Todd Williams, partner at ScottMadden, recently presented “Generation Trends – What Are the Impacts on Transmission?” at the fourth annual Transmission Summit West. This presentation focused on how natural gas prices, carbon legislation, and renewable generation sources will drive the need for transmission infrastructure investment.

1. Copyright © 2012 by ScottMadden. All rights reserved.
Generation Trends –
What Are the Impacts on Transmission?
Infocast Transmission Summit West 2012
October 23, 2012
Todd Williams
Partner
Atlanta

2. Copyright © 2012 by ScottMadden. All rights reserved.
Witches Brew…Or Love Potion #9
1

3. Copyright © 2012 by ScottMadden. All rights reserved.
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5
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25
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Sep-2004
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Nov-2006
Dec-2007
Jan-2009
Feb-2010
Mar-2011
Apr-2012
$/MMBTU(2012$)
▪ Fuel Use Act
(restrict plants
using gas or oil
as primary
fuels)
Trend 1 – Gas
U.S. Natural Gas Real Spot Prices (Henry Hub) –
A History of Price Volatility
2
Regulated Era Transition Era Deregulated Era
$0
$5
$10
$15
$20
$25
$30
$/MMBTU(2012$)
Sources: World Bank Commodity Price Data, adjusted by CPI to 2012 dollars; NERC; naturalgas.org
▪ Natural Gas
Policy Act
(begins
wellhead
price dereg.)
▪ Winter of 76–77
▪ Order 380 (elim. min. bills
for LDC – “take-or-pay”)
▪ Order 436/500 (transport
service to all customers)
▪ Order 636
(gas pipeline
unbundling)
▪ Decontrol of
NGPA prices
begins
▪ Natural Gas
Wellhead
Decontrol Act
▪ Natural Gas Clearinghouse
formed
▪ HL&P Bidding
Program
▪ NYMEX futures
contract
established
▪ Order 637 (differentiated
pipeline rate structures)
▪ Order 698 (NAESB
stds. – pipeline/
generator comm.)
▪ Order 720
(pipeline
posting
requirements)
▪ Arab Oil
Embargo
▪ PURPA
▪ First retail gas
choice program

4. Copyright © 2012 by ScottMadden. All rights reserved.
Trend 1 – Gas
Natural Gas Prices – Kinda Hard to Predict
Gas Prices Remain Depressed
◆ Natural gas prices are not projected to return to pre-
recession levels in the near to intermediate term
◆ U.S. government forecasts (shown right) reflect steady
2%+ per year growth
◆ 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: Slow increase in the medium
term, tempered by the sluggish U.S. economy
◆ 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 Notes: *2005 forecast is in $/MCF and is an average wellhead price,
not a Henry Hub average price.
**Natural Gas Week (Aug. 6, 2011).
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
$10
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Pricein$/MMBTU
2009 Forecast
2007 Forecast
2011 Forecast
2005 Forecast
Jan. 2012 Forecast
Actual EIA Projected
EIA Actual and Projected Henry Hub Average Spot Price
and Selected Forecasts ($/MMBTU*) (in 2010$)
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
UBS, RBC 3.75
NGW** Scorecard Avg. 3.66
Raymond James 3.25
Moody’s ≥3.00
3
Latest EIA
forecast:
$3.12

5. Copyright © 2012 by ScottMadden. All rights reserved.
Trend 1 – Gas
Breakeven Costs Suggest Future Volatility Is Possible...
4
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)
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
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$/MCF
Henry Hub Futures 2012 Strip High (1/1/10–12/31/11)
Henry Hub Futures 2012 Strip Low (1/1/10–12/31/11)
NYMEX Price Required for 12% IRR
for Selected Shale Plays ($/MCF)
Sources:RangeResources(citingGoldmanSachs)
“Natural gas is going to enter a golden age we haven't seen
since the 1950s.”
Bob Best, Executive Chairman, Atmos Energy

6. Copyright © 2012 by ScottMadden. All rights reserved.
Trend 1 – Gas
…And the Predicted Supply
Response May Be Taking Place
5
Drilling Pullback Started with Sub-$3 Gas
◆ Some producers are pulling back dry gas production
◆ Gas rigs are being repurposed for oil production
◆ Some recent announcements:
— Chesapeake: “Bare minimum” levels
— Conoco: Shutting in 100 MMcf/day
— EQT: Suspends gas drilling indefinitely in
Huron, coalbed methane plays in App. Basin
— Quicksilver: Focusing on oil, liquids projects
— Noble: Low price “circuit-breaker” tripped;
suspending dry gas production in Marcellus
until $4/MMBTU gas for three consecutive
months
◆ Others are continuing, or at least remaining mum
◆ Curtailment or supply response?
LNG Safety Valve?
◆ Landed LNG in European hubs exceeds $11/MMBTU,
Japan exceeds $17/MMBTU
◆ With transport and regas ~$2/MMBTU, prolonged low
($3) domestic gas prices could energize a U.S. LNG
export market
◆ Varied opinions
Lag effect: As recently as mid-February, domestic
production was up from last year (nearly 20%) but trending
downward as Canadian imports and LNG imports have
been reduced significantly (down nearly 30% and 50%,
respectively, from Winter 2011). As rigs are reduced, one
might expect a continued ramp-down in domestic dry gas
production.
Sources: EIA; Baker Hughes; Energy Intelligence Natural Gas Week
$-
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
0
200
400
600
800
1,000
1,200
1,400
Jan-10
Mar-10
May-10
Jul-10
Sep-10
Nov-10
Jan-11
Mar-11
May-11
Jul-11
Sep-11
Nov-11
Jan-12
Mar-12
May-12
Jul-12
HenryHubSpotGasPrices($/MMBTU)
No.ofU.S.Rigs
Rig Count vs. Spot Gas Prices (Jan. 2010–Aug. 2012)
Henry Hub Spot Gas Prices
Gas Rigs
Horizontal Rigs

7. Copyright © 2012 by ScottMadden. All rights reserved.
Trend 1 – Gas
Coal Versus Gas: The Switch Goes On
6
Notes: *Per MMBTU.
**Assumes 20% var. O&M, wind at 33% availability; zero
marginal cost for hydro.
Sources: EIA; SNL Financial; ScottMadden analysis
$0
$2
$4
$6
$8
$10
$12
$14
Jan-02
Jul-02
Jan-03
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Jul-08
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Jul-09
Jan-10
Jul-10
Jan-11
Jul-11
Jan-12
DeliveredPrice($/MMBTU)
Coal
Natural Gas
At $3* gas and
$2.50* coal, a coal
unit at about
9,600 BTU/kWh is
displaced by a 8,000
BTU/kWh gas
combined cycle
$0
$2
$4
$6
$8
$10
$12
$14
FuturesPrice($/MMBTU)
Central Appalachian Coal (Big Sandy
12,000 1.67 Barge)
Gulf Coast Gas TX (Henry Hub)
Illustrative NYMEX Coal and Gas Futures Prices as
of May 3, 2012 (in $/MMBTU) (Jan. 2012–Dec. 2014)
Example Plant Dispatch Curve** – SERC Region
(May 2012)
Fuel Mix of Top 10
U.S. Generators
Coal Share of Total Gen Gas Share of Total Gen
2010 2011 2010 2011
Southern Co. 57% 51% 25% 30%
NextEra Energy 4% 3% 51% 57%
American Electric
Power 81% 77% 8% 11%
Exelon 5% 3% 1% 1%
TVA 49% 47% 7% 8%
Duke Energy 60% 57% 7% 10%
Entergy 13% 12% 23% 25%
FirstEnergy 64% 70% 0% 0%
Dominion Resources 38% 32% 14% 19%
Progress Energy 45% 36% 29% 32%
$0
$50
$100
$150
$200
$250
$300
$350
$400
$450
0 50,000 100,000 150,000 200,000 250,000
MarginalPrice($/MWh)
Cumulative Capacity (MW)
Coal Coke Gas Oil Nuc Other Renew Water Wind
$30
$35
$40
$45
180,000 190,000 200,000 210,000 220,000 230,000
As modeled here,**
coal and gas
compete
in the $30 to $45
marginal cost range
Monthly Cost of Fuel Receipts at U.S. Electric-Generating
Plants (in $/MMBTU incl. Taxes) (Jan. 2002–May 2012)
Source:SNLFinancial

8. Copyright © 2012 by ScottMadden. All rights reserved.
Trend 2 – EPA
All of the Above...Except Coal –
EPA Rules: The Big Three
Proposed Rule Affected Units Requirements Implications and Issues
Cooling Water
Intake under Clean
Water Act §316(b)
(final rule delayed
until June 2013)
◆ Power generation,
manufacturing, and
industrial facilities
◆ Use 25%+ of water for
cooling and two million
gallons/day
◆ Site-specific Best Available
Control Technology (BACT) for
impingement and entrainment
mortality
◆ Not “one-size-fits-all”
◆ EPA estimates 257 affected
facilities at average cost of
$0.7 to $8.9 million per facility
◆ ERCOT est. for closed loop
cooling tower: $200/KW
◆ Closed loop for new; perhaps
for existing?
Mercury and Air
Toxics Standard
(MATS) (final
standards released
in Dec. 2011; for
new plants, revised
rule pending, due
Mar. 2013)
◆ New and existing coal- and
oil-fired utility steam
generating units
◆ Natural gas plants not
affected
◆ Cut 91% of mercury and limit
acid gases, other metals,
particulate matter
◆ Maximum Achievable Control
Technology (MACT)
◆ Three-year compliance
window; possible (rare) one-
year extension
◆ Per EPA, affects 1,350 coal-
and oil-fired units at 525
plants
◆ May require scrubbers on all
coal units
Cross-State Air
Pollution Rule –
CSAPR (issued
July 2011; 2012/14
implementation;
stayed Dec. 30,
2011; rule vacated
by D.C. Circuit,
Aug. 21, 2012; EPA
has until early Oct.
to appeal)
◆ Power plants in 28 affected
states (including late
entrant TX)
◆ Per EPA, affects 3,632
electric generating units at
1,074 coal-, gas-, and oil-
fired facilities
◆ Defined state (not regional)
SO2, NOx emissions budgets
for “upwind” contribution to
“downwind” non-attainment
◆ Likely requires state-of-the-art
SO2 and NOx controls
◆ Pending appeal with
expedited timing
— Jan.: Briefing plans
— Apr.: Hearings
— July–Aug.: Decision
expected
◆ For now, CAIR remains in
effect—2012 dif. in emissions
budget
— SO2: + <1%
— NOx: +15%
— Ozone season NOx: +14%
Sources: EPA; Van Ness Feldman; Bryan Cave; World Resources Institute;
industry news
7
Strong industry reaction. Political and judicial
arm wrestling. Invest or retire?

9. Copyright © 2012 by ScottMadden. All rights reserved.
Trend 2 – EPA
All of the Above...Except Coal –
EPA Rules: Plus Two
8
Proposed Rule Affected Units Requirements Implications and Issues
Coal Combustion
Residuals Treatment
as Solid or Hazardous
Waste (proposed June
2010)
◆ To be determined Two alternatives proposed:
◆ Hazardous waste:
comprehensive waste program,
federally enforceable
◆ Solid waste: EPA performance
standards for coal ash handling
facilities; state enforcement;
wet handling of coal ash
through impoundments with
liners
◆ Concerns that hazmat label
will send more CCRs to
landfills rather than beneficial
use
◆ Uncertainty about states
ability to manage this along
with other changing EPA
standards
Greenhouse Gas New
Source Performance
Standards for Electric
Generation
(proposed Mar. 2012;
EPA not expected to
act on final rule until
after election)
◆ New fossil-fired
steam and
combined-cycle
generating units
>25 MW
◆ Explicitly excludes
existing units or
modifications or
reconstructions of
existing units
◆ Some believe rules
may apply where
existing plants are
modified in a way
that increases their
hourly rate of
emissions
◆ Proposed cap of 1,000 pounds
of CO2 per MWh
◆ Pegged to natural gas
combined cycle (EPA: 95% of
NGCCs constructed between
2006 and 2010 met standard)
◆ Allows construction of new
generation with commitment to
later install CCS equipment,
but no one believes this is
practical now
◆ Grandfathers “transitional
units”—new generation with
pre-construction permits and
begins construction by late
March 2013
◆ Effectively eliminates new
coal plants: Without CCS
cannot meet standard;
implicitly assumes CCS costs
will decline, be at commercial
scale within 10 years
◆ EPA assumptions:
◆ Most new units would be
gas-fired given low gas
prices
◆ New coal attractive over
NGCCs at $9.60/MMBTU
gas
◆ But assumes coal by
comparison would cost
between $9 and $50/MWh
in “pollution damages”
Could GHG new source rules morph into a modification standard that affects
existing generation more profoundly than EPA says?

10. Copyright © 2012 by ScottMadden. All rights reserved.
Trend 2 – EPA
Cost of EPA Rules
Source: AEP, conference presentation, 10/9/12 SNL Electric Generation Conference
9

11. Copyright © 2012 by ScottMadden. All rights reserved.
Trend 2 – EPA
All of the Above...Except Coal –
EPA Rules = Massive Coal Plant Retirements?
Sources: Deutsche Bank; FitchRatings: Sanford C. Bernstein; SNL Financial
10
◆ Divergent estimates on coal plant retirements
— EPA only looked at each regulation, not the combined effect
— Final rule more aggressive than draft
◆ Some post-Cross-State Air Pollution Rule coal generation retirement analyses
— EPA: 4.8 GW (1% of capacity); no impact on power prices
— Bernstein: 60 GW by late 2015 (combined CAIR and MATS)
— Black & Veatch: 65 GW, 50 GW in the Eastern
Interconnection
— Burns & McDonnell: 40 to 50 GW
— EPRI: 61 GW between 2010 and 2035; 54 GW “on the
fence”
— Friedman Billings Ramsey: 50 GW to 55 GW by 2018,
largely due to MATS
— Fitch: 83 GW (combined rules effects)
— Guggenheim Securities: 50 GW by 2015 (combined rules
effects)
— ICF: 70 GW of retirements (combined rules effects)
— Wood Mackenzie: 78.7 GW by 2033
More than 30 GW Announced
Retirements in Next 10 Years
◆ U.S. power companies have
formalized plans to retire 30,321
MW of coal-fired generating
capacity between 2012 and 2021
◆ This figure is up from a March 2012
estimate of 25,000 MW of coal
capacity retirements during the
same period
Source: SNL

12. Copyright © 2012 by ScottMadden. All rights reserved.
Trend 3 – Midstream Gas System
Does Design Basis = Current Use State?
11
New Pipelines Needed; NGLs Are Current Focus
◆ Pipeline expansions 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
Pipeline Capacity from Selected Basins to
Selected Demand Centers as of Sept. 2008 (BCF/Day)
(5.00)
-
5.00
10.00
15.00
20.00
25.00
June-06 June-07 June-08 June-09 June-10 June-11
$/MMBTU
Basis Differential (Transco Zone 6-Henry Hub)
100 per. Mov. Avg. (Basis Differential (Transco Zone 6-Henry
Hub))
Basis (Price) Differential—NY Transco Zone 6 (NYC) vs. Henry Hub
and 100-Day Moving Average (June 2006–Nov. 2011)
Sources: EIA; FERC; Morgan Stanley; Credit Suisse; SNL Financial;
ScottMadden analysis

13. Copyright © 2012 by ScottMadden. All rights reserved.
Trend 4 – Midstream Electric-Gas Coordination –
No Problem or Big Deal?
◆ Firmness of gas contracts and contracting method; potential for common mode failure
— If the gas isn’t firm, can the capacity be? Transmission N-1 and N-2 planning excludes pipeline loss
• Multiple gas plants depend on single pipeline; can be coupled with coincident heating load peak (TX 2/2/2011)
• Motor-driven compressors need power
• The building of new pipelines to full utilization (anchor tenant vs. fully subscribed model)
– In electric, we like reserve margin
— Biggest issues may be in bid-based markets; vertically integrated utilities can recover firm gas costs in rates
◆ Response speed, intra-hour and intra-day responsiveness, volumetric volatility, high pressures needed by new CCs
— Gas travels at 20 mph; electricity must be balanced instantaneously
— Storage can help, but still has some “speed limits” on working gas withdrawal
— Electricity demand ramps more rapidly than pipeline delivery cycles
• High pressure needs of CCs can exhaust line packs quickly; line packs are built up overnight
• A CC can look to a pipeline like a city the size of St. Louis or San Antonio, limiting grid flexibility to react abruptly
◆ Location, location, location
— Pipelines built to move gas from old production centers to heating loads in population centers
— Now supply is in a different place; so is demand from electric generation, the fastest growing gas demand component
— Storage is concentrated geographically; generation is not
◆ Market operations and scheduling
— Scheduling day mismatch; generators cannot order in time to secure their dispatch commitments
◆ Code of conduct and communications
— Communications and coordination is not what it should be
— And some of what it should be may be illegal, due to revealing sensitive electric transmission information
— But NAESB with FERC approval has relaxed some of the code of conduct constraints if reliability will be impacted
12

14. Copyright © 2012 by ScottMadden. All rights reserved.
Portfolio Diversity and the Nation’s Power Supply
Déjà Vus All Over Again?
13
0
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70,000 1950
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2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
U.S.Operating PowerGeneration Capacityby Fuel
and by Initial Operating Date (as of Year-End 2011)
Wind
Solar
Other
Oil
Nuclear
Hydro
Gas
Coal
Clean Air Act
Amendments
affect coal plant
build
Nuclear
cost
overruns
make
headlines
Merchant
generators
proliferate
and get
active in gas
generation
build-out
Merchant
bust
Massive
coal
retirement
forecast by
some
Nuclear
catches on
Notes: Excludes capacity in operation before 1950. 2011 data are preliminary and incomplete; pending EIA update.
Hydro is run-of-river and pumped storage; excludes tidal, etc. Coal includes lignite and refined coal, but does not include petcoke, black liquor, and the
like. Gas does not include propane or syngas. Oil includes residual, distillate, and "other" oil, which includes waste oil products like butane, sludge oil, tar
oil, and propane.
Current U.S. Operating Power Generation Capacity by Fuel
and Initial Operating Date (as of Year-End 2011)
Source: EIA

15. Copyright © 2012 by ScottMadden. All rights reserved.
Supply Shakeup – Is Transmission Ready?
14
Planning Cycles
◆ Traditionally long lead time for developing and constructing transmission may not keep pace
with generation requirements as driven by new regulations
◆ Varied planning horizons for different asset types complicates transmission planning
◆ Assets currently contemplated have unique operating characteristics (operate based on pricing,
load, contracts—not system conditions)
◆ Assets are being added to the resource mix that may not actually operate under all scenarios
Operations
◆ Retirement of larger or strategically placed units may cause changes to power flows and
stability dynamics
◆ Enhancements and investments to transmission systems may be needed to provide reactive
and voltage support, address thermal constraints and provide system stability
Outage Coordination
◆ Given tight window for compliance, many units that will be retrofitted may need to take
concurrent long-term maintenance outages, causing resource adequacy concerns
New generation, outages for retrofits, and required transmission must be coordinated in
order to ensure continued bulk system reliability
Sources: NERC 2011 Long Term Reliability Assessment; Industry news

16. Copyright © 2012 by ScottMadden. All rights reserved.
Closing Thoughts
◆ Supply uncertainty is at unprecedented levels
— Is your current transmission plan based on generation assumptions that are less certain?
◆ The mismatch in planning cycles between supply and transmission makes it unlikely that all major
assumptions made at the beginning of the transmission planning cycle will still be true when facilities
come on line
— And, almost inconceivable that they will remain true for the 50-year useful life
— This is exacerbated by the number of players planning supply and, increasingly, transmission
◆ Despite this uncertainty, we are embarking on another step-function increase in transmission build
— This is needed in part because of the backlog and long latency between planning and reality
— Is the transmission planning and development process flexible enough to accommodate the
policy mandates currently in place or coming?
◆ During the 10-year transmission planning horizon (possible), and almost certainly during the 50-year
useful life:
— Disruptive technologies will be introduced (or a lot of VC money will go down the drain)
— Discontinuous public polices and market rules will be enacted
◆ This unprecedented uncertainty makes planning more challenging than ever before, especially for
transmission
◆ Our advice
— Maintain a questioning attitude
— Make assumptions and conventional wisdom explicit—and challenge them!
— Consider more than one state of the world
15

17. Copyright © 2012 by ScottMadden. All rights reserved.
Witches Brew…Or Love Potion #9
16
Perhaps a bit of both...depending on how we
coordinate timing, constraints, and opportunities

18. ScottMadden, Inc
3495 Piedmont Road
Building 10, Suite 805
Atlanta, GA 30305
Phone 404-814-0020
scottmadden.com
A. Todd Williams
Director
toddwilliams@scottmadden.com
17
To read more: http://www.scottmadden.com/insight/561/The-Energy-Industry-Update.html