Copyright © 2013 by ScottMadden. All rights reserved.
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
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.
Copyright © 2013 by ScottMadden. All rights reserved.
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
Copyright © 2013 by ScottMadden. All rights reserved.
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
Copyright © 2013 by ScottMadden. All rights reserved.
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
Copyright © 2013 by ScottMadden. All rights reserved.
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
Copyright © 2013 by ScottMadden. All rights reserved.
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
Copyright © 2013 by ScottMadden. All rights reserved.
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.
Copyright © 2013 by ScottMadden. All rights reserved.
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
Copyright © 2013 by ScottMadden. All rights reserved.
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
Copyright © 2013 by ScottMadden. All rights reserved.
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
Copyright © 2013 by ScottMadden. All rights reserved.
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)
Copyright © 2013 by ScottMadden. All rights reserved.
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
Copyright © 2013 by ScottMadden. All rights reserved.
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
Copyright © 2013 by ScottMadden. All rights reserved.
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.
Copyright © 2013 by ScottMadden. All rights reserved.
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
Copyright © 2013 by ScottMadden. All rights reserved.
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
Copyright © 2013 by ScottMadden. All rights reserved.
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)
Copyright © 2013 by ScottMadden. All rights reserved.
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
Copyright © 2013 by ScottMadden. All rights reserved.
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)
Copyright © 2013 by ScottMadden. All rights reserved.
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
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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.
Copyright © 2013 by ScottMadden. All rights reserved.
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Cristin Lyons Partner
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Greg Litra Partner
ScottMadden, Inc.
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Suite 480
Raleigh, NC 27608
Phone: 919-781-4191
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http://www.scottmadden.com/insight/605/The-Energy-Industry-Update.html