Gas Is Increasingly in Demand Divergence of Fates of Coal- and Gas-Fired Generation

Historic “Longitudinal” Flow Pattern Shifting to Today’s Developing “Grid” Flow Patterns

Sources: EIA, “Natural Gas Markets: Recent Changes and Key Drivers,” at LDC Gas Forum (Sept. 2012); Midwest ISO gas-power workshop (May 2012) www.midwestiso.org/Events/Pages/GE20120510.aspx; NERC gas-power interdependence report (released Dec. 2011) www.nerc.com/files/Gas_Electric_Interdependencies_Phase_I.pdf

More gas, less

coal: a story

evolves over past

several forecasts

Daily U.S. Natural Gas Burn for Power Generation:

2005–2011 vs. 2012 (through Sept.)

NERC-Wide Coal- and Gas-Fired Generation Outlook:

2008–2012 LTRA Reference Case Comparison

http://www.rightcolor.com/




Gas-Power Interdependence: Regional Differences Mean Different Concerns

7

Complicates solution

Facilitates solution

Southeast

Coal retirements; gas-fired replacements

Modest winter gas demand

Bilateral market; traditional cost-based

regulation of generation

Shale supply in adjacent regions

Midwest

Massive anticipated gas-fired replacements

High winter gas demand; large gas demand

centers

Bid-based market

Shale supply in adjacent regions

Problem identified and being worked

New England

End-of-the-(gas) line; history of gas issues

High winter gas demand; large gas demand

centers

Nearby sources declining

Constrained interfaces—gas and power

Bid-based market

LNG import capability

Problem identified and being worked

Depending upon variables such as existing

and anticipated gas resources and

infrastructure, volume and timing of coal-fired

power plant retirements and retrofits, market

structure, and a history of collaboration

among regional players, solutions to gas-

power interdependence complexities can be

facilitated or hampered.

Source: ScottMadden white paper, “Gas-Power Interdependence” (Jan. 2013), available at http://www.scottmadden.com/insight/598/GasPower-Interdependence.html



Gas-Power Interdependence: Regional Differences Mean Different Concerns (Cont’d)

8

Complicates solution

Facilitates solution

Desert Southwest

Heavy reliance upon gas-fired generation,

with more on horizon

California

Large intermittent resource build-out,

aggressive targets

Heavy reliance upon gas-fired generation

“Peaky,” low cap-factor gas needs for

renewable capacity backstop

Available gas supply in West

Generally more temperate

Large gas demand centers (SF, LA)

Bid-based market

Generator, gas transmission

communication taking place

Northwest/Mountain West

Large intermittent resource build-out

Significant hydro resources, but need to

distinguish capacity and energy needs

Significant coal-fired capacity; massive

retirements not expected immediately

Available Rockies, Canadian supply

Largely traditional (non-bid-based) market

Recent pipeline expansions

Working group established for Northwest

Source: ScottMadden white paper, “Gas-Power Interdependence” (Jan. 2013), available at http://www.scottmadden.com/insight/598/GasPower-Interdependence.html


Fossil Generation

Todd Williams

Partner

Todd Williams is a partner with ScottMadden and co-leads

the firm’s fossil practice. He has extensive experience

assisting large companies align their operations with their

strategic vision. From operational performance

improvement to organizational restructuring, Todd has

designed and implemented large scale initiatives to help his

clients succeed. He has experience working with

companies that need a turn around, are planning a merger

integration, or just want to drive performance improvement.

Todd combines extensive project management skills with a

large variety of previous engagements to bring creative

solutions to his clients.


Latest Outlook for Fossil Generation

Key Trends

Anticipated coal-fired plant retirements spurred by EPA regulations and persistent low natural gas prices continue to increase, however some owners will hold on (at least for a while) for various reasons: retrofit technology successes, performance of other plants, rate impacts, and reliability

For coal plant owners contemplating retrofits, the supply chain is increasingly cause for concern in regions such as the Midwest as EPA deadlines and large volumes of plants stress capability to complete refurbishment in a timely manner

Discussion Overview

2012 Election and Policy Developments

NERC’s Latest View

Coal Plant Retirement Risks

Supply Chain Issues for Retrofit and Replacement

10


The 2012 Election and Policy Shifts: Implications for the Power Generation Business

11

Area Current Views and Recent

Developments Implications

Power plant emissions regulation

For CSAPR, MATS, and other rules, cycle of

new proposed and final rules under statutory

deadlines forced by “citizens suits” plus cycle

of revisions driven by court challenges;

pundits are split on whether rule-making will

be more or less aggressive

Nomination of EPA Air chief McCarthy

Emissions markets likely “dead” for a while

with legal wrangling over regulations

Climate change and carbon regulation

Pres. Obama signals focus on climate

change in SOTU

New source GHG regulations for fossil-fired

power plants and refineries will be released,

but may be constrained (slightly) by

Congressional oversight

Split Congress likely limits comprehensive

GHG legislation

Obama and Reid comments on new focus on

climate creates some possibility of a carbon

tax in any budget “grand bargain” – a “sleeper”

issue

Possible expansion of GHG controls via

regulation of existing facilities

Production tax credits Extended through 2013 for renewable

facilities

Final dash to renewables construction in 2013?

Potential grants of relief in some states to near-term RPS deadlines


NERC’s Latest Long-Term Reliability Assessment: Some Good News and Some Cautionary Notes

12

2012 Key Reliability Findings

Significant

fossil-fired

generator

retirements

over the next

five years

NERC estimates nearly 71 GWs of retirements

by 2022, with 90% of that retiring by 2017

Estimates are highly uncertain, as generation

owners are still evaluating options and many

have not announced retirement decisions. Per

NERC, about 44 GWs of retirements are

confirmed based upon announcements and

resource plans

Next three or four years may see system

stability issues in some areas, need

transmission enhancements

Long-term

generator

maintenance

outages for

environmental

retrofits

Most controls are required by 2016 (MATS compliance), and NERC estimates that about 339 unit-level

retrofits covering 160 GWs will be required

NERC’s “unconfirmed” maintenance outages schedules still unknown, leaving less than 50 GWs (of the 160

GWs) confirmed, may result in generation capacity not being available during shoulder months and off‐peak

times during the operating day in the near term (2013–2016)

Increased

dependence

on natural gas

for electricity

generation

NERC estimates almost 100 GWs of planned and “conceptual” new capacity over the next 10 years will be

gas-fired

NERC continues to study impacts on operations and planning of this interdependence between gas and

power generation, especially:

—Availability of gas‐fired generation with neither firm transportation nor dual‐fuel capabilities, especially

during extreme cold weather

— Impact of significant gas supply or pipeline disruption

Source: NERC, 2012 Long-Term Reliability Assessment (Nov. 2012)

6.1

13.5 18.3

23.3

36.1 40.9 41.5 42.6 42.7 43.4 43.4 43.5

0

10

20

30

40

50

60

70

80

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Gig

aw

att

s

NERC‐Wide Cumulative Summer Fossil‐Fired Capacity Resource Retirements

UnconfirmedGasPetroleumCoal


NERC’s Latest Long-Term Reliability Assessment: Regional Variation in the Reliability Outlook

13

Reserve

Margins

Falling Below

NERC

Reference

Level by 2022

Expanding Concerns But Less Urgent

Longer-term, reserve margins begin to fall below reference levels in some other regions

These regions (except ERCOT) have at least five years to enhance capacity

“Conceptual resources”—generation in early stages of assessment—not considered for the reserve margin forecast, could be sufficient to aid regions including WECC, PJM, and Ontario, but their eventual construction is uncertain

Reserve

Margins

Falling Below

NERC

Reference

Level by 2014

Trouble in Texas

ERCOT’s Anticipated Reserve Margin below NERC Reference Margin Level in every year and is zero by 2020 unless more capacity is added

NERC fears that capacity deficiencies could trigger emergency operating procedures that may include the shedding of firm load

While acknowledging some progress, NERC “strongly recommends” the Texas PUC and ERCOT develop policies that bring capacity online in near and long term

Source: NERC, 2012 Long-Term Reliability Assessment (Nov. 2012)


Potential Coal Plant Retirements: The Latest Tally

14

Selected U.S. Coal Plant Retirement Forecasts: 30 GWs to 100 GWs between 2015 and 2020

Analyst Projected Retirements

Union of Concerned Scientists

59 GWs “ripe for retirement” in add’n to est. 41 GWs announced (100 GWs total)

Brattle 59–77 GWs

Sanford Bernstein 58 GWs by 2015

Bipartisan Policy Center 56 GWs by 2016

Friedman Billings Ramsay 50–55 GWs by 2018

Guggenheim Partners 50 GWs by 2015

ICF 50 GWs by 2015

EIA 49 GWs by 2020

Reuters/Factbox 35 GWs by 2015

Wood Mackenzie 30 GWs by 2015, add’l 45 GWs by 2025

Regulatory “tsunami”: With re-election of President Obama, the “tsunami” (no longer “train wreck”) of EPA regulations affecting power generation is now expected to be promulgated and implemented

Gas vs. coal: The story remains centered on the natural gas vs. coal price differential, as natural gas prices continue to remain low by historical standards. Meanwhile, coal mines have ramped back production in response to lower demand, and production costs are rising in response to increased mining regulation

Regional impacts: EIA projects that most retirements will be older, inefficient units concentrated in the Mid-Atlantic, Ohio River Valley, and Southeast, which have excess capacity. The Midwest ISO could be particularly affected by a large number of unit retirements

East vs. West: Generation using lower sulfur Powder River Basin (PRB) and Illinois coal is expected to fare better than Appalachian coal-fired plants. Coal producer Peabody Energy estimates that PRB is competitive with $2.50 to $2.75/MMBTU natural gas, while for Illinois it is $3.25 to $3.50 and $4.50 for Appalachian coal

“Unretirements” and temporary deferrals: Some utilities may reconsider retirement of selected coal plants for varied reasons

— Detroit Edison, e.g., told regulators that it planned to keep some (albeit large) units open that it had originally slated for closure as new controls technology works better than projected

— Otter Tail Power is delaying retirement of its Hoot Lake plant from 2015 to 2020 to reduce ratepayer impacts

— TVA has had to delay idling of five coal units because of unanticipated operating challenges at a large pumped storage plant

— At PJM’s request, First Energy delayed some unit retirements to 2015, pending upgrades, in order to provide voltage support

Announced Coal-Fired Plant Retirements as of Jan. 2013 (26 GWs through 2022)

Sources: Industry news; SNL Financial; ScottMadden analysis


Coal Generation By the Numbers

There are almost 1,000 coal units in US with a total nameplate capacity of 327.3 GW, representing 44% of total generation in 2011

611 units (151 GW) of those units do not have FGD or SCR installed and can be considered ‘at risk’ for compliance with the Utility MACT rule

15

0

100

200

300

400

500

600

700

800

900

1,000

Total Units FGD &SCR

Just FGD Just SCR Other NOxand SO2

Other NOxOnly

Other SO2Only

None(But

Planned)

None(No Plan)

No

. o

f O

pe

rati

ng

Un

its

U.S. Coal-Fired Power Generation and Air Quality Control System Status (No. of Units)

ERCOTFRCC

MRO

NPCC

ReliabilityFirst

SERC

SPP

WECC

Note: Reflects units large enough to be CEMS monitored (roughly greater than 25 MWs) and includes both utility and non-utility generation

Sources: Ventyx Energy Velocity Suite; ScottMadden analysis


Power Plant Replacement and Retrofit Supply Chain: Timing Is Everything

16

If Retrofit Decision on Coal Unit Has Not Been Made, Technology Options May Be Limited Given Compliance Timeframes

Selected Estimates of Retrofit Timing by Technology

MATS compliance deadline (if T0 = 1/1/13)

MATS compliance deadline + 12-month extension

(if T0 = 1/1/13)

ASI – Active Sorbent Injection DSI – Dry Sorbent Injection SCR – Selected Catalytic Reduction FGD – Flue Gas Desulfurization

-3%

-2%

-1%

0%

1%

2%

3%

4%

Com

bin

ed

-C

ycle

Con

str

uction

Sim

ple

-Cycle

Con

str

uction

Scru

bb

er

Con

str

uction

Con

str

uction

Ma

t'l &

Serv

ice

s

Lab

ore

rs

Con

str

uction

Lab

or

Em

issio

ns

Con

tro

lE

quip

me

nt

Bo

ilerm

ake

rs

Con

str

uction

Se

rvic

es

Co

st

Ch

an

ge (

YO

Y%

)

3Q 20123Q 2013

12-Month Trailing Index Cost Changes for Selected Facilities,

Categories, and Items (3Q 2012 and Projected 3Q 2013)

Sou

rce: Po

wer A

dvo

cate

Sou

rce: MISO

/Brattle

With EPA compliance deadlines (esp. MATS*) approaching, the power plant construction and maintenance supply chain will be stretched

Both significant new construction (replacement of retiring units) and retrofits will be occurring contemporaneously

Retrofit windows will be limited—shoulder months and perhaps some winter outages

Compliance is required by Q1 2015, with possible extensions into early 2016, leaving only about 24 to 36 months to complete

Per a MISO-commissioned study, the most single-year retrofits and new build of 89 GWs**, which it deems a “soft cap”

Available skilled labor supply may be stretched thin

A shortage of skilled labor persists, despite relatively high construction unemployment (11+% as of 3Q 2012)

This is manifesting itself in increased cost: craft labor is seeing a gradual, nationwide increase in wages and fringe benefits

Boilermakers in particular could be in short supply: MISO found that 10% of boilermakers are in utility construction, while retrofit/build workload will require about 30% of all boilermakers over the next several years

Contractor performance and liquidity should be monitored

Increased competition and aggressive bidding on projects has increased risk of liquidity and performance issues with general and sub-contractors

Rising materials costs exacerbate this risk

Notes: *Mercury and Air Toxics Standard; **normalized as wet FGD-equivalent MWs

Sources: Midwest ISO-The Brattle Group, “Supply Chain and Outage Analysis of MISO Coal

Retrofits for MATS” (May 2012); Power Advocate, Cost Intelligence Report for the

Energy Industry (Nov. 2012); EEI; EPA; Engineering News-Record; ScottMadden

analysis

Natural Gas

Ed Baker

Partner

Ed Baker is a partner with ScottMadden and leads the

firm's gas practice. He has been a consultant, and with

ScottMadden, since 2001. Recent projects have been in

performance improvement, process standardization,

organization design and staffing, and business planning.


Latest Outlook for Natural Gas

Key Trends

Natural gas prices remain low by historical standards, with ample supply and relatively mild winter demand

Shale gas continues to be the major part of this U.S. energy story, but there are risks to low gas prices (significantly increased demand, greater and multiple levels of regulation, pricing uncertainty/miscalculations)

Discussion Overview

Price Predictions

Shale Gas

The United States as the “Saudi Arabia of Natural Gas”

New Pipeline Capacity Needs

18


Natural Gas Price Predictions Have Been Difficult and Often Unreliable

Gas Prices Remain Depressed

Natural gas prices are not projected to return to pre-recession levels in the near to intermediate term

Through 2014, EIA expects prices will gradually rise but still remain relatively low. EIA expects the Henry Hub price will average $3.41 per MMBtu in 2013 (compared to $2.75 per MMBtu in 2012) and $3.63 per MMBtu in 2014

Some contrarians, however, posit $6/MMBTU natural gas by 2015

Demand May Pull up Prices, but Supply Response and Impact of Worldwide Demand Create Uncertainty

Industrial gas demand: growth is due to the bolster of petrochemical plants and production by the energy-hungry metals

Short-term gas demand from power generation is projected to increase, but that demand growth levels off longer term (~10 years)

More Canadian gas may go to Asia as LNG export facilities in western Canada emerge to take Canadian gas traditionally exported to the United States—now displaced by shale gas

Some big question marks: the impact of production efficiencies, drilling inventory, and gas demand response

19

Notes: *2005 forecast is in $/MCF and is an average wellhead price, not a Henry Hub average

price.

**Natural Gas Week (Aug. 6, 2012 and Nov. 12, 2012).

Sources: Industry news; EIA; IEA; FERC; SNL Financial; Natural Gas Week

$8.94

$4.00

$4.39

$3.94

$3.60

$4.11 $4.16 $4.27 $4.30 $4.42 $4.59

$4.72 $4.80

$0

$2

$4

$6

$8

$10

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Pri

ce

in

$/M

MB

TU

2009 Forecast

2007 Forecast

2011 Forecast

2005 Forecast

Jan. 2012 Forecast

Despite the apparent smooth trajectory, gas price volatility may

remain, driven by pipeline constraints, increased gas consumption for

power generation, and changing basis relationships.

Selected 2013 Gas Price Forecasts ($/MMBTU) JP Morgan $4.25 Morgan Stanley 3.95 NGW** Scorecard Avg. 3.93 UBS, RBC, Raymond James 3.75 Moody’s ≥3.00

Latest EIA

forecast:

$3.41

EIA Actual and Projected Henry Hub Average Spot Price and Selected Forecasts ($/MMBTU*) (in 2010$)

2012 Actual:

$2.75


Shale Gas, Especially Marcellus, Continues to Have Competitive Breakeven Costs

Shale Gas Economics Remain Favorable

Shale play economics have been resilient, even with abundant supply and “rock-bottom” prices

Natural gas liquids (NGLs) continue to buoy economics of “wet” plays like Marcellus and Barnett

Some supply response emerging (e.g., Chesapeake pull-back)?

Utica—The Next Big Shale Play?

Utica Shale, a 170,000 square mile formation deeper than the Marcellus, is seen by some as the next major shale play

ExxonMobil, Chesapeake, Hess, and others are making significant investments in leases, largely in Ohio

Little production to date, so Utica’s productivity is uncertain

20

Sources: Range Resources Company Presentation (Oct. 2011) (citing Goldman Sachs);

*Carol Freedenthal, Jofree Consulting, quoted in Natural Gas Week (Oct. 31,

2011); El Paso Midstream; Kinder Morgan; Enterprise Products Partners;

PennEnergy; Reuters: SNL Financial (historical gas strip prices)

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$/M

CF

Henry Hub Futures 2013 Strip High (1/1/11–12/31/12)

Henry Hub Futures 2013 Strip Low (1/1/11–12/31/12)

Sou

rces

: Ran

ge R

eso

urc

es (

citi

ng

Go

ldm

an S

ach

s)

“Natural gas is going to enter a golden age we

haven't seen since the 1950s.”

Bob Best

Executive Chairman, Atmos Energy

NYMEX Price Required for 12% IRR for Selected Shale Plays ($/MCF)


Shale Gas: Risks to Bullish View

Production curves (output yield from fields and wells) vary within and across various shale plays

— Some skeptics point to rapid decline rates

— No “one-size-fits-all” assessment of shale play productivity; assessments still evolving

Reserves and ultimate supply are smaller than technically recoverable resources—a key question is how much at what price

Externalities—and responses thereto—could play a role in slowing development

— Stringent EPA regulation or local opposition, such as New York’s ban on fracking, could make availability of the shale resource moot

Economics are brutal in the current environment

— Series of write-downs on North American shale stakes by BHP Billiton ($2.84B), BP ($2.1B), BG ($1.3B), and others as “land rush” meets $3 natural gas prices

— While current gas prices offer breakeven for some wet plays, most dry gas is not in the money at $3

Water consumption remains a concern in some areas

— Water usage rates in recently drought-prone areas like Texas are emerging as a point of concern

— Industry proponents, however, point to the large percentage of water consumed by municipalities and irrigation

21

Barnett

Eagle Ford

Haynesville

Marcellus

Niobrara

250

125

600

85

300

Average Freshwater Use per Shale Well (000s of Gallons)

4,600

5,000

5,000

5,600

3,000

Drilling Hydraulic Fracturing

Source: GAO

Notes: *Based upon paper for Society of Petroleum Engineers and assuming EURs

as of 2009

**Monthly futures prices as of Oct. 23, 2012

Sources: The American Oil & Gas Reporter (May 2011); World Oil (July 2012); UBS

Investment Research, “NYT Shale Gas Allegations Seem Exaggerated” (June

27, 2011); industry publications


Bulls and Bears Views on United States as the “Saudi Arabia of Natural Gas”

22

The Bullish View

European gas production is dropping—the U.K., for example, has become a net importer of LNG

Spain’s gas is 80% LNG

Japan’s possible dismantling of its nuclear sector will put pressure on gas supply, already seen in its landed LNG prices; perhaps a similar situation emerging in Germany

Europe is highly dependent upon Russia, which has used resources as geopolitical levers, for gas supply

Several U.S. LNG facilities are considering reversing trains for export, with Sabine Pass (LA) fully approved

Potential U.S. LNG will make global LNG supply curve more elastic, limiting long-term increases in price

The Bearish View

Soft economic could contain gas demand growth, and Asian demand is uncertain

Somewhere from 60%+ of European gas needs locked in with long-term contracts of unknown duration

Hard to develop LNG export capacity quickly, and it will require long-term contracts with anchor tenants to justify investment

Plenty of competition: Canada, Qatar, Australia, and others now; possible rich shale resources in China, Russia, and Africa; Russia, as swing producer, could be a spoiler

Potential for political impediments at home to gas exports

Price relationships and influenced by currency exchange rate, which could change with different policy

$0

$2

$4

$6

$8

$10

$12

$14

Gulf toJapan

JCCForward

Gulf toU.K.

NBPForward

$/M

CF

All-In U.S. LNG Cost at Gulf (Illustrative) vs. Japan and U.K. LNG Hub Prices

Regas Tariff

Panama Canal

Boiloff

Fuel

Vessel Charter

15% + $2.25

Henry Hub - Jan 2015

Japan U.K.

Source: B. Schlesinger & Assocs. (citing Deutsche Bank)

Source: K. Medlock (Rice U.)

Henry Hub NBP JKM LNG-Crude Index

Notes: NBP is National Balancing Point (U.K.); JCC is Japan Customs-Cleared Crude; JKM is

Japan/Korea Marker. All are market hubs used for LNG pricing.

Sources: EIA International Natural Gas Workshop (Aug. 13, 2012), presentations by Brattle

Group; Benjamin Schlesinger and Associates, Kenneth Medlock (Rice Univ.), Howard

Rogers (Oxford Institute for Energy Studies)

Selected International LNG Price Trends

(Various Locations)


For New Natural Gas Resources, A Need for New Pipeline Capacity

New Pipelines Needed; NGLs Are Current Focus

Pipeline expansion proposals: Marcellus and other shale plays

Some liquids-focused pipelines moving NGLs to the upper Midwest and Canada or Gulf Coast

Expansion of dry natural gas pipelines to East Coast urban centers could be contentious: ROW negotiations, new battleground for fracking opponents

Additional Capacity, Basis Changes?

Approximately 6 BCF/day in new gas pipeline capacity proposed for Marcellus

With new pipeline capacity from shale gas resources to markets, basis relationships may change

Falling premiums: NY, New England vs. market centers like Henry Hub

But increased gas-fired generation along with winter heating demand may continue to constrain pipeline capacity, leading to volatile winter gas prices

23

Sources: EIA; FERC; Morgan Stanley; Credit Suisse; SNL Financial;

ScottMadden analysis

Pipeline Capacity from Selected Basins to

Selected Demand Centers as of Sept. 2008 (BCF/Day)

Questions and Answers

Greg Litra

Partner and Energy, Clean Tech, and

Sustainability Research Leader

Greg Litra joined the firm in 1995 after practicing corporate

law for several years. He specializes in the energy and

utilities business sectors, supporting consulting

engagements in the areas of strategy development, market

assessment, energy regulation, and industry trend analysis.

Additionally, Greg leads the firm’s energy and clean tech

research activities, and he spearheads the publication of

ScottMadden’s semi-annual Energy Industry Update.


Contact Us

25

Cristin Lyons Partner

ScottMadden, Inc.

2626 Glenwood Ave

Suite 480

Raleigh, NC 27608

Phone: 919-781-4191

[email protected]

Todd Williams Partner

ScottMadden, Inc.

3495 Piedmont Rd, Bldg 10

Suite 805

Atlanta, GA 30305

Phone: 404-814-0020

[email protected]

Ed Baker Partner

ScottMadden, Inc.

3495 Piedmont Rd, Bldg 10

Suite 805

Atlanta, GA 30305

Phone: 404-814-0020

[email protected]

Stu Pearman Partner and

Energy Practice Leader

ScottMadden, Inc.

2626 Glenwood Ave

Suite 480

Raleigh, NC 27608

Phone: 919-781-4191

[email protected]

Greg Litra Partner

ScottMadden, Inc.

2626 Glenwood Ave

Suite 480

Raleigh, NC 27608

Phone: 919-781-4191

[email protected]

See the link below for the Winter 2012–2013 Energy Industry Update

http://www.scottmadden.com/insight/605/The-Energy-Industry-Update.html

mailto:[email protected]












Documents

The State of the Energy Industry