Download 30th Annual Platts Global Power Markets Conference

30th Annual
Platts Global Power Markets
Conference
April 14, 2015
Bob Flexon, President and Chief Executive Officer
Energizing you, powering our communities.
Forward-Looking Statements
Cautionary Statement Regarding Forward-Looking Statements
This presentation contains statements reflecting assumptions, expectations, projections, intentions or
beliefs about future events that are intended as “forward looking statements.” You can identify these
statements by the fact that they do not relate strictly to historical or current facts. Management
cautions that any or all of Dynegy’s forward-looking statements may turn out to be wrong. Please read
Dynegy’s annual, quarterly and current reports filed under the Securities Exchange Act of 1934,
including its 2014 Form 10-K for additional information about the risks, uncertainties and other factors
affecting these forward-looking statements and Dynegy generally. Dynegy’s actual future results may
vary materially from those expressed or implied in any forward-looking statements. All of Dynegy’s
forward-looking statements, whether written or oral, are expressly qualified by these cautionary
statements and any other cautionary statements that may accompany such forward-looking
statements. In addition, Dynegy disclaims any obligation to update any forward-looking statements to
reflect events or circumstances after the date hereof.
2
Dynegy - Scale and Diversification with a
Purpose
In MWs
Legacy Dynegy
IPH
EquiPower
Asset Mix
20%
Retail
CCGT
Coal
Peakers
Total
PJM
~4,500
~3,600
~2,900
~11,000
~40%
ISO-NE
~2,500
~1,100
~400
~4,000
~20%
MISO
0
~7,000
0
~7,000
~25%
NYISO
~1,100
0
0
~1,100
~5%
CAISO
~1,000
0
~1,500
~2,500
~10%
TOTAL
~9,100
~11,700
~4,800
~25,600
100%
CCGT
35%
45%
Duke
Market
% of
Portfolio
Coal
Peakers
Diversified fleet with critical scale in key US power markets
3
System Stretched Too Thin
What is Causing the Stress
Economic Pressure
Natural Gas
Intermittent Resources
Renewables
Environmental
Regulations
Distributed Generation
State
Demand Response
Market
Design
Federal
Loss of Baseload
Generation
Need for Natural Gas
Infrastructure BuildOut
Coal
Nuclear
Stress On System
Reflected In Prices
Financial Stress
Physical Stress
Every market suffers from these issues to varying degrees
5
Financial Stress From Natural Gas Prices
Natural Gas Basis Differentials(1) (in $ per mmbtu)
2015
2016
$1.65
$1.12
Henry Hub Natural Gas Price(1) (in $ per mmbtu)
$8.85
$8.69
$6.74
$2.32
2017
($0.03) ($0.10)
($0.15)
($0.03)
($0.19)
($1.00)($0.82)
($1.06)
($1.14)
$6.94
Dominion
$4.37
$3.99
$3.92
Chicago CG
Algonquin CG
Natural Gas Price(1) (in $ per mmbtu)
$4.32
2015
$3.37
$3.72
$2.75
TETCO M3
$2.83
$3.14
2016
2017
$5.46
$5.02
$3.11 $3.27 $3.95
$2.99 $3.18 $2.80
$2.37
$2.01
$1.69$2.08
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
Dominion
TETCO M3
Chicago CG
Declining Natural Gas Prices
Regional Natural Gas Pricing
•
•
Prolific shale production has preceded natural gas
demand growth
Algonquin CG
Expansion of shale gas production in basins with
limited infrastructure has resulted in significant
regional natural gas price differentials
Economic pressure from low natural gas prices initiated the first wave of asset
retirements; regional natural gas price differentials amplify the problem
6
(1)
Prices as of March 26, 2015; basis differential versus Henry Hub; Henry Hub price per mmbtu: 2015 - $2.83; 2016 - $3.14; 2017 - $3.37; 2015 represents
balance of year pricing
Federal Environmental Policy Onslaught Adds
To Financial Stress
CSAPR Phase I Begins
Air
Water
MATS Compliance Begins
Solid Waste
MATS Compliance 1 Year Extension
MATS Compliance 1 Year Federal Exemption
316(b) Compliance Begins
2015
2016
2017
2018
2019
2020
Effluent Limits Guidelines
Compliance Expected
CSAPR Phase II Begins
Attainment for 2010 SO2 and NOX
Clean Power Plan Interim Period Begins
Coal Combustion Residual Compliance Begins
The weak economic backdrop and compliance dates drive the second round of
retirements
7
Loss of Baseload Generation to Retirements
Historical and Projected Asset Retirements by Market(1) (in GW)
18,000
16,000
ISO-NE Retirements
ISO-NE
• Approximately 15% of capacity retired
from 2010 through 2017
PJM
14,000
MISO
12,000
PJM Retirements
10,000
• Approximately 15% of capacity retired
from 2010 through 2017
8,000
MISO Retirements
• Approximately 8% of capacity retired from
2010 through 2017
6,000
4,000
2,000
0
2010
2011
2012
Economic
Retirements
2013
2014
2015E
2016E
2017E 2018E…
Environmental
Retirements
Economic &
Environmental
Retirements
Past and pending asset retirements removing 10-15% of the installed capacity
across three major US power markets
8
(1)
Source: MISO, PJM, ISO-NE
$1,000
$900
$800
$700
$600
$500
$400
$300
$200
$100
$0
25,000
PJM West Pricing and Load Comparisons
1H2012
1H2013
1H2014
Average
Demand
ISO-NE Pricing and Load
$800
$700
30,000
35,000
40,000
45,000
50,000
55,000
60,000
65,000
Demand (MWs)
$500
$/MWh (Day-Ahead)
$400
MISO Pricing and Load
1H2012
1H2013
1H2014
$600
$500
Average
Demand
$400
$300
$200
$100
Average
Demand
$300
$/MWh (Day-Ahead)
$/MWh (Day-Ahead)
Impact of Stress on the System Reflected in Prices
$0
8,000
13,000
18,000
23,000
Demand (MWs)
$200
1H2012
1H2013
1H2014
$100
$0
40,000
45,000
50,000
55,000
60,000
65,000
Demand (MWs)
70,000
75,000
80,000
Baseload plant retirements shrink supply, tighten the energy market, and
amplify volatility
9
Significant Generation from Plants Slated to Retire
Energy Generated from Assets Slated to Retire(1)(2)
4.4% 4.3% 4.5%
4.3%
3.7%
3.0%
3.2%
PJM
3.4%
3.0%
MISO
2012
2013
ISO-NE
2014
Removing low-cost generation from supply expected to drive energy prices
higher
10
(1)
Internal Source: Energy Velocity, Dynegy Fundamental; (2) Reflects MISO Classic, PJM, and ISO-NE announced retirements
Changing Natural Gas Market Dynamics
U.S. Natural Gas Consumption by Sector (Bcfd)
80
Exports
60
Residential
40
Industrial
20
Electric Power
Commercial
0
2005
Historical Natural Gas Flows(1)
2010
2015
2020
Future Natural Gas Flows(1)
Natural gas market dynamics have fundamentally changed, but the evolution
of natural gas infrastructure has lagged
11
(1)
Source: Morgan Stanley
Constrained New England Natural Gas Supply
New England Natural Gas Prices(1) ($ per mmbtu)
Iroquois Gas Transmission
Tennessee Gas Pipeline
Algonquin Gas Transmission
Maritimes & Northeast Pipeline
Winter 15/16
Summer 16
$9.85
$3.13
$3.07
NYMEX Henry Hub
$2.89
Algonquin CG
Constrained Natural Gas Transmission
• Natural gas transmission into New England is
constrained
• Constraint becomes particularly acute in the winter as
the natural gas demand for heating rises
• Limited supply infrastructure as a result of public and
political opposition to infrastructure development
Pipeline Expansion Needed For Price Relief
• Transmission charges have increased by 500% since
2005
• Spent $7 billion on transmission since 2003; plans to
spend an additional $4.5 billion by 2018
• Additional transmission lines are not the answer
Efficient combined cycle assets are underutilized in high demand periods due
to lack of natural gas infrastructure
12
(1)
Winter 15/16 comprised of prices for November 2015-March 2016, Summer 2016 comprised of prices for April 2016-October 2016, prices as of March 26, 2015
Dependency on Intermittent Resources Brings
Reliability Risks
PJM Supply Mix(1)(2) (in GW)
ISO-NE Supply Mix(1) (in GW)
34 Reserve Margin 34
222
Reserve Margin
Demand Response
Demand Response
Renewable
Renewable
199
Hydro
Hydro
Baseload &
Intermediate
2010
2020
CAISO Supply Mix(1) (in GW)
63
76
Reserve Margin
2010
2020
Demand Response
Renewable
Hydro
Baseload &
Intermediate
2010
Baseload &
Intermediate
Reliance on Intermittent Resources to Serve Load
•
•
•
•
Hydro, wind, and solar generation are subject to rainfall, wind, and
solar resource availability
Wind and solar are incapable of being actively dispatched
Demand response capabilities remain somewhat untested
Minimum demand response contribution to winter supply
2020
Intermittent resources increasingly represent a key component of supply
across multiple markets
13
(1)
Source: ICF; (2) PJM scale expanded to improve detail; 2010 reserve margin estimated due to change in PJM footprint
Intermittent Resources and Price Impact
MISO
CAISO
Annual Percentage of Negative MISO Real Time Hours(1)
4.4%
4.0%
2.1%
2012
Intermittent Resources Physically Stress the System
•
Fast-ramping peaking capacity becomes increasingly
necessary as penetration of renewables creates intraday
volatility
2013
2014
Intermittent Resources Financially Stress the
System, Suppressing Off-Peak Pricing
•
Nuclear plants are unable to cycle and must pay the system
to remain on line when wind power puts negative prices on
the system, typically overnight
Intermittent resources not only stress the physical system, but they also have
a negative financial impact on reliable, low-cost baseload generation
14
(1)
Hubs included are Arkansas, Cinergy/Indiana, Illinois, Louisiana, Michigan, and Minnesota
Incentivizing Investment
Incentivizing Investment: Why Does It Matter?
Future reliability hinges on
how private capital is
invested today
Investment decisions based
on cumulative capacity and
energy revenue
Current tariffs and
practices need to reflect
the evolving system
stresses
 When markets are allowed
to function, uneconomic
resources retired
 Weak price signals in times
of shrinking supply reflect
market design and public
policy flaws
 Regulatory conditions need
to be examined before the
investment climate erodes
further
Well-functioning, sustainable competitive wholesale markets provide the
price signals for new investment
16
Incentives Versus Interference
Out of Market Revenues
• Propping up uneconomic resources fails to
value those that are economic
Out of
Market
Revenues
Inconsistent Market Design
• Significantly different market designs lead to
barriers (a.k.a. seams) across markets
Mandated
RPS and
Energy
Efficiency
Inconsistent
Market
Design
Market
Distortion
Preferential
treatment
for DR,
variable, and
distributed
resources
Inconsistent
Federal and
State
Regulations
Inconsistent Regulations
• Inconsistent implementation of regulations
such as the Clean Power Plan shifts
investment and jobs from one state to
another
Increased Demand Response
• Increased DR with compensation equal to
traditional generation but with reduced
performance expectations
Mandated RPS and Energy Efficiency
• State-mandated RPS and EE targets lead to
expensive fees on consumers’ bills
Markets with the least interference and best design such as PJM
are those most likely to attract private capital and investment
17
Destructive Out of Market “Solutions”
Out of Market
Subsidies Being
Pursued in Illinois
Out of Market
Subsidies Being
Pursued in New York
Low Carbon Portfolio Standard
• Designed to provide subsidy to uneconomic generation
• Subsidy akin to Wind Production Tax Credit distorts
market outcomes
Reliability Support Services Agreement
• Allows asset under reliability contract to continue
offering into energy and capacity markets, distorting
market outcomes
Above Market Contracts with Utility Affiliate
Out of Market
Subsidies Being
Pursued in Ohio
• Distorts market outcomes by preserving uneconomic
generation
• Makes suppliers agnostic to offering at real costs
Out of market subsidies take decisions about winners and losers out of the
hands of the market and places decisions in the hands of policy makers at the
expense of consumers and businesses
18
Positioning Power Portfolios for the
Future
Need For Well-Designed Markets
PJM
ISO-NE
MISO
ERCOT
CAISO
High
Scarcity
Price Caps
Capacity
Market
Forward
Capacity
Market
Sloped
Demand
Curve
Stable
Market
Rules
Performance
Incentives
*
Both PJM and ISO-NE are leading the way with market designs that send
appropriate price signals to address system stresses
20
*Planned but not approved
Constructive Performance Incentives
PJM Capacity
Performance
Capacity Performance Payments
• Payment to generators over
performing during shortage events
• Penalty to generators under
performing during shortage events
• Provides incentive for generators to
invest in reliability
ISO-NE Performance
Incentives
PJM and ISO-NE are leading the industry by implementing market design
solutions that address system reliability
21
Constructive Forward Capacity Markets
PJM Projected Reserve Margin(2)
PJM Capacity Auction Results(1)
20%
($ per kw-month)
$3.86
$3.99
15%
$4.62
18.0%
18.8%
18.8%
18.2%
$3.65
$2.71
$2.28
17.1%
10%
5%
12/13
13/14
14/15
15/16
16/17
17/18
0%
ISO-NE Capacity Auction Results
($ per kw-month)
PY 15/16 PY 16/17 PY 17/18 PY 18/19 PY 19/20
Sending Appropriate
Price Signal, But Market
Response Takes Time
$11.08
$9.55
Price Signal Inconsistent
With Desired Result
ISO-NE Projected Reserve Margin(2)
25%
Cleared at the Floor
$3.21
$3.43
14/15
15/16
16.0%
11.0%
10%
$2.95 $2.95
24.0%
20%
15%
$7.03
24.0%
11.0%
5%
$3.15
0%
12/13
13/14
16/17
17/18
18/19 Rest 18/19
of Pool SEMA/RI
PY 15/16 PY 16/17 PY 17/18 PY 18/19 PY 19/20
PJM’s constructive market design facilitates market stabilization; ISO-NE
recognized the need to evolve to a more constructive model
(1)
22
Average of RTO and MAAC pricing; (2) Source: PJM and ISO-NE
MISO Market Does Not Address Pending
Supply Shortfall
MISO Capacity Auction Results(1) ($ per kw-month)
$3.99
$3.86
$3.21
$2.95
$0.51
$0.03
13/14
14/15
MISO
ISO-NE
PJM
MISO Projected Reserve Margin(2)
18%
16%
14%
12%
10%
8%
6%
4%
2%
0%
16.6%
Target Reserve Margin
11.5%
12.3%
10.6%
9.0%
PY 15/16
PY 16/17
PY 17/18
PY 18/19 PY 19/20
Lack of Forward Capacity Auction
Vertical Demand Curve
•
• Sends no price signal to indicate an impending
shortfall
• Capacity is worthless when market is oversupplied
and invaluable when market is short
•
MISO executes its capacity auction six weeks
before the start of the planning year
Timing of price signal inconsistent with assets
that take years to build
Six week forward capacity market with opaque rules does not send new build
price signal until it is too late
(1)
23
PJM price shown is average of RTO and MAAC pricing; (2) Source: MISO
Refining The Market Construct to
Meet Future Requirements
Needed Reforms
Coordinated State and National Energy Policy
Energy Market & Ancillary
Services Price Formation
Capacity Market & Resource
Adequacy Rules
Out of Market Entry &
Uneconomic Supply
• Reliability commitments need to be reflected in LMPs
• Administratively-mitigated prices skew true market prices
• Sloped demand curve and forward commitment reflect supply-demand balance
• Buyer-side mitigation prevents undue price suppression
• Flexible capacity needed to balance variability of intermittent resources
• RMR resources should be held out of energy and capacity markets to avoid artificial price
suppression
Proper Role for Demand
Response
• Comparable obligation if receiving comparable compensation
• If a capacity product, then should have similar “must offer” requirements and be an
annual product
Transmission and Seams
• Greater transparency and coordination between ISOs will lead to price convergence and
market efficiency
Dynegy strongly supports competitive wholesale power markets, which
provide significant consumer benefits but require improved market designs
25
Stresses continue to affect each market, and only select
markets are changing their market designs to relieve the
pressure.
Well-designed markets must consistently send appropriate
price signals to address system needs.
Competitive markets should also reflect a level playing
field resulting in optimum outcomes without interference
from outside forces. Interference through subsidies shifts
risks from shareholders to customers, distorting the
market and driving higher prices to the consuming public.
26