The State of the Energy Industry

The State of the Energy Industry

ScottMadden-Energy Central Webcast

March 27, 2013

Copyright © 2013 by ScottMadden. All rights reserved.

Today’s Agenda and Your Presenters
Welcome and Introduction Fossil Generation
 2012 Election and Policy Developments
 NERC’s Latest View
 Coal Plant Retirement Risks
 Supply Chain Issues for Retrofit and
Replacement
Stu Pearman Todd Williams
Partner and Energy Practice Partner and Fossil
Leader Generation Practice Leader

Energy Infrastructure Natural Gas
 Efficiency, Demand, and Rate  Price Predictions
Regulation
 Shale Gas
 Electric Transmission
 The United States as the “Saudi Arabia
 Gas-Power Interdependence of Natural Gas”
 New Pipeline Capacity Needs
Cristin Lyons Ed Baker
Partner and Transmission, Partner and Natural Gas
Distribution, and Smart Grid Practice Leader
Practice Leader

Questions and Answers

Greg Litra
Partner and Energy, Clean
Tech, and Sustainability
Research Leader
1

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

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?
Lost Revenue Adjustment and Revenue Decoupling Mechanisms Electric Rate Cases Settled
for Electric Utilities (as of July 2012) and Median Allowed Returns on Equity (by Year)
12.5 70

Number of Rate Cases Settled
12.0 60

Return on Equity (%)
11.5 50

11.0 40

10.5 30

10.0 20

9.5 Allowed ROEs 10
No. of Electric Rate Cases
9.0 0
Revenue Decoupling Mechanism (Elec. Utils.)
Lost Revenue Adjustment Mechanism (Elec. Utils.)
Pending

 Even without direct mandates like energy efficiency resource  Amid the ongoing low interest rate environment, allowed returns
standards, indirect effects from federal mandates, building on equity (ROE) continue to fall
codes, and improved materials and technologies, continue to  In an effort to rein in rate awards, some commissions are
reduce energy intensity requiring more frequent rate cases, while utilities continue to seek
 Fitch considers energy efficiency “a significant threat to the automatic adjustment mechanisms to combat regulatory lag
credit profile of the electric utility sector and the first major  There is continuing divergence of transmission and other utility
challenge to the otherwise monopolistic utility franchise” businesses with regard to regulatory construct and returns.
Transmission ROEs generally remain in the 10%–12% range in
 Increasingly, utilities will have to develop business and many regions, formula rates remain commonplace, and FERC
regulatory models that provide a return on investment in recently reaffirmed its transmission incentive ROE policy
demand-side energy infrastructure
 On the horizon, further activity to recover increasing costs of
 Some utilities contemplate partial decoupling mechanisms or system hardening, infrastructure upgrades, and pension and
similar strategies; many jurisdictions have these in place benefits
 Alternative rate structures can impact allowed ROEs because of
the perceived reduced revenue risk for the utility and complicated
peer comparisons
Sources: DSIREUSA; Institute for Electric Efficiency; FitchRatings; SNL Financial
4

Electric Transmission:
Some Driving and Restraining Forces
Driving Forces Restraining Forces

 FERC recently reaffirmed and clarified its  Load growth has slowed due to the
incentive rate policy recession and weak recovery
 Continues to provide solid returns (>12%  Energy efficiency and demand response
ROE) when compared to distribution continue to impact load growth and peak
(~10%) loads
 Aging infrastructure presents ongoing  Energy intensity is increasing
opportunities
 Distributed energy resources are
 Coal retirements are driving the need for proliferating in certain regions
new projects
 Siting and lack of federal backstop
 Renewables driven both by economics authority slow development
(read production tax credit) and renewable
portfolio standards will require  Retail rate pressure continues,
interconnection exacerbated by the weak economy
Complicating  Recent challenges to ROEs (MA, MD,
Factors others…)

 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

5

Gas-Power Interdependence:
Implications of the “Dash to Gas”
Divergence of Fates of Coal- and Gas-Fired Generation For Power, Natural Gas Is Increasingly in Demand
NERC-Wide Coal- and Gas-Fired Generation Outlook: Daily U.S. Natural Gas Burn for Power Generation:
2008–2012 LTRA Reference Case Comparison 2005–2011 vs. 2012 (through Sept.)

More gas, less
coal: a story
evolves over past
several forecasts

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)
Copyright © 2013 by ScottMadden. All rights reserved. www.midwestiso.org/Events/Pages/GE20120510.aspx;
6 NERC gas-power interdependence report (released Dec. 2011)
www.nerc.com/files/Gas_Electric_Interdependencies_Phase_I.pdf

Regional Differences Mean Different Concerns

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

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

Depending upon variables such as existing
Southeast
and anticipated gas resources and
 Coal retirements; gas-fired replacements infrastructure, volume and timing of coal-fired
 Modest winter gas demand power plant retirements and retrofits, market
 Complicates solution  Bilateral market; traditional cost-based structure, and a history of collaboration
 Facilitates solution regulation of generation among regional players, solutions to gas-
 Shale supply in adjacent regions 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
7

Regional Differences Mean Different Concerns (Cont’d)
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

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  Complicates solution
 Generally more temperate  Facilitates solution
 Large gas demand centers (SF, LA)
 Bid-based market Desert Southwest
 Generator, gas transmission  Heavy reliance upon gas-fired generation,
communication taking place with more on horizon

Source: ScottMadden white paper, “Gas-Power Interdependence” (Jan. 2013), available at
http://www.scottmadden.com/insight/598/GasPower-Interdependence.html
8

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.

Fossil Generation

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

Current Views and Recent
Area Implications
Developments
Power plant emissions  For CSAPR, MATS, and other rules, cycle of  Emissions markets likely “dead” for a while
regulation new proposed and final rules under statutory with legal wrangling over regulations
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
Climate change and  Pres. Obama signals focus on climate  Split Congress likely limits comprehensive
carbon regulation change in SOTU GHG legislation
 New source GHG regulations for fossil-fired  Obama and Reid comments on new focus on
power plants and refineries will be released, climate creates some possibility of a carbon
but may be constrained (slightly) by tax in any budget “grand bargain” – a “sleeper”
Congressional oversight issue
 Possible expansion of GHG controls via
regulation of existing facilities
Production tax credits  Extended through 2013 for renewable  Final dash to renewables construction in
facilities 2013?
 Potential grants of relief in some states to
near-term RPS deadlines

11

NERC’s Latest Long-Term Reliability Assessment:
Some Good News and Some Cautionary Notes
2012 Key Reliability Findings
 Significant  NERC estimates nearly 71 GWs of retirements NERC‐Wide Cumulative Summer Fossil‐Fired
fossil-fired by 2022, with 90% of that retiring by 2017 Capacity Resource Retirements
generator  Estimates are highly uncertain, as generation 80 Unconfirmed
retirements owners are still evaluating options and many 70 Gas
Petroleum
over the next have not announced retirement decisions. Per 60 Coal

Gigawatts
five years NERC, about 44 GWs of retirements are 50 40.9 41.5 42.6 42.7 43.4 43.4 43.5
confirmed based upon announcements and 40
36.1

resource plans 30 23.3
18.3
 Next three or four years may see system 20 13.5
stability issues in some areas, need 10
6.1
transmission enhancements 0
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

 Long-term  Most controls are required by 2016 (MATS compliance), and NERC estimates that about 339 unit-level
generator retrofits covering 160 GWs will be required
maintenance  NERC’s “unconfirmed” maintenance outages schedules still unknown, leaving less than 50 GWs (of the 160
outages for GWs) confirmed, may result in generation capacity not being available during shoulder months and off‐peak
environmental times during the operating day in the near term (2013–2016)
retrofits

Increased  NERC estimates almost 100 GWs of planned and “conceptual” new capacity over the next 10 years will be
dependence gas-fired
on natural gas  NERC continues to study impacts on operations and planning of this interdependence between gas and
for electricity power generation, especially:
generation —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)

12

NERC’s Latest Long-Term Reliability Assessment:
Regional Variation in the Reliability Outlook
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
Reserve
Margins  While acknowledging some progress, NERC
Falling Below “strongly recommends” the Texas PUC and
NERC ERCOT develop policies that bring capacity
Reference online in near and long term
Level by 2014

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 Reserve
considered for the reserve margin Margins
forecast, could be sufficient to aid regions Falling Below
including WECC, PJM, and Ontario, but NERC
their eventual construction is uncertain Reference
Level by 2022

Source: NERC, 2012 Long-Term Reliability Assessment (Nov. 2012)
13

Potential Coal Plant Retirements: The Latest Tally
Selected U.S. Coal Plant Retirement Forecasts: Announced Coal-Fired Plant Retirements
30 GWs to 100 GWs between 2015 and 2020 as of Jan. 2013 (26 GWs through 2022)
Analyst Projected Retirements
Union of Concerned 59 GWs “ripe for retirement” in add’n to est.
Scientists 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
Sources: Industry news; SNL Financial; ScottMadden analysis
14

Coal Generation By the Numbers
U.S. Coal-Fired Power Generation and
Air Quality Control System Status (No. of Units)
1,000 FRCC
WECC ERCOT
900

800 SPP MRO
NPCC
No. of Operating Units

700

600
Reliability
500 First
SERC
400

300

200

100

0
Total Units FGD & Just FGD Just SCR Other NOx Other NOx Other SO2 None None
SCR and SO2 Only Only (But (No Plan)
Planned)
 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

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
15

Power Plant Replacement and Retrofit Supply Chain:
Timing Is Everything
If Retrofit Decision on Coal Unit Has Not Been Made, With EPA compliance deadlines (esp. MATS*) approaching,
Technology Options May Be Limited Given Compliance Timeframes the power plant construction and maintenance supply chain
will be stretched
Selected Estimates of Retrofit Timing by Technology
 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
ASI – Active Sorbent Injection  Per a MISO-commissioned study, the most single-year
DSI – Dry Sorbent Injection
SCR – Selected Catalytic Reduction
retrofits and new build of 89 GWs**, which it deems a “soft
FGD – Flue Gas Desulfurization cap”

Available skilled labor supply may be stretched thin
 A shortage of skilled labor persists, despite relatively high

Source: MISO/Brattle
construction unemployment (11+% as of 3Q 2012)
MATS compliance deadline MATS compliance deadline
 This is manifesting itself in increased cost: craft labor is
(if T0 = 1/1/13) + 12-month extension seeing a gradual, nationwide increase in wages and fringe
(if T0 = 1/1/13) benefits
 Boilermakers in particular could be in short supply: MISO
12-Month Trailing Index Cost Changes for Selected Facilities, found that 10% of boilermakers are in utility construction,
Categories, and Items (3Q 2012 and Projected 3Q 2013) while retrofit/build workload will require about 30% of all
4% boilermakers over the next several years
3Q 2012
Cost Change (YOY%)

3% 3Q 2013
Contractor performance and liquidity should be monitored
2%  Increased competition and aggressive bidding on projects
1% has increased risk of liquidity and performance issues with
Source: Power Advocate

general and sub-contractors
0%
 Rising materials costs exacerbate this risk
Equipment
Mat'l & Services
Simple-Cycle
Construction

Construction

Construction

Boilermakers

Construction
Laborers

Emissions
Construction
Combined-

Construction

Control
Scrubber

-1%
Services
Labor
Cycle

-2% 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
-3% Retrofits for MATS” (May 2012); Power Advocate, Cost Intelligence Report for the
Energy Industry (Nov. 2012); EEI; EPA; Engineering News-Record; ScottMadden
analysis

16

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.

Natural Gas

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
EIA Actual and Projected Henry Hub Average Spot Price and Selected
Gas Prices Remain Depressed Forecasts ($/MMBTU*) (in 2010$)
 Natural gas prices are not projected to return to pre- $10
recession levels in the near to intermediate term 2009 Forecast
$8.94
 Through 2014, EIA expects prices will gradually rise but 2007 Forecast
still remain relatively low. EIA expects the Henry Hub $8
2011 Forecast
price will average $3.41 per MMBtu in 2013 (compared to
$2.75 per MMBtu in 2012) and $3.63 per MMBtu in 2014 2005 Forecast

Price in $/MMBTU
 Some contrarians, however, posit $6/MMBTU natural gas $6 Jan. 2012 Forecast
by 2015

Demand May Pull up Prices, but Supply Response and $4.80
$4.59 $4.72
Impact of Worldwide Demand Create Uncertainty $4 $4.39 $4.27 $4.30
$4.42
$4.00 $4.11 $4.16
$3.94
Selected 2013 Gas Price Forecasts ($/MMBTU)
 Industrial gas demand: growth is due to the bolster of $3.60
JP Morgan $4.25
2012 Actual:
petrochemical plants and production by the energy- Morgan Stanley 3.95
$2 $2.75
hungry metals NGW** Scorecard Avg. 3.93
Latest EIA UBS, RBC, Raymond James 3.75
 Short-term gas demand from power generation is forecast: Moody’s ≥3.00
projected to increase, but that demand growth levels off $3.41
longer term (~10 years) $0
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

 More Canadian gas may go to Asia as LNG export
facilities in western Canada emerge to take Canadian Despite the apparent smooth trajectory, gas price volatility may
gas traditionally exported to the United States—now remain, driven by pipeline constraints, increased gas consumption for
displaced by shale gas power generation, and changing basis relationships.
 Some big question marks: the impact of production
efficiencies, drilling inventory, and gas demand response
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

19

Shale Gas, Especially Marcellus,
Continues to Have Competitive Breakeven Costs
NYMEX Price Required for 12% IRR for Selected Shale Plays ($/MCF)
Shale Gas Economics Remain Favorable
$7.00  Shale play economics have been resilient,
even with abundant supply and “rock-bottom”
$6.00 prices

Sources: Range Resources (citing Goldman Sachs)
$5.00  Natural gas liquids (NGLs) continue to buoy
economics of “wet” plays like Marcellus and
$4.00 Barnett
$/MCF

$3.00  Some supply response emerging
(e.g., Chesapeake pull-back)?
$2.00
Utica—The Next Big Shale Play?
$1.00
 Utica Shale, a 170,000 square mile formation
$0.00 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

Henry Hub Futures 2013 Strip High (1/1/11–12/31/12)
“Natural gas is going to enter a golden age we
Henry Hub Futures 2013 Strip Low (1/1/11–12/31/12)
haven't seen since the 1950s.”
Bob Best
Sources: Range Resources Company Presentation (Oct. 2011) (citing Goldman Sachs); Executive Chairman, Atmos Energy
*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)
20

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 Average Freshwater Use per Shale Well (000s of Gallons)
stakes by BHP Billiton ($2.84B), BP ($2.1B),
BG ($1.3B), and others as “land rush” meets Drilling Hydraulic Fracturing
$3 natural gas prices
Barnett 4,600
250
— While current gas prices offer breakeven for
some wet plays, most dry gas is not in the Eagle Ford 5,000
125
money at $3
Haynesville 600 5,000
 Water consumption remains a concern in some areas
— Water usage rates in recently drought-prone Marcellus 85 5,600
areas like Texas are emerging as a point of
concern Niobrara 300 3,000

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

21

Bulls and Bears Views on United States as the
“Saudi Arabia of Natural Gas”
The Bullish View The Bearish View
 European gas production is dropping—the U.K., for example,  Soft economic could contain gas demand growth, and Asian
has become a net importer of LNG demand is uncertain
 Spain’s gas is 80% LNG  Somewhere from 60%+ of European gas needs locked in with
long-term contracts of unknown duration
 Japan’s possible dismantling of its nuclear sector will put
pressure on gas supply, already seen in its landed LNG prices;  Hard to develop LNG export capacity quickly, and it will require
perhaps a similar situation emerging in Germany long-term contracts with anchor tenants to justify investment
 Europe is highly dependent upon Russia, which has used  Plenty of competition: Canada, Qatar, Australia, and others
resources as geopolitical levers, for gas supply now; possible rich shale resources in China, Russia, and
Africa; Russia, as swing producer, could be a spoiler
 Several U.S. LNG facilities are considering reversing trains for
export, with Sabine Pass (LA) fully approved  Potential for political impediments at home to gas exports
 Potential U.S. LNG will make global LNG supply curve more  Price relationships and influenced by currency exchange rate,
elastic, limiting long-term increases in price which could change with different policy

All-In U.S. LNG Cost at Gulf (Illustrative) Selected International LNG Price Trends
vs. Japan and U.K. LNG Hub Prices (Various Locations)
$14 Source: K. Medlock (Rice U.)
Japan U.K.
$12
Regas Tariff
$10
Panama Canal
$/MCF

$8
Boiloff
$6 Fuel
$4 Vessel Charter

$2 15% + $2.25
Henry Hub - Jan 2015
$0
Gulf to JCC Gulf to NBP
Japan Forward U.K. Forward Henry Hub NBP JKM LNG-Crude Index

Source: B. Schlesinger & Assocs. (citing Deutsche Bank) 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.
Copyright © 2013 by ScottMadden. All rights reserved. Sources: EIA International Natural Gas Workshop (Aug. 13, 2012), presentations by Brattle
22 Group; Benjamin Schlesinger and Associates, Kenneth Medlock (Rice Univ.), Howard
Rogers (Oxford Institute for Energy Studies)

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 Pipeline Capacity from Selected Basins to
Selected Demand Centers as of Sept. 2008 (BCF/Day)
 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

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

23

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.

Questions and Answers

Contact Us

Cristin Lyons ScottMadden, Inc. Todd Williams ScottMadden, Inc. Ed Baker ScottMadden, Inc.
Partner 2626 Glenwood Ave Partner 3495 Piedmont Rd, Bldg 10 Partner 3495 Piedmont Rd, Bldg 10
Suite 480 Suite 805 Suite 805
Raleigh, NC 27608 Atlanta, GA 30305 Atlanta, GA 30305

Phone: 919-781-4191 Phone: 404-814-0020 Phone: 404-814-0020
cmlyons@scottmadden.com toddwilliams@scottmadden.com edbaker@scottmadden.com

Greg Litra ScottMadden, Inc. Stu Pearman ScottMadden, Inc.
Partner 2626 Glenwood Ave Partner and 2626 Glenwood Ave
Energy Practice Leader
Suite 480 Suite 480
Raleigh, NC 27608 Raleigh, NC 27608

Phone: 919-781-4191 Phone: 919-781-4191
glitra@scottmadden.com spearman@scottmadden.com

See the link below for the Winter 2012–2013 Energy Industry Update
http://www.scottmadden.com/insight/605/The-Energy-Industry-Update.html

25

The State of the Energy Industry

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