UNITED STATES SECURITIES AND EXCHANGE COMMISSION | |||||||||
Washington, D.C. 20549 | |||||||||
FORM 8-K | |||||||||
CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 November 6, 2017 Date of Report (Date of earliest event reported) | |||||||||
Commission File Number | Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number | IRS Employer Identification Number | |||||||
1-16169 | EXELON CORPORATION | 23-2990190 | |||||||
(a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (800) 483-3220 | |||||||||
333-85496 | EXELON GENERATION COMPANY, LLC | 23-3064219 | |||||||
(a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959 | |||||||||
1-1839 | COMMONWEALTH EDISON COMPANY | 36-0938600 | |||||||
(an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321 | |||||||||
000-16844 | PECO ENERGY COMPANY | 23-0970240 | |||||||
(a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000 | |||||||||
1-1910 | BALTIMORE GAS AND ELECTRIC COMPANY | 52-0280210 | |||||||
(a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201 (410) 234-5000 | |||||||||
001-31403 | PEPCO HOLDINGS LLC | 52-2297449 | |||||||
(a Delaware limited liability company) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000 | |||||||||
001-01072 | POTOMAC ELECTRIC POWER COMPANY | 53-0127880 | |||||||
(a District of Columbia and Virginia corporation) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000 | |||||||||
001-01405 | DELMARVA POWER & LIGHT COMPANY | 51-0084283 | |||||||
(a Delaware and Virginia corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000 | |||||||||
001-03559 | ATLANTIC CITY ELECTRIC COMPANY | 21-0398280 | |||||||
(a New Jersey corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000 | |||||||||
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
☐ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
☐ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
☐ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
☐ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Indicate by check mark whether any of the registrants are emerging growth companies as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company | ☐ | |
If an emerging growth company, indicate by check mark if any of the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
- 2 -
Section 7 - Regulation FD
Item 7.01. Regulation FD Disclosure.
On November 6-8, 2017, Exelon Corporation (Exelon) will participate in the Edison Electric Institute (EEI) conference. During the conference, Exelon will re-affirm its 2017 adjusted (non-GAAP) operating earnings guidance range of $2.55—$2.75 per share, as disclosed in its third quarter 2017 earnings release and the slides for its earnings call, as furnished to the SEC in the Current Report on Form 8-K on November 2, 2017. Attached as Exhibits 99.1 and 99.2 to this Current Report on Form 8-K are the presentation slides and handouts to be used at the conference.
Section 9 - Financial Statements and Exhibits
Item 9.01. Financial Statements and Exhibits
(d) Exhibits.
Exhibit No. | Description |
* * * * *
This Current Report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements made by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants) include those factors discussed herein as well as those discussed in (1) Exelon's 2016 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 24; (2) Exelon's Third Quarter 2017 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 18 and (3) other factors discussed in filings with the Securities and Exchange Commission by the registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
EXELON CORPORATION | |
/s/ Jonathan W. Thayer | |
Jonathan W. Thayer | |
Senior Executive Vice President and Chief Financial Officer | |
Exelon Corporation | |
EXELON GENERATION COMPANY, LLC | |
/s/ Bryan P. Wright | |
Bryan P. Wright | |
Senior Vice President and Chief Financial Officer | |
Exelon Generation Company, LLC | |
COMMONWEALTH EDISON COMPANY | |
/s/ Gerald J. Kozel | |
Gerald J. Kozel | |
Vice President, Controller | |
Commonwealth Edison Company | |
PECO ENERGY COMPANY | |
/s/ Phillip S. Barnett | |
Phillip S. Barnett | |
Senior Vice President, Chief Financial Officer and Treasurer | |
PECO Energy Company | |
BALTIMORE GAS AND ELECTRIC COMPANY | |
/s/ David M. Vahos | |
David M. Vahos | |
Senior Vice President, Chief Financial Officer and Treasurer | |
Baltimore Gas and Electric Company | |
PEPCO HOLDINGS LLC | |
/s/ Donna J. Kinzel | |
Donna J. Kinzel | |
Senior Vice President, Chief Financial Officer and Treasurer | |
Pepco Holdings LLC | |
POTOMAC ELECTRIC POWER COMPANY | |
/s/ Donna J. Kinzel | |
Donna J. Kinzel | |
Senior Vice President, Chief Financial Officer and Treasurer | |
Potomac Electric Power Company | |
DELMARVA POWER & LIGHT COMPANY | |
/s/ Donna J. Kinzel | |
Donna J. Kinzel | |
Senior Vice President, Chief Financial Officer and Treasurer | |
Delmarva Power & Light Company | |
ATLANTIC CITY ELECTRIC COMPANY | |
/s/ Donna J. Kinzel | |
Donna J. Kinzel | |
Senior Vice President, Chief Financial Officer and Treasurer | |
Atlantic City Electric Company | |
November 6, 2017
EXHIBIT INDEX
Exhibit No. | Description |
EEI Financial Conference
November 2017
2
Cautionary Statements Regarding Forward-Looking Information
This presentation contains certain forward-looking statements within the meaning of the Private Securities
Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual
results to differ materially from the forward-looking statements made by Exelon Corporation, Exelon Generation
Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company,
Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City
Electric Company (Registrants) include those factors discussed herein, as well as the items discussed in (1)
Exelon’s 2016 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion
and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and
Supplementary Data: Note 24, Commitments and Contingencies; (2) Exelon’s Third Quarter 2017 Quarterly
Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information,
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I,
Financial Information, ITEM 1. Financial Statements: Note 18; and (2) other factors discussed in filings with the
SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements,
which apply only as of the date of this press release. None of the Registrants undertakes any obligation to
publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of
this presentation.
3
Non-GAAP Financial Measures
Exelon reports its financial results in accordance with accounting principles generally accepted in the United
States (GAAP). Exelon supplements the reporting of financial information determined in accordance with GAAP
with certain non-GAAP financial measures, including:
• Adjusted operating earnings exclude certain costs, expenses, gains and losses and other specified items, including mark-to-
market adjustments from economic hedging activities, unrealized gains and losses from nuclear decommissioning trust fund
investments, merger and integration related costs, impairments of certain long-lived assets, certain amounts associated with
plant retirements and divestitures, costs related to a cost management program and other items as set forth in the reconciliation
in the Appendix
• Adjusted operating and maintenance expense excludes regulatory operating and maintenance costs for the utility businesses
and direct cost of sales for certain Constellation and Power businesses, decommissioning costs that do not affect profit and loss,
the impact from operating and maintenance expense related to variable interest entities at Generation, EDF’s ownership of O&M
expenses, and other items as set forth in the reconciliation in the Appendix
• Total gross margin is defined as operating revenues less purchased power and fuel expense, excluding revenue related to
decommissioning, gross receipts tax, Exelon Nuclear Partners, JExel Nuclear JV, variable interest entities, and net of direct cost of
sales for certain Constellation and Power businesses
• Adjusted cash flow from operations primarily includes net cash flows from operating activities and net cash flows from investing
activities excluding capital expenditures, net merger and acquisitions, and equity investments
• Free cash flow primarily includes net cash flows from operating activities and net cash flows from investing activities excluding
certain capital expenditures, net merger and acquisitions, and equity investments
• Operating ROE is calculated using operating net income divided by average equity for the period. The operating income reflects all
lines of business for the utility business (Electric Distribution, Gas Distribution, Transmission).
• EBITDA is defined as earnings before interest, taxes, depreciation and amortization. Includes nuclear fuel amortization expense.
• Revenue net of purchased power and fuel expense is calculated as the GAAP measure of operating revenue less the GAAP
measure of purchased power and fuel expense
Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the
forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently
available, as management is unable to project all of these items for future periods
4
Non-GAAP Financial Measures Continued
This information is intended to enhance an investor’s overall understanding of period over period financial
results and provide an indication of Exelon’s baseline operating performance by excluding items that are
considered by management to be not directly related to the ongoing operations of the business. In addition, this
information is among the primary indicators management uses as a basis for evaluating performance, allocating
resources, setting incentive compensation targets and planning and forecasting of future periods.
These non-GAAP financial measures are not a presentation defined under GAAP and may not be comparable to
other companies’ presentation. Exelon has provided these non-GAAP financial measures as supplemental
information and in addition to the financial measures that are calculated and presented in accordance with
GAAP. These non-GAAP measures should not be deemed more useful than, a substitute for, or an alternative to
the most comparable GAAP measures provided in the materials presented.
Non-GAAP financial measures are identified by the phrase “non-GAAP” or an asterisk. Reconciliations of these
non-GAAP measures to the most comparable GAAP measures are provided in the appendices and attachments
to this presentation, except for the reconciliation for total gross margin, which appears on slide 45 of this
presentation.
5
Exelon: An Industry Leader
Note: All numbers reflect year-end 2016; revenue accounts for PHI as of the merger effective date of March 24, 2016 through December 31, 2016.
6
The Exelon Value Proposition
Regulated Utility Growth with utility EPS rising 6-8% annually from 2017-
2020 and rate base growth of 6.5%, representing an expanding majority of earnings
ExGen’s strong free cash generation will support utility growth while also
reducing debt by ~$3B over the next 4 years
Optimizing ExGen value by:
• Seeking fair compensation for the zero-carbon attributes of our fleet;
• Closing uneconomic plants;
• Monetizing assets; and
• Maximizing the value of the fleet through our generation to load matching strategy
Strong balance sheet is a priority with all businesses comfortably meeting
investment grade credit metrics through the 2020 planning horizon
Capital allocation priorities targeting:
• Organic utility growth;
• Return of capital to shareholders with 2.5% annual dividend growth through 2018(1),
• Debt reduction; and
• Modest contracted generation investments
(1) Quarterly dividends are subject to declaration by the board of directors
7
Exelon Utilities Overview
Note: All numbers reflect year-end 2016; revenue number accounts for PHI revenue as of March 24, 2016 merger date.
8
Exelon Utilities are an Industry Leader
15.217.719.620.2
23.724.925.0
31.732.435.1
50.0
57.0
PEG FE D ETR XEL EIX ED EXC PCG AEP SO DUK
Total Utility Rate Base ($B)(1)
Total Capital Expenditures 2017-2019 ($B)(1)
6.9
10.210.410.911.112.0
14.317.3
18.0
22.125.5
3 .9
SO DUK FE PEG ETR D ED XEL EIX AEP PCG EXC(2)
US Utility Customers (millions)
3.1
4.24.84.95.05.1
5.45.56.0
6.8
8.99.29.8
10.0
ETR PEG ED NEE D EIX PCG EXC AEP XEL FE SRE DUK SO
Source: Company Filings
(1) Includes utility and generation
(2) $23B includes $15.2B of utility capital expenditures and $6.9B of generation capital expenditures
9
Our Capital Plan Drives Stable Earnings Growth
Capital Expenditures ($M)
Over $20B of capital is being invested at utilities from 2017-2020 to improve reliability
2,200 2,025
1,675 1,775
925
950
975 875
775
800
775 750
1,375 1,400
1,350 1,425
2019E
4,775
2018E
5,175
2020E
4,825
2017E
5,275
Note: CapEx numbers are rounded to nearest $25M and numbers may not add due to rounding
(1) Rate base reflects year-end estimates
Rate Base ($B)(1)
11.9 13.2
14.0 14.8 15.5
5.3
5.7
6.1
6.5 6.9
6.2
6.6
7.0
7.4
7.8
8.3
8.9
9.4
9.9
10.5
+6.5%
2020E
40.8
2019E
38.6
2018E
36.6
2017E
34.4
2016E
31.7
PHI ComEd PECO BGE
10
Utility CapEx Update
2017 Exelon Utilities CapEx Spend ($M) Notable Projects
• Pepco’s Waterfront Substation
− $182 million invested to date. Expected completion by end of
2017
− Part of “Capital Grid” project
− Replaces aging infrastructure and improves substation
performance
− Will support existing customers and planned development in
the Capitol Riverfront and Southwest Waterfront areas
• ComEd’s Grand Prairie Gateway transmission line
− $203 million investment
− 60-mile, 345kV line through four northern Illinois counties
− Energized April 2017
− Estimated customer savings of $121 to $325 million, net of
construct costs, within the first 15 years
− Reduces carbon emissions by nearly 500,000 tons within the
first 15 years
FY Plan(1)
$5,275
YTD Actual
$3,805
Exelon Utilities on track to meet their 2017 capital investment commitments to the benefit of customers
(1) FY Plan rounded to the nearest $25M
11
Proven Track Record of Improving Operational Performance
Operations Metric
At CEG Merger (2012) 2015 Q3 2017
BGE ComEd PECO PHI BGE ComEd PECO PHI
Electric
Operations
OSHA Recordable Rate
2.5 Beta SAIFI (Outage
Frequency)(1)
2.5 Beta CAIDI (Outage
Duration)
Customer
Operations
Customer Satisfaction N/A
Service Level % of Calls
Answered in <30 sec
Abandon Rate
Gas Operations
Percent of Calls Responded to
in <1 Hour
No Gas
Operations
No Gas
Operations
Overall Rank
Electric Utility Panel of 24
Utilities(2)
23rd 2nd 2nd 18th Q1 Q2
Q3 Q4
Performance
Quartiles
Exelon Utilities has identified and transferred best practices at each of its utilities to
improve operating performance in areas such as:
• System Performance
• Emergency Preparedness
• Corrective and Preventive Maintenance
(1) 2.5 Beta SAIFI is YE projection
(2) Ranking based on results of five key industry performance indicators – CAIDI, SAIFI, Safety, Customer Satisfaction, and Cost per Customer
12
Formulaic Mechanisms Cover Bulk of Rate Base Growth
2.1
1.1
1.3
9.0
0.7
2.3
0.9
0.8
Total
9.0
2020E
2.1
2019E
2.0
2018E
2.1
(0.1)
2017E
2.8
Of the approximately $9.0 billion of rate base growth Exelon Utilities forecasts
over the next 4 years, ~75% will be recovered through existing formula and
tracker mechanisms
Rate Base Growth Breakout 2017-2020 ($B)(1)
6.7
2.3 Tracker/Formula Rate
Base Rate Case
Note: Numbers may not add due to rounding
(1) Assumes PECO transmission formula rate beginning in 2018; base rate base decrease due to reclassification of transmission rate base growth at PECO
13
Q3 2017 TTM Earned ROE
Trailing 12 Month ROE vs Allowed ROE
Twelve Month Trailing Earned ROEs*
9.7%
9.9%9.9%
ACE Delmarva Consolidated EU Pepco(1) Legacy EU
Allowed ROE
Note: Represents the period from 10/1/2016 to 9/30/2017. ROEs represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Transmission).
5.9%
6.4%
7.8%
7.3%
7.7%
7.3%
10.3%
10.7%
9.5%
9.7%
Q2 2017 TTM Earned ROE
(1) Pepco MD Distribution allowed ROE is based on authorized ROE of 9.55% for the rates that were in effect during the trailing twelve month period. The order issued on 10/20/17
authorized an ROE of 9.50%.
14
Exelon Utilities’ Distribution Rate Case Updates
Pepco DC Order
Authorized Revenue Requirement Increase(1) $36.9M
Authorized ROE 9.50%
Common Equity Ratio 49.14%
Order Received 7/25/17
Pepco MD Order
Authorized Revenue Requirement Increase(1) $32.4M
Authorized ROE 9.50%
Common Equity Ratio 50.15%
Order Received 10/20/17
ACE NJ Order
Authorized Revenue Requirement Increase(1) $43.0M
Authorized ROE 9.60%
Common Equity Ratio 50.47%
Order Received 9/22/17
Delmarva MD Filing
Requested Revenue Requirement Increase(1) $21.6M(4)
Requested ROE 10.10%
Requested Common Equity Ratio 50.68%
Order Expected 2/14/18
ComEd Filing
Requested Revenue Requirement Increase(1) $95.6M(2)
Requested ROE 8.40%
Requested Common Equity Ratio 45.89%
Order Expected Q4 2017
(1) Revenue requirement includes changes in depreciation and amortization expense where applicable, which have no impact on pre-tax earnings
(2) Amount represents ComEd’s position filed in Rebuttal testimony on July 21, 2017
(3) As permitted by Delaware law, Delmarva Power will implement interim rate increases of $2.5M in Q3 2017 and will implement full allowable rates on March 17, 2018, subject to refund
(4) Amount represents adjusted requested revenue requirement filed on September 28, 2017
Delmarva DE Gas Filing
Requested Revenue Requirement Increase(1,3) $12.9M
Requested ROE 10.10%
Requested Common Equity Ratio 50.52%
Order Expected Q3 2018
Delmarva DE Electric Filing
Requested Revenue Requirement Increase(1,3) $31.2M
Requested ROE 10.10%
Requested Common Equity Ratio 50.52%
Order Expected Q3 2018
15
Exelon Utilities EPS Growth of 6-8% to 2020
$0.00
$1.70
$1.90
$1.60
$1.50
$1.80
$1.40
$2.00
$2.10
$1.80
2017E
$1.90
$1.70
2019E
$2.05
2020E 2018E
$1.60
$1.50
U
ti
lit
y
O
p
erat
in
g
E
a
rnin
g
s
Rate base growth combined with PHI ROE improvement drives EPS growth
$1.40
$1.75
Exelon Utilities Operating Earnings 2017-2020
Note: Reflects GAAP operating earnings except for 2017. 2017 GAAP EPS range would be $1.35 to $1.65. 2017 adjusted (non-GAAP) operating earnings include adjustments to exclude $0.05
for merger commitments and integration costs. Includes after-tax interest expense held at Corporate for debt associated with existing utility investment.
16
Exelon Generation Overview
Note: All numbers reflect year-end 2016
17
Constellation Overview
Note: All numbers reflect year-end 2016
(1) As calculated based on the national average generation supply mix used in EPA eGRID2014.
18
Exelon Generation: Gross Margin Update
• Delay in recognition of Illinois ZEC revenues lowers the Capacity and ZEC Revenues line in 2017 by $150M and
increases the 2018 line by $150M – see slide 19 for details
• Excluding impact of Illinois ZEC timing:
− In 2017, $50M reduction in Power New Business targets
− In both 2018 and 2019, $100M reduction due to lower power and capacity prices and $100M reduction to
Power New Business Targets
• Behind ratable hedging position reflects the upside we see in power prices
− ~11-14% behind ratable in 2018 when considering cross commodity hedges
Recent Developments
Gross Margin Category ($M)
(1) 2017 2018 2019 2017 2018 2019
Open Gross Margin
(2,5)
(including South, West, Canada hedged gross margin)
$3,600 $3,900 $3,700 $(150) $(100) $(100)
Capacity and ZEC Revenues
(2,5,6) $1,700 $2,300 $2,000 $(150) $100 $(50)
Mark-to-Market of Hedges
(2,3) $2,150 $650 $450 $250 $100 $50
Power N w Business / To Go $100 $700 $850 $(100) $(150) $(100)
Non-Power Margins Executed $350 $200 $100 $50 $50 -
Non-Power New Business / To Go $100 $300 $400 $(50) $(50) -
Total Gross Margin*
(4,5) $8,000 $8,050 $7,500 $(150) $(50) $(200)
September 30, 2017 Change from June 30, 2017
(1) Gross margin categories rounded to nearest $50M
(2) Excludes EDF’s equity ownership share of the CENG Joint Venture
(3) Mark-to-Market of Hedges assumes mid-point of hedge percentages
(4) Based on September 30, 2017, market conditions
(5) Reflects TMI and Oyster Creek retirements in September 2019 and December 2019, respectively. EGTP removal impacts partial year 2017 and full year 2018 and 2019.
(6) 2018 includes $150M of IL ZEC revenues associated with 2017 production
19
ExGen Forward Total Gross Margin* Walk: Q3 2017 vs. Q2 2017
Cumulative
Rounding
$50
Power New
Business
($50)
IL ZEC Timing
($150)
Q2
$8,150
Q3
$8,000
$150
Q3
$8,050
IL ZEC
Timing(5)
Capacity
Revenues(2,4)
($50)
Energy
Prices
($50)
Power New
Business
($100)
Q2
$8,100
Energy Prices
($100)
Q2 Capacity
Revenues(2,4)
($50)
$7,700
($50)
Power New
Business
$7,500
Q3
FY 2017 ($M)(1,3,4) FY 2018 ($M)(1,3,4)
FY 2019 ($M)(1,3,4) Key Takeaways
• Change in timing of Illinois ZEC contract finalization results in
2017 reduction of $150M on a rounded basis and 2018
increase of $150M
• Aggressive bidding by market participants in a low volatility
period is pressuring Wholesale margins and limiting C&I Retail
growth; reduce Power New Business To Go by $100M in 2018
and 2019 to reflect continuation of current, low discipline
market bidding behavior
• Lower energy prices reduce Open Gross Margin by $50M in
2018 and 2019; October price recovery offsets 2019 declines
• Lower observed capacity prices in NY and MISO reduce
Capacity Revenues by $50M on a rounded basis in 2018 and
2019
(1) Gross margin categories rounded to nearest $50M
(2) Excludes EDF’s equity ownership share of the CENG Joint Venture
(3) Based on September 30, 2017, market conditions
(4) Reflects TMI and Oyster Creek retirements in September 2019 and December 2019, respectively
(5) 2018 includes $150M of IL ZEC revenues associated with 2017 production
20
Forward Market Liquidity
Total calendar peak traded volumes for the rolling
5-year window have been trending lower over the
past year
Calendar peak traded volumes beyond prompt
year +1 account for less than 10% of total traded
volumes
* Please note that hedging strategy utilizes various price points
(i.e. NIHUB, ERCOT), channels to market (i.e. Origination, Mid-
Marketing, Retail, OTC), products (i.e. calendar, seasonal), and
other exchanges
July 2016
September 2017
Overall liquidity is declining
Limited liquidity in the outer years
3%
2% 10%
43%
43%
0%
1%
12%
29% 58%
September 2016 PJM West Hub Calendar
Peak Traded Volumes(1) (by year)
September 2017 PJM West Hub Calendar
Peak Traded Volumes(1) (by year)
(1) Total monthly traded volumes for rolling prompt year + 4 years on ICE and NASDAQ Exchanges only
Prompt+4
Prompt+3
Prompt+2
Prompt+1
Prompt yr
21
Exelon’s Policy Priorities
22
Resiliency and Energy Market Reform
Price Formation Resiliency
• PJM has stated that it is prepared to implement its reforms
allowing all resources to set LMP by mid-2018
• “FERC should expedite its efforts with states, RTO/ISOs, and
other stakeholders to improve energy price formation in
centrally-organized wholesale electricity markets.” – DOE
Staff Report, August 2017
• The Commission should focus “first and foremost on the
optimization of price formation in the energy and ancillary
service markets.” Ill. Commerce Comm’n Comments at 7
• “PJM staff is proposing to reform the existing pricing model in
order to ensure that the cost of serving load is reflected in
LMP to the fullest extent possible… This follows the principles
of sound market design.” - William W. Hogan, October 23,
2017
• “Accurately valuing resilience is not a zero-sum game.
Compensating base-load generation does not equate to
destruction of markets. On the contrary, I think it’s a step
toward accurately pricing contributions of all market
participants.” – FERC Chairman Neil Chatterjee, October 13,
2017
• “The unknowns are what we're going to have to deal with: if
there was a physical attack, if you had [an explosion like the
one on the Spectra pipeline that wasn’t] fixed in a timely
manner heading into the winter heating season, central
Pennsylvania would have had potential issues. . . So now the
conversation's gotten broader around these cascading
events, and then how do you price resiliency? That
conversation needs to take place." FERC Commissioner Rob
Powelson, October 27, 2017
• "We used to talk about equipment failure and outages caused
by storms. Now, the threat profile has changed, the
considerations are broader. There could be intentional
attacks – cyber or physical. Those concerns lead us beyond
reliability and into resilience." PJM CEO and President Andrew
L. Ott, September 20, 2017
Exelon recommends that FERC:
1. Immediately require PJM to submit its energy price formation proposal
2. Require the affected RTOs to submit detailed information on the grid’s vulnerabilities to enable the
development of a design basis threat analysis that can inform cost-effective market reforms, and
3. State that it will not interfere with state programs that value resilient resources like nuclear plants
23
ZEC Updates
New York ZEC Legal Challenges IL ZEC Legal Challenges
Federal Case:
• Case dismissed on July 25 and judgment entered
on July 27
• “The ZEC program does not thwart the goal of an
efficient energy market; rather, it encourages
through financial incentives the production of
clean energy.”
• On August 24, the plaintiffs appealed to the US
Court of Appeals for the 2nd Circuit
• Briefing schedule:
• Plaintiff-Appellant Opening Brief filed
October 13
• Reply Briefs due December 1
• Oral arguments will then follow
State Case:
• Motions to dismiss procedural challenges filed in
NY State court were briefed in 1Q17
• The court heard oral arguments on June 19
• Currently awaiting decision; next step determined
by outcome
• Both cases dismissed and judgment entered July
14
• “The ZEC program does not conflict with the
Federal Power Act.”
• On July 17, both sets of plaintiffs appealed to the
US Court of Appeals for the 7th Circuit
• On July 18, the 7th Circuit consolidated the
appeals and set a briefing schedule:
• Plaintiff-Appellant Opening Brief filed
August 28
• Reply Briefs due December 12
• Oral arguments will then follow
24
Exelon Policy Priorities
Create support for current challenged plants through
federal and state initiatives
Support the ultimate pricing of carbon in the market on a
regional or national level
Modernize Utility Ratemaking to Ensure Appropriate
Recovery
Secure Proper Policies to Enable Innovative
Technologies
Recognize the Value of Zero-Carbon Electricity
Regulatory
and policy
structure that
supports
clean,
affordable
and reliable
options for all
customers
Invest in infrastructure that provides customer benefit
through grid resiliency and efficiency
Ensure fair rate structures to support new technologies
Providing new technologies to respond to customer needs
Open adjacent customer facing markets to sales and
services
25
Our Carbon Policy Principles
• Exelon believes in our nation’s ability to transition the generation fleet to a zero-carbon
future while maintaining affordable and reliable electric service for consumers
• For the foreseeable future, the most cost-effective carbon solution for our customers will
be the continued operation of our nation’s nuclear fleet
• Exelon believes competitive markets produce superior results for consumers and drive
innovation. However, those markets do not currently incorporate appropriate pricing for
environmental attributes.
• Exelon is pursuing a two-part strategy for moving toward a more competitive treatment
of CO2 emissions:
o First, we must maintain nuclear units that provide a cost-effective form of CO2
abatement. The New York ZEC program demonstrates that as long as the clean
energy payment required to maintain operations at existing nuclear units is lower than
the social cost of CO2 emissions and the cost of CO2 abatement being paid to other
zero carbon resources, maintaining nuclear capacity should be selected as the most
competitive source of CO2 abatement.
o Second, we must continue to work toward a technology neutral price of CO2
abatement. Exelon is pursuing approaches to reflect a uniform price on CO2 in
wholesale markets as an eventual substitute for technology-specific subsidies. As
these approaches are phased in, the ZEC programs have been designed to
automatically reduce ZEC payments in response to higher energy prices.
26
Financial Overview
27
Note: Amounts may not sum due to rounding
* Refer to pages 3 and 4 for information regarding non-GAAP financial measures
Strong Third Quarter Results
$0.85
$0.00
$0.20
$0.12
$0.16
$0.06
$0.32
Q3 2017 EPS Results
• GAAP earnings were $0.85/share
in Q3 2017 vs. $0.53/share in Q3
2016
• Adjusted operating earnings*
were $0.85/share in Q3 2017 vs.
$0.91/share in Q3 2016, at the
mid-point of our guidance range
of $0.80-$0.90/share
HoldCo
ComEd
PECO
PHI
BGE
ExGen
Adjusted Operating
Earnings*
$0.85
($0.04)
$0.19
$0.12
$0.15
$0.07
$0.36
GAAP Earnings
28
~($0.20)
$0.40 - $0.50
$2.50 - $2.80(1)
$0.60 - $0.70
$0.30 - $0.40
$1.05 - $1.15
$0.25 - $0.35
2017 Initial Guidance
$1.00 - $1.10
$0.25 - $0.35
$0.30 - $0.40
$0.40 - $0.50
$0.60 - $0.70
$2.55 - $2.75(1)
2017 Revised Guidance
ExGen
BGE
ExGen
BGE
PHI
PECO
ComEd
HoldCo ~($0.15) HoldCo
PECO
ComEd
PHI
Narrowing 2017 Adjusted Operating Earnings* Guidance Range
(1) 2017 earnings guidance based on expected average outstanding shares of 949M. Earnings guidance for OpCos may not sum up to consolidated EPS guidance.
(2) Revised guidance reflects delay in Illinois ZEC revenue recognition for 2017 until 2018, shifting $0.09 of EPS
29
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Ann
oun
ced
Cos
t Re
duct
ions
Cost Management is Integral to Our Business Strategy
ExGen Forecast O&M* Q3 2017 ($M)(1) ExGen Forecast O&M*: Q3 2017 vs. Q4 2016(1) 125
225
150 25075
2018
4,300
2020 2019
4,450
4,600
50
2017
4,850
ExGen and BSC Cost Reductions Since Constellation Merger
New Cost Reductions of $250M Run-Rate by 2020
(Q3 2017 Earnings Call)
(1) Adjusted for TMI retirement and removal of EGTP, net of other expenses
CEG Merger Synergies of $170M in 2012, $350M in 2013,
and $500M Run-Rate beginning in 2014
CENG Service Agreement Run-Rate
Synergies of $70M (2013 EEI)
$350M Cost Management Program (2015 EEI)
PHI Merger Run-Rate Synergies of
$130M
Cost Reductions of $100M in 2018 and $125M in
2019 (Q3 2016 Earnings Call)
ExGen O&M ($M) 2017 2018 2019 2020
2017-2020
CAGR
Q4 2016 O&M
$4,850 $4,725 $4,725 $4,775 - 0.5%
EGTP & TMI
($0) ($50) ($125) ($225) -
Q4 ‘16 O&M, Net
of EGTP & TMI
$4,850 $4,675 $4,600 $4,550 -2.1%
Cost Savings
($0) ($75) ($150) ($250) -
Q3 2017 O&M $4,850 $4,600 $4,450 $4,300 -3.9%
ExGen Total O&M Cost Reductions EGTP & TMI
30
ExGen’s Strong Free Cash Flow Supports Utility Growth and Debt Reduction
2017-2020 Exelon Generation Free Cash Flow* and Uses of Cash ($B)
(1) Sources include change in margin, tax parent benefit, equity investments, and acquisitions and divestitures
Redeploying Exelon Generation’s free cash flow to maximize shareholder value
($2.3 - $2.7)
($2.8 - $3.2)
(~$1.3)
Committed ExGen Growth CapEx ExGen/HoldCo Debt Reduction
~$6.8
Cumulative ExGen
FCF 2017-2020(1)
Utility Investment
31
Maintaining Strong Investment Grade Credit Ratings is
a Top Financial Priority
Current Ratings(2,3) ExCorp ExGen ComEd PECO BGE ACE DPL Pepco
Moody’s Baa2 Baa2 A1 Aa3 A3 A3 A2 A2
S&P BBB- BBB A- A- A- A A A
Fitch BBB BBB A A A- A- A A-
(1) Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment
(2) Current senior unsecured ratings as of October 24, 2017, for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco
(3) All ratings have a “Stable” outlook
(4) Exelon Corp downgrade threshold (red dotted line) is based on the S&P Exelon Corp Summary Report; represents minimum level to maintain current Issuer Credit Rating of BBB at Exelon Corp
(5) Reflects net book debt (YE debt less cash on hand) / adjusted operating EBITDA*
(6) Reflects removal of EGTP
(7) Reflects delay in Illinois ZEC revenue recognition from 2017 to 2018
ExGen Debt/EBITDA Ratio*(5,6,7) Exelon S&P FFO/Debt %*(1,4,6,7)
Credit Ratings by Operating Company
0%
5%
10%
15%
20%
25%
18%-20%
2017 Target
21%
0.0
1.0
2.0
3.0
4.0
2.6x
3.1x
2017 Target
3.0x
Excluding Non-Recourse
Book
S&P Threshold
32
Theoretical Dividend Affordability from Utility less HoldCo(1,2)
Utility less HoldCo payout ratio falling consistently even as dividend grows
(1) Chart is illustrative and shows theoretical payout ratio if utilities supported 100% of the external dividend and interest expense at HoldCo. Currently, the utilities have a payout ratio of 70% which
covers the majority of the external dividend and interest expense at HoldCo with ExGen covering the remainder.
(2) Board of directors has approved a policy of 2.5% per year dividend increase through 2018. For illustrative purposes only, the chart assumes the dividend continues to increase 2.5% per year
through 2020, although the board has not yet established dividend policy for periods after 2018. Quarterly dividends are subject to declaration by the board of directors.
75%
79%
81%
84%
95%
90%
85%
80%
75%
70%
65%
60%
2020 2019 2018 2017
Utility Earnings Payout Ratio (less HoldCo)
Midpoint of Payout Ratio Range
33
Recognition for Stewardship and Employee Engagement
Supplier Diversity: Exelon is the only utility and energy company to be inducted into the Billion Dollar
Roundtable, which recognizes corporations that have achieved spending of $1 billion with minority and women-
owned suppliers; our 2016 spend was nearly $2B
Civic 50: Points of Light named Exelon utility sector leader in its annual
ranking of the nation’s most community-minded public and
private companies
Top 50 Companies for Diversity: National recognition from DiversityInc,
first year in Top 50 after being named a DiversityInc “Top Utility”
in 2015 and 2016
Best Places to Work in 2017: Ranked No. 18 on Indeed.com survey of Fortune 500 companies based on
employee reviews
CEO Action for Diversity & Inclusion™: Joined 150 leading companies in the largest CEO-driven business
commitment to advance diversity and inclusion
Top 50 Most Energy-Efficient Utilities: American Council for an Energy-Efficient Economy ranks BGE and
ComEd in the top 10 with PECO also making the list
Lowest Carbon Emissions: 2017 Air Emissions Benchmarking Report notes Exelon’s generation fleet had the
lowest carbon dioxide emissions of the top 20 privately held and investor-owned energy producers
HeForShe: In continuing its commitment to gender equality, Exelon joined the United Nations HeForShe
campaign, which provides a platform on which men can engage and become change agents for gender equality
34
Hurricane Support
• More than 2,200 employees, contractors and support personnel from Exelon’s six utilities
mobilized to assist residents in the southeastern U.S. impacted by Hurricane Irma
− Exelon teams shared our experience with severe weather restoration efforts and
industry-leading best practices to lead one of the largest contingents of support
nationally
− Crews deployed for more than two weeks helping to restore power to nearly eight
million customers in Florida and Georgia
• Approximately 250 Exelon employee volunteers logged over 1,300 hours for disaster relief
activities
• Exelon and its employees contributed approximately $820,000 in disaster relief
35
Appendix
36
Exelon Debt Maturity Profile(1)
,594
312
500
910
800 833
500
850
360
763
295
175
1,430
675 700 600 650
1,200
18597
788
350
900
258
1,023
2,512
623
700
750741
833
750
807
1,150
300
900
2027 2026 2025 2024 2023 2019 2018 2017
26
2022 2021
1,189
2020 2041
1,400
2042 2044 2043 2045
1,225 1,275
2046 2047 2038 2040 2039 2036 2037 2035 2034 2033 2032 2031
78
2030 2029
53
2028
PHI Holdco ExCorp EXC Regulated ExGen
Exelon’s weighted average LTD maturity is approximately 14 years
(1) ExGen debt includes legacy CEG debt; Excludes securitized debt and non-recourse debt
As of 9/30/17
($M)
BGE 2.6B
ComEd 7.9B
PECO 3.1B
PHI 5.9B
ExGen 9.5B
HoldCo 6.3B
Consolidated 35.3B
LT Debt Balances (as of 9/30/17)
37
PJM Capacity Revenues(1,2,3)
(1) Revenues reflect capacity cleared in Base, CP transitional
& incremental auctions and are for calendar years
(2) Revenues reflect owned and contracted generation
(3) Reflects 50.01% ownership at CENG
(4) Volumes at ownership and rounded
$1,300
$1,200
$1,100
$1,000
$900
$800
$700
$600
$500
$400
$300
$200
$100
$0
$180
$170
$160
$150
$140
$130
$120
$110
$100
$90
$80
$70
$60
$50
$1,125
2018
$1,300
2017
$1,100
2016
$1,125
2019 2020
$1,000
Revenues ($ Million)
Calendar weighted avg. price ($/Mw-day)
R
e
ve
nu
e
s
($
M
)
C
ap
a
cit
y
P
ri
c
e
(
$
/
M
W
-d
)
Capacity Market: PJM
Cleared Volumes
(MW)(4) CP Price Base Price CP Price
Comed
Nuclear 6,925 $203 - $183 8,075 $188
Fossil/Other - $203 50 $183 - $188
Subtotal 6,925 50 8,075
EMAAC
Nuclear 4,375 $120 - $100 4,350 $188
Fossil/Other 1,525 $120 1,675 $100 2,325 $188
Subtotal 5,900 1,675 6,675
SWMAAC
Nuclear 850 $100 - $80 850 $86
Fossil/Other - $100 - $80 - $86
Subtotal 850 - 850
MAAC
Nuclear - - - $86
Fossil/Other - - 225 $86
Subtotal - - 225
BGE
Nuclear - $100 - $80 - $86
Fossil/Other 375 $100 225 $80 375 $86
Subtotal 375 225 375
Rest of RTO
Nuclear - $100 - $80 - $77
Fossil/Other 275 $100 75 $80 - $77
Subtotal 275 75 -
PJM Total
Nuclear 12,150 - 13,275
Fossil/Other 2,175 2,025 2,925
Grand Total 14,325 2,025 16,200
2019/2020 2020/2021
38
Portfolio Management Strategy
Protect Balance Sheet Ensure Earnings Stability Create Value
Exercising Market Views
%
H
e
d
ge
d
Purely ratable
Actual hedge %
Market views on timing, product
allocation and regional spreads
reflected in actual hedge %
High End of Profit
Low End of Profit
% Hedged
Open Generation
with LT Contracts
Portfolio Management &
Optimization
Portfolio Management Over Time Align Hedging & Financials
Establishing Minimum Hedge Targets
Credit Rating
Capital &
Operating
Expenditure
Dividend
Capital
Structure
39
Components of Gross Margin Categories
Open Gross
Margin
•Generation Gross
Margin at current
market prices,
including ancillary
revenues, nuclear
fuel amortization
and fossils fuels
expense
•Power Purchase
Agreement (PPA)
Costs and
Revenues
•Provided at a
consolidated level
for all regions
(includes hedged
gross margin for
South, West and
Canada(1))
Capacity and ZEC
Revenues
•Expected capacity
revenues for
generation of
electricity
•Expected
revenues from
Zero Emissions
Credits (ZEC)
MtM of
Hedges(2)
•Mark-to-Market
(MtM) of power,
capacity and
ancillary hedges,
including cross
commodity, retail
and wholesale
load transactions
•Provided directly
at a consolidated
level for five major
regions. Provided
indirectly for each
of the five major
regions via
Effective Realized
Energy Price
(EREP), reference
price, hedge %,
expected
generation.
“Power” New
Business
•Retail, Wholesale
planned electric
sales
•Portfolio
Management new
business
•Mid marketing
new business
“Non Power”
Executed
•Retail, Wholesale
executed gas sales
•Energy
Efficiency(4)
•BGE Home(4)
•Distributed Solar
“Non Power”
New Business
•Retail, Wholesale
planned gas sales
•Energy
Efficiency(4)
•BGE Home(4)
•Distributed Solar
•Portfolio
Management /
origination fuels
new business
•Proprietary
trading(3)
Margins move from new business to
MtM of hedges over the course of the
year as sales are executed(5)
Margins move from “Non power new
business” to “Non power executed” over
the course of the year
Gross margin linked to power production and sales
Gross margin from
other business activities
(1) Hedged gross margins for South, West & Canada region will be included with Open Gross Margin; no expected generation, hedge %, EREP or reference prices provided for this region
(2) MtM of hedges provided directly for the five larger regions; MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh
(3) Proprietary trading gross margins will generally remain within “Non Power” New Business category and only move to “Non Power” Executed category upon management discretion
(4) Gross margin for these businesses are net of direct “cost of sales”
(5) Margins for South, West & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin
40
ExGen Disclosures
Gross Margin Category ($M)
(1) 2017 2018 2019
Open Gross Margin
(including South, West & Canada hedged GM)
(2,5) $3,600 $3,900 $3,700
Capacity and ZEC Revenues
(2,5,6) $1,700 $2,300 $2,000
Mark-to-Market of Hedges
(2,3) $2,150 $650 $450
Power New Business / To Go $100 $700 $850
Non-Power Margins Executed $350 $200 $100
Non-Power New Business / To Go $100 $300 $400
Total Gross Margin*
(4,5) $8,000 $8,050 $7,500
Reference Prices
(4) 2017 2018 2019
Henry Hub Natural Gas ($/MMBtu) $3.14 $3.05 $2.89
Midwest: NiHub ATC prices ($/MWh) $26.52 $27.45 $26.36
Mid-Atlantic: PJM-W ATC prices ($/MWh) $28.81 $30.77 $29.22
ERCOT-N ATC Spark Spread ($/MWh)
HSC Gas, 7.2HR, $2.50 VOM
($0.78) $1.22 $2.65
New York: NY Zone A ($/MWh) $24.38 $27.29 $26.67
New England: Mass Hub ATC Spark Spread ($/MWh)
ALQN Gas, 7.5HR, $0.50 VOM
$4.36 $3.99 $4.24
(1) Gross margin categories rounded to nearest $50M
(2) Excludes EDF’s equity ownership share of the CENG Joint Venture
(3) Mark-to-Market of Hedges assumes mid-point of hedge percentages
(4) Based on September 30, 2017, market conditions
(5) Reflects ownership of FitzPatrick as of April 1, 2017, and TMI and Oyster Creek retirements in September 2019 and December 2019, respectively. EGTP removal impacts partial year 2017 and
full year 2018 and 2019.
(6) 2018 includes $150M of IL ZEC revenues associated with 2017 production
41
ExGen Disclosures
(1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions
regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 15 refueling outages in 2017, 15 in 2018, and 11 in 2019
at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 93.4%, 93.2% and 94.7% in 2017, 2018, and 2019, respectively at Exelon-operated nuclear plants, at ownership. These
estimates of expected generation in 2018 and 2019 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years.
(2) Excludes EDF’s equity ownership share of CENG Joint Venture
(3) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. Includes all hedging products, such as wholesale and retail sales of power, options and swaps.
(4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with
our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs, RPM capacity and ZEC revenues, but includes the mark-to-market value of capacity contracted at prices
other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's
energy hedges.
(5) Spark spreads shown for ERCOT and New England
(6) Reflects ownership of FitzPatrick as of April 1, 2017, and TMI and Oyster Creek retirements in September 2019 and December 2019, respectively. EGTP removal impacts partial year 2017 and full year 2018 and 2019.
Generation and Hedges 2017 2018 2019
Exp. Gen (GWh)
(1) 200,200 199,300 202,000
Midwest 95,900 95,800 97,000
Mid-Atlantic
(2,6) 60,700 60,500 59,000
ERCOT 17,800 19,500 20,800
New York
(2,6) 14,700 15,500 16,600
New England 11,100 8,000 8,600
% of Expected Generation Hedged
(3) 98%-101% 79%-82% 45%-48%
Midwest 97%-100% 74%-77% 41%-44%
Mid-Atlantic
(2,6) 98%-101% 90%-93% 51%-54%
ERCOT 97%-100% 77%-80% 44%-47%
New York
(2,6) 99%-102% 71%-74% 43%-46%
New England 103%-106% 86%-89% 52%-55%
Effective Realized Energy Price ($/MWh)
(4)
Midwest $33.00 $29.50 $29.50
Mid-Atlantic
(2,6) $44.00 $37.00 $39.00
ERCOT
(5) $11.00 $3.50 $3.50
New York
(2,6) $41.50 $37.50 $32.00
New England
(5) $20.00 $2.50 $3.00
42
ExGen Hedged Gross Margin* Sensitivities
(1) Based on September 30, 2017, market conditions and hedged position; gas price sensitivities are based on an assumed gas-power relationship derived from an internal model that is
updated periodically; power price sensitivities are derived by adjusting the power price assumption while keeping all other price inputs constant; due to correlation of the various
assumptions, the hedged gross margin impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin impact calculated when correlations between
the various assumptions are also considered; sensitivities based on commodity exposure which includes open generation and all committed transactions; excludes EDF’s equity share of
CENG Joint Venture
Gross Margin* Sensitivities (with existing hedges)
(1) 2017 2018 2019
Henry Hub Natural Gas ($/MMBtu)
+ $1/MMBtu $(20) $140 $515
- $1/MMBtu $(10) $(210) $(500)
NiHub ATC Energy Price
+ $5/MWh - $120 $265
- $5/MWh - $(115) $(265)
PJM-W ATC Energy Price
+ $5/MWh - $10 $150
- $5/MWh $5 $(40) $(145)
NYPP Zone A ATC Energy Price
+ $5/MWh - $25 $40
- $5/MWh - $(20) $(45)
Nuclear Capacity Factor
+/- 1% +/- $10 +/- $35 +/- $35
43
ExGen Hedged Gross Margin* Upside/Risk
6,000
6,500
7,000
7,500
8,000
8,500
9,000
2017 2018 2019
A
p
p
ro
xima
te
G
ro
ss
Margin*
(
$
m
illion
)(
1
,2
,3
)
$8,050
$7,950
$8,250
$7,800
(1) Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold
into the spot market; approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential
modeling changes; these ranges of approximate gross margin in 2018 and 2019 do not represent earnings guidance or a forecast of future results as Exelon has not completed its planning
or optimization processes for those years; the price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of
September 30, 2017
(2) Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions
(3) Reflects ownership of FitzPatrick as of April 1, 2017, and TMI and Oyster Creek retirements in September 2019 and December 2019, respectively. EGTP removal impacts partial year 2017
and full year 2018 and 2019.
$7,050
$8,300
44
Row Item Midwest Mid-Atlantic ERCOT New York New England
South, West &
Canada
(A) Start with fleet-wide open gross margin
(B) Capacity and ZEC
(C) Expected Generation (TWh) 95.8 60.5 19.5 15.5 8.0
(D) Hedge % (assuming mid-point of range) 75.5% 91.5% 78.5% 72.5% 87.5%
(E=C*D) Hedged Volume (TWh) 72.3 55.4 15.3 11.2 7.0
(F) Effective Realized Energy Price ($/MWh) $29.50 $37.00 $3.50 $37.50 $2.50
(G) Reference Price ($/MWh) $27.45 $30.77 $1.22 $27.29 $3.99
(H=F-G) Difference ($/MWh) $2.05 $6.23 $2.28 $10.21 ($1.49)
(I=E*H) Mark-to-Market value of hedges ($ million)(1) $150 $345 $35 $115 ($10)
(J=A+B+I) Hedged Gross Margin ($ million)
(K) Power New Business / To Go ($ million)
(L) Non-Power Margins Executed ($ million)
(M) Non-Power New Business / To Go ($ million)
(N=J+K+L+M) Total Gross Margin*
$200
$300
$8,050 million
$3.9 billion
$6,850
$700
$2.3 billion
Illustrative Example of Modeling Exelon Generation
2018 Gross Margin*
(1) Mark-to-market rounded to the nearest $5 million
45
Additional ExGen Modeling Data
Total Gross Margin Reconciliation (in $M)(1) 2017 2018 2019
Revenue Net of Purchased Power and Fuel Expense*(2,3) $8,575 $8,575 $8,025
Non-cash amortization of intangible assets, net, related to
commodity contracts recorded at fair value at merger date
$50 - -
Other Revenues(4) $(150) $(200) $(200)
Direct cost of sales incurred to generate revenues for certain
Constellation and Power businesses
$(475) $(325) $(325)
Total Gross Margin* (Non-GAAP) $8,000 $8,050 $7,500
(1) All amounts rounded to the nearest $25M
(2) ExGen does not forecast the GAAP components of RNF separately, as to do so would be unduly burdensome. RNF also includes the RNF of our proportionate ownership share of CENG.
(3) Excludes the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices
(4) Other Revenues reflects primarily revenues from Exelon Nuclear Partners, JExel Nuclear JV, variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear
plants through regulated rates, and gross receipts tax revenues
(5) ExGen amounts for O&M, TOTI, Depreciation & Amortization; excludes EDF’s equity ownership share of the CENG Joint Venture
(6) Other reflects Other Revenues excluding gross receipts tax revenues, nuclear decommissioning trust fund earnings from unregulated sites, and the minority interest in ExGen Renewables JV and
Bloom
(7) TOTI excludes gross receipts tax of $125M
(8) Excludes P&L neutral decommissioning depreciation
(9) Interest expense includes impact of reduced capitalized interest due to Texas CCGT plants in service as of May and June of 2017. Capitalized interest will be an additional ~$25M lower in 2018 as
well due to this.
Key ExGen Modeling Inputs (in $M)(1,5) 2017
Other(6) $175
Adjusted O&M* $(4,850)
Taxes Other Than Income (TOTI)(7) $(400)
Depreciation & Amortization(8) $(1,075)
Interest Expense(9) $(400)
Effective Tax Rate 32.0%
46
Appendix
Reconciliation of Non-GAAP
Measures
47
Q3 2016 QTD GAAP EPS Reconciliation
NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.
Three Months Ended September 30, 2016 ExGen ComEd PECO BGE PHI Other Exelon
2016 GAAP Earnings (Loss) Per Share $0.25 $0.04 $0.13 $0.06 $0.18 ($0.13) $0.53
Mark-to-market impact of economic hedging activities (0.06) - - - - - (0.06)
Unrealized gains related to NDT fund investments (0.07) - - - - - (0.07)
Amortization of commodity contract intangibles 0.01 - - - - - 0.01
Merger and integration costs 0.01 - - - - - 0.01
Merger commitments - - - - (0.04) 0.05 0.01
Long-Lived asset impairments 0.01 - - - - - 0.01
Plant retirements and divestitures 0.22 - - - - - 0.22
Cost management program 0.01 - - - - - 0.01
Like-kind exchange tax position - 0.16 - - - 0.05 0.21
CENG noncontrolling interest 0.03 - - - - - 0.03
2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per
Share
$0.41 $0.20 $0.13 $0.06 $0.14 $(0.03) $0.91
48
Q3 2017 QTD GAAP EPS Reconciliation
NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.
Three Months Ended September 30, 2017 ExGen ComEd PECO BGE PHI Other Exelon
2017 GAAP (Loss) Earnings Per Share $0.32 $0.20 $0.12 $0.06 $0.16 ($0.00) $0.85
Mark-to-market impact of economic hedging activities (0.05) - - - - - (0.05)
Unrealized gains related to NDT fund investments (0.07) - - - - - (0.07)
Amortization of commodity contract intangibles 0.01 - - - - - 0.01
Merger and integration costs 0.01 - - - (0.01) - -
Long-lived asset impairments 0.03 - - - - - 0.03
Plant retirements and divestitures 0.08 - - - - - 0.08
Cost management program 0.01 - - - - - 0.01
Reassessment of state deferred income taxes 0.02 - - - - (0.04) (0.02)
Bargain purchase gain (0.01) - - - - - (0.01)
CENG noncontrolling interest 0.02 - - - - - 0.02
2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per
Share
$0.36 $0.19 $0.12 $0.07 $0.15 ($0.04) $0.85
49
Q3 2016 YTD GAAP EPS Reconciliation
NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.
Nine Months Ended September 30, 2016 ExGen ComEd PECO BGE PHI Other Exelon
2016 GAAP Earnings (Loss) Per Share $0.58 $0.32 $0.37 $0.20 ($0.10) $(0.37) $1.00
Mark-to-market impact of economic hedging activities 0.07 - - - - - 0.07
Unrealized gains related to NDT fund investments (0.13) - - - - - (0.13)
Amortization of commodity contract intangibles 0.01 - - - - - 0.01
Merger and integration costs 0.02 - - - 0.04 0.04 0.10
Merger commitments - - - - 0.26 0.17 0.43
Long-lived asset impairments 0.11 - - - - - 0.11
Plant retirements and divestitures 0.37 - - - - - 0.37
Reassessment of state deferred income taxes 0.01 - - - - (0.01) -
Cost management program 0.02 - - - - - 0.03
Like-kind exchange tax position - 0.16 - - - 0.05 0.21
CENG noncontrolling interest 0.04 - - - - - 0.04
2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per
Share
$1.10 $0.48 $0.37 $0.20 $0.20 $(0.11) $2.24
50
Q3 2017 YTD GAAP EPS Reconciliation
Nine Months Ended September 30, 2017 ExGen ComEd PECO BGE PHI Other Exelon
2017 GAAP Earnings (Loss) Per Share $0.51 $0.47 $0.35 $0.24 $0.38 $0.06 $2.01
Mark-to-market impact of economic hedging activities 0.10 - - - - - 0.10
Unrealized gains related to NDT fund investments (0.22) - - - - - (0.22)
Amortization of commodity contract intangibles 0.03 - - - - - 0.03
Merger and integration costs 0.05 - - - (0.01) - 0.04
Merger commitments (0.02) - - - (0.06) (0.06) (0.15)
Long-lived asset impairments 0.31 - - - - - 0.31
Plant retirements and divestitures 0.15 - - - - - 0.15
Reassessment of state deferred income taxes 0.02 - - - - (0.06) (0.04)
Cost management program 0.02 - - - - - 0.03
Like-kind exchange tax position - 0.02 - - - (0.05) (0.03)
Asset retirement obligation - - - - - - -
Tax settlements (0.01) - - - - - (0.01)
Bargain purchase gain (0.25) - - - - - (0.25)
CENG noncontrolling interest 0.08 - - - - - 0.08
2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per
Share
$0.76 $0.50 $0.35 $0.25 $0.31 ($0.12) $2.05
NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.
51
GAAP to Operating Adjustments
• Exelon’s 2017 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following:
− Mark-to-market adjustments from economic hedging activities
− Unrealized gains from NDT fund investments to the extent not offset by contractual accounting as
described in the notes to the consolidated financial statements
− Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at
the ConEdison Solutions and FitzPatrick acquisition dates
− Certain merger and integration costs associated with the PHI and FitzPatrick acquisitions
− Adjustments to reserves for uncertain tax positions related to the deductibility of certain merger
commitments associated with the 2012 CEG and 2016 PHI acquisitions
− Impairments as a result of the ExGen Texas Power, LLC assets held for sale
− Plant retirements and divestitures at Generation
− Non-cash impact of the remeasurement of state deferred income taxes, related to changes in statutory
tax rates and changes in forecasted apportionment
− Costs incurred related to a cost management program
− Certain adjustments related to Exelon’s like-kind exchange tax position
− Non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation
related to the non-regulatory units
− Benefits related to the favorable settlement of certain income tax positions related to PHI's unregulated
business interests
− The excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick
acquisition
− Generation’s noncontrolling interest, primarily related to CENG exclusion items
52
(1) All amounts rounded to the nearest $25M
(2) Calculated using S&P Methodology. Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment.
(3) Reflects impact of operating adjustments on GAAP EBITDA
(4) Includes other adjustments as prescribed by S&P
(5) Reflects present value of net capacity purchases
(6) Reflects present value of minimum future operating lease payments
(7) Reflects after-tax unfunded pension/OPEB
(8) Includes non-recourse project debt
(9) Applies 75% of excess cash against balance of LTD
(10) Reflects removal of EGTP
(11) Reflects delay in Illinois ZEC revenue recognition from 2017 to 2018
YE 2017 Exelon FFO Calculation ($M)
(1,2,10,11)
GAAP Operating Income $3,500
Depreciation & Amortization $3,350
EBITDA $6,850
+/- Non-operating activities and nonrecurring items(3) $450
- Interest Expense ($1,450)
+ Current Income Tax (Expense)/Benefit $325
+ Nuclear Fuel Amortization $1,075
+/- Other S&P Adjustments(4) $350
= FFO (a) $7,600
YE 2017 Exelon Adjusted Debt Calculation ($M)
(1,2,10)
Long-Term Debt (including current maturities) $32,050
Short-Term Debt $1,125
+ PPA Imputed Debt(5) $350
+ Operating Lease Imputed Debt(6) $875
+ Pension/OPEB Imputed Debt(7) $4,100
- Off-Credit Treatment of Debt(8) ($1,725)
- Surplus Cash Adjustment(9) ($600)
+/- Other S&P Adjustments(4) ($650)
= Adjusted Debt (b) $35,525
YE 2017 Exelon FFO/Debt
(1,2)
FFO (a)
= 21%
Adjusted Debt (b)
GAAP to Non-GAAP Reconciliations
53
YE 2017 ExGen Net Debt Calculation ($M)
(1,3)
Long-Term Debt (including current maturities) $8,775
Short-Term Debt $350
- Surplus Cash Adjustment ($300)
= Net Debt (a) $8,825
YE 2017 Book Debt / EBITDA
Net Debt (a)
= 3.1x
Operating EBITDA (b)
(1) All amounts rounded to the nearest $25M
(2) Reflects impact operating adjustments on GAAP EBITDA
(3) Reflects removal of EGTP
(4) Reflects delay in Illinois ZEC revenue recognition from 2017 to 2018
YE 2017 ExGen Operating EBITDA Calculation
($M)
(1,3,4)
GAAP Operating Income $775
Depreciation & Amortization $1,375
EBITDA $2,150
+/- Non-operating activities and nonrecurring items(2) $725
= Operating EBITDA (b) $2,875
GAAP to Non-GAAP Reconciliations
YE 2017 ExGen Net Debt Calculation ($M)
(1,3)
Long-Term Debt (including current maturities) $8,775
Short-Term Debt $350
- Surplus Cash Adjustment ($300)
- Nonrecourse Debt ($1,925)
= Net Debt (a) $6,900
YE 2017 Recourse Debt / EBITDA
Net Debt (a)
= 2.6x
Operating EBITDA (b)
YE 2017 ExGen Operating EBITDA Calculation
($M)
(1,3,4)
GAAP Operating Income $775
Depreciation & Amortization $1,375
EBITDA $2,150
+/- Non-operating activities and nonrecurring items(2) $725
- EBITDA from projects financed by nonrecourse debt ($250)
= Operating EBITDA (b) $2,625
54
GAAP to Non-GAAP Reconciliations
(1) ACE, Delmarva, and Pepco represents full year of earnings
Q3 2017 Operating ROE Reconciliation ($M)(1) ACE Delmarva Pepco
Legacy
EXC
Consolidated
EU
Net Income (GAAP)
(1)
$85 $114 $210 $1,281 $1,690
Operating Exclusions
($23) ($12) ($25) $34 ($25)
Adjusted Operating Earnings
(1)
$63 $103 $185 $1,315 $1,665
Average Equity
$1,061 $1,323 $2,419 $12,750 $17,554
Operating ROE (Adjusted Operating Earnings/Average Equity) 5.9% 7.8% 7.7% 10.3% 9.5%
Q2 2017 Operating ROE Reconciliation ($M)(1) ACE Delmarva Pepco
Legacy
EXC
Consolidated
EU
Net Income (GAAP)
(1)
$91 $127 $203 $1,132 $1,548
Operating Exclusions
($25) ($32) ($29) $186 $105
Adjusted Operating Earnings
(1)
$66 $95 $174 $1,318 $1,653
Average Equity
$1,039 $1,300 $2,390 $12,308 $17,038
Operating ROE (Adjusted Operating Earnings/Average Equity) 6.4% 7.3% 7.3% 10.7% 9.7%
55
GAAP to Non-GAAP Reconciliations
2017-2020 ExGen Free Cash Flow Calculation ($M)(1)
Cash from Operations (GAAP)
$15,150
Other Cash from Investing and Activities
($650)
Baseline Capital Expenditures
(4)
($4,025)
Nuclear Fuel Capital Expenditures ($3,625)
Free Cash Flow before Growth CapEx and Dividend $6,825
ExGen Adjusted O&M Reconciliation ($M)(1) 2017 2018 2019 2020
GAAP O&M $6,325 $5,300 $5,150 $5,025
Decommissioning(2) 25 50 50 50
TMI Retirement (75) - - -
EGTP Impairment (450) - - -
Direct cost of sales incurred to generate revenues for certain Constellation and Power
businesses(3)
(425) (325) (325) (325)
O&M for managed plants that are partially owned (425) (425) (400) (425)
Other (125) (25) (25) (25)
Adjusted O&M (Non-GAAP) $4,850 $4,600 $4,450 $4,300
(1) All amounts rounded to the nearest $25M. Items may not sum due to rounding.
(2) Reflects earnings neutral O&M
(3) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin*
(4) Baseline capital expenditures refer to maintenance and required capital expenditures necessary for day-to-day plant operations and includes merger commitments
• ExGen’s effective tax rate declines due to its
declining pre-tax income relative to the tax credits it
generates, which remain relatively constant
• Exelon’s consolidated tax rate remains reasonably
constant as growing earnings from the Utilities at a
higher effective tax rate offset the declining tax rate
at ExGen
Tax Rate and Utility Asset Projections at Current Plan
1
Tax Rate Expectations(1)
2018 2019 2020
ExGen Tax Rate 33% 28% 27%
Consolidated Tax Rate 34% 33% 34%
Consol. Cash Tax Rate 1% 6% 28%
Exelon Utilities Asset Projections ($B)(2)
2018 2019 2020
Rate Base 36.6 38.6 40.8
Deferred Tax Liabilities 14.4 15.2 15.7
Key Highlights
Key Highlights
• Deferred tax liabilities are growing at a slowing rate
through 2020 as percentage of new investment
impacted by bonus depreciation declines
Note: tax rates and liabilities are based on the current tax code before the effect of any reforms that may be adopted
(1) Rounded to the nearest 1%
(2) All numbers reflect year-end 2016