Earnings Conference Call 2 Quarter 2013 July 31 , 2013 Exhibit 99.2 nd st |
Cautionary Statements Regarding Forward-Looking Information 1 2013 2Q Earnings Release Slides 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, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon Generation Company, LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2012 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 19; (2) Exelon’s First Quarter 2013 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 17; and (3) 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. 2013 2Q Earnings Release Slides |
• Current 5-year plan includes $16B of growth CapEx (~$13.5B at Utilities) • Installed 99 MW at AVSR YTD with another 102 MW to come on line in 2013 • Adding 46 MW to wind portfolio in 2014 with the Beebe 1B project • Continued smart meter installation at PECO, BGE and ComEd • 2Q13 nuclear capacity factor of 92.8% and YTD 2013 capacity factor of 94.6% • Entered into agreement with EDF to operate the CENG plants • Dispatch match rate for fossil and hydro fleet of 99.1% and energy capture rate for wind and solar fleet of 92.4% • Top decile safety performance for ComEd, PECO and BGE • SB9 was enacted clarifying language in EIMA. ComEd made annual filing for distribution with ICC • BGE filed a rate case in May with the MDPSC • Engaged in PJM stakeholder process around RPM • Delivered 2Q earnings within our guidance range • Canceled LaSalle and Limerick EPU projects • On track to achieve $550M of annual run-rate merger synergies by 2014 • Identified additional O&M savings at ExGen 2013 2Q Earnings Release Slides 2 2Q13 In Review 2013 Expectations: • Deliver 3Q13 operating earnings within guidance range of $0.60 - $0.70/share (1) • On-track to achieve full-year operating earnings within guidance range of $2.35 - $2.65/share (1) as disclosed on 4Q12 earnings call (1) Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. Financial Discipline Operational Excellence Opportunistic Growth & Investment Regulatory Advocacy AVSR = Antelope Valley Solar Ranch. EIMA = Energy Infrastructure Modernization Act. EPU = Extended Power Uprate. ICC = Illinois Commerce Commission. MDPSC = Maryland Public Service Commission. O&M = Operating & Maintenance. RPM = Reliability Pricing Model. |
RPM Results 3 Coal Fired Gen-BRA Offers (2) (GW) % of Unforced Capacity Procured by Type (1) 16/17 59 49 15/16 59 54 14/15 65 56 13/14 67 65 2 Cleared Uncleared RPM Clearing Trends (1) Sources: (1) PJM RPM Base Residual Auction Results Reports (2) RPM Commitments by Fuel Type by DY (2) Estimated based on PY 16/17 PJM Base Residual Auction Results. Includes imports. For comparability, PJM geographical additions included by adding initial BRA offered and cleared quantities to previous years. Total GW • Decrease in existing coal-fired generation • 6.3 GW of coal retirements in 2012 alone • 10 GW in the PJM deactivation queue for 2013 - 2015 • Internal estimate: ~ 22 GW for 2012 - 2016 • Increase in planned gas-fired generation • Increase in cleared GW of Energy Efficiency (EE), Demand Response (DR), and Imports 95% 85% 90% 100% 80% 0% 169 79% 9% 12% 15/16 165 84% 16/17 14/15 150 87% 1% 5% 153 90% 1% 9% 13/14 Existing Gen as of 13/14 (incl. Wind) Cumulative New/Gen Uprates since 13/14 Cleared EE, DR and Imports Combined Recommended Reserve Margin (~15.6%) 12% 12% 9 5 10 2013 2Q Earnings Release Slides BRA = Base Residual Auction. RPM = Reliability Pricing Model. PY = Plan Year. Notes: (1) PY 13/14 includes ATSI (2) PY 14/15 includes Duke (3) PY 15/16 includes significant portion of AEP and DEOK zone load previously under FRR alternative (4) PY 16/17 includes EKPC (5) PY 13/14 is base year for cumulative New Gen and Uprates |
Hedging Activity and Market Fundamentals 4 2013 2Q Earnings Release Slides Fundamental View vs. Market - 2015 % of Expected Generation Hedged (1) - Total Portfolio (1) Mid-point of disclosed hedge % range was used $60 $55 $50 $45 $40 $35 $15 1Q13 3Q12 1Q12 3Q11 1Q11 2Q13 1Q13 4Q12 3Q12 2015-Ratable 2015-Actual 2015-Actual (excl NG hedges) Market PJMW Fundamental View PJMW Market NiHub Fundamental View NiHub 50% 45% 40% 35% 30% 25% 15% 20% • Structural changes in the stack are expected to increase volatility in the spot energy market and drive prices higher than current market • Continue to see a disconnect in forward heat rates compared to our fundamental forecast given current natural gas prices, expected retirements, new generation resources, and load assumptions • We align our hedging strategies with our fundamental views • We have widened our deviation from ratable across our entire portfolio over the past 6 months to approximately 8% • Use of natural gas as a cross-commodity hedge leaves more upside to heat rate expansion Market Fundamentals Impacts of our view on our hedging activity 2013 2Q Earnings Release Slides |
Exelon Generation: Gross Margin Update June 30, 2013 Delta to March 31, 2013 Gross Margin Category ($M) (1) (2) 2013 2014 2015 2013 2014 2015 Open Gross Margin (3) (including South, West, Canada hedged gross margin) 5,750 5,700 5,900 (250) (650) (500) Mark-to-Market of Hedges (3,4) 1,450 850 400 250 450 150 Power New Business / To Go 200 550 750 (150) (50) (50) Non-Power Margins Executed 350 150 50 50 50 0 Non-Power New Business / To Go (5) 250 450 550 (50) (50) 0 Total Gross Margin 8,000 7,700 7,650 (150) (250) (400) Key Changes in 2Q 2013 • 2013: AVSR delays; $50M due to FTR under collection; and $50M due to lower power new business targets • 2014: power new business targets • 2015: power new business targets • Reducing 2013 ExGen O&M by $100M ($50M at Constellation to offset lower new business targets) and targeting reductions in 2014 and 2015 to result in a roughly flat O&M CAGR for 2013 - 2015 2013 2Q Earnings Release Slides Retail & Wholesale Load (TWh) 30-40% 60-70% 150 155 2013E 25-35% 155 2015E 2014E 25-35% Wholesale Load Total Contracted Retail Load 65-75% 65-75% Numbers and percentages are rounded to the nearest 5. Index load expected to be 20% to 30% of total forecasted retail load. 5 Reduction of $50M due to unplanned nuclear outages and $350M reduction due to prices and $50M reduction in $200M reduction due to prices and $50M reduction in 1) Gross margin rounded to nearest $50M. 2) Gross margin does not include revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners and entities consolidated solely as a result of the application of FIN 46R. 3) Includes CENG Joint Venture. 4) Mark to Market of Hedges assumes mid-point of hedge percentages. 5) Any changes to new business estimates for our non-power business are presented as revenue less costs of sales. 200 150 100 50 0 FTR = Financial Transmission Rights. CAGR = Compound Annual Growth Rate. |
Key Financial Messages 6 2013 2Q Earnings Release Slides • Delivered non-GAAP operating earnings in 2Q of $0.53/share within guidance range provided of $0.50 - $0.60/share 2Q 2013 vs. Guidance • Reduction of wholesale new business targets and unplanned nuclear outages • Favorable impacts of SB9 at ComEd Full Year 2013 vs. Guidance • Reduction of wholesale new business targets • Reduction of 2013 ExGen O&M by $100M • Favorable load at ComEd and PECO • Lower ExGen effective tax rate • Favorable interest related to tax positions • Favorable impacts of SB9 at ComEd • Lower depreciation and other favorable items at ExGen $0.32 $0.11 $0.09 $0.53 ($0.01) $0.03 HoldCo ExGen ComEd PECO BGE 2013 2Q Results Expect 3Q 2013 earnings of $0.60 - $0.70/share and re-affirm full year guidance range of $2.35-$2.65/share 2013 2Q Earnings Release Slides (1) (1) Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. Numbers may not add due to rounding. SB9 = Senate Bill 9. |
ExGen Operating EPS Contribution 7 2013 2Q Earnings Release Slides $0.47 $0.32 2Q 2013 2012 (excludes Salem and CENG) 2Q12 Actual 2Q13 Actual Planned Refueling Outage Days 51 47 Non-refueling Outage Days 16 31 Nuclear Capacity Factor 93.4% 92.8% Lower RNF, primarily due to lower realized energy prices, lower capacity pricing and decreased load volumes: $(0.15) Increased depreciation expense related to ongoing capital expenditures: $(0.01) Lower O&M costs, primarily due to merger synergies, offset in part by timing of Salem nuclear refueling outage costs: $0.01 Lower income tax, primarily driven by AVSR investment tax credit benefits: $0.01 (1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. Key Drivers – 2Q13 vs. 2Q12 (1) RNF = Revenue Net Fuel. |
Exelon Utilities Operating EPS Contribution 8 2013 2Q Earnings Release Slides 2Q 2013 2Q 2012 $0.05 $0.11 $0.09 $0.16 $0.10 $0.02 $0.03 $0.22 BGE PECO ComEd Weather (2) : $(0.02) Higher distribution revenue due to higher allowed ROE (2) : $0.01 Impact of Senate Bill 9: $0.01 Discrete impacts of the May 2012 distribution formula rate order under EIMA (3) : $0.07 Higher O&M costs, primarily due to inflation: $(0.01) Preferred securities redemption: $(0.01) Lower income tax, primarily due to gas distribution tax repairs deduction: $0.01 Electric and gas distribution rates: $0.02 PECO (-0.01): BGE (+0.01): ComEd: (+0.06) Key Drivers – 2Q13 vs. 2Q12 (1): Numbers may not add due to rounding. (1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. (2) Due to the distribution formula rate, changes in ComEd’s earnings are driven primarily by changes in 30-year U.S. Treasury rates (allowed ROE), rate base and capital structure in addition to weather, load and changes in customer mix. (3) Energy Infrastructure Modernization Act |
2013 Projected Sources and Uses of Cash (1) Exelon beginning cash balance as of 1/1/13. Excludes counterparty collateral activity. (2) Cash Flow from Operations primarily includes net cash flows provided by operating activities and net cash flows used in investing activities other than capital expenditures. (3) Dividends are subject to declaration by the Board of Directors. (4) Includes PECO’s $210 million Accounts Receivable (A/R) Agreement with Bank of Tokyo and excludes BGE’s current portion of its rate stabilization bonds (5) “Other” includes proceeds from options, redemption of PECO preferred stock and expected changes in short-term debt. (6) Includes cash flow activity from Holding Company, eliminations, and other corporate entities. 9 2013 2Q Earnings Release Slides |
10 Exelon Generation Disclosures June 30, 2013 2013 2Q Earnings Release Slides 2013 2Q Earnings Release Slides |
11 Portfolio Management Strategy Protect Balance Sheet Ensure Earnings Stability Create Value Exercising Market Views 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 2013 2Q Earnings Release Slides • Aligns hedging program with financial policies and financial outlook • Establish minimum hedge targets • Hedge enough commodity risk to • Ensure stability in near-term cash • Disciplined approach to hedging • Tenor aligns with customer • Multiple channels to market that • Large open position in outer years • Ability to exercise fundamental market views to create value within the ratable framework • Modified timing of hedges versus • Cross-commodity hedging (heat • Delivery locations, regional and Strategic Policy Alignment Three-Year Ratable Hedging Bull / Bear Program Credit Rating Capital Structure Capital & Operating Expenditure Dividend to meet financial objectives of the company (dividend, credit rating) meet future cash requirements under a stress scenario flows and earnings preferences and market liquidity allow us to maximize margins to benefit from price upside purely ratable rate positions, options, etc.) zonal spread relationships 2013 2Q Earnings Release Slides |
12 Components of Gross Margin Categories Margins move from new business to MtM of hedges over the course of the year as sales are executed 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 2013 2Q Earnings Release Slides Hedged gross margins for South, West and Canada region will be included with Open Gross Margin, and no expected generation, hedge %, EREP or reference prices provided for this region. Proprietary trading gross margins will remain within “Non Power” New Business category and not move to “Non Power” Executed category. (1) (2) (3) 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. Open Gross Margin MtM of Hedges (2) “Power” New Business “Non Power” Executed “Non Power” New Business •Generation Gross Margin at current market prices, including capacity and ancillary revenues, nuclear fuel amortization and fossils fuels expense •Exploration and Production •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) ) •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 •Retail, Wholesale planned electric sales •Portfolio Management new business •Mid marketing new business •Retail, Wholesale executed gas sales •Load Response •Energy Efficiency •BGE Home •Distributed Solar •Retail, Wholesale planned gas sales •Load Response •Energy Efficiency •BGE Home •Distributed Solar •Portfolio Management / origination fuels new business •Proprietary trading (3) 2013 2Q Earnings Release Slides |
ExGen Disclosures Gross Margin Category ($M) (1,2) 2013 2014 2015 Open Gross Margin (including South, West & Canada hedged GM) (3) $5,750 $5,700 $5,900 Mark to Market of Hedges (3,4) $1,450 $850 $400 Power New Business / To Go $200 $550 $750 Non-Power Margins Executed $350 $150 $50 Non-Power New Business / To Go (5) $250 $450 $550 Total Gross Margin $8,000 $7,700 $7,650 Reference Prices (6) 2013 2014 2015 Henry Hub Natural Gas ($/MMbtu) $3.68 $3.91 $4.14 Midwest: NiHub ATC prices ($/MWh) $31.00 $29.90 $31.04 Mid-Atlantic: PJM-W ATC prices ($/MWh) $37.76 $37.26 $38.53 ERCOT-N ATC Spark Spread ($/MWh) HSC Gas, 7.2HR, $2.50 VOM $4.93 $7.90 $8.76 New York: NY Zone A ($/MWh) $36.82 $35.40 $36.22 New England: Mass Hub ATC Spark Spread($/MWh) ALQN Gas, 7.5HR, $0.50 VOM $3.03 $4.59 $3.02 2013 2Q Earnings Release Slides 13 (1) Gross margin rounded to nearest $50M. (2) Gross margin does not include revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners and entities consolidated solely as a result of the application of FIN 46R. (3) Includes CENG Joint Venture. (4) Mark to Market of Hedges assumes mid-point of hedge percentages. (5) Any changes to new business estimates for our non-power business are presented as revenue less costs of sales. (6) Based on June 30, 2013 market conditions. |
14 ExGen Disclosures Generation and Hedges 2013 2014 2015 Exp. Gen (GWh) (1) 215,500 214,400 207,600 Midwest 97,200 97,100 96,400 Mid-Atlantic (2) 74,200 72,600 69,900 ERCOT 14,600 17,800 18,500 New York (2) 14,100 12,100 9,300 New England 15,400 14,800 13,500 % of Expected Generation Hedged (3) 96-99% 78-81% 41-44% Midwest 95-98% 77-80% 38-41% Mid-Atlantic (2) 97-100% 82-85% 48-51% ERCOT 102-105% 77-80% 34-37% New York (2) 96-99% 81-84% 45-48% New England 97-100% 71-74% 23-26% Effective Realized Energy Price ($/MWh) (4) Midwest $37.00 $34.00 $34.00 Mid-Atlantic (2) $49.00 $46.00 $46.50 ERCOT (5) $11.50 $9.00 $7.50 New York (2) $32.00 $37.00 $44.00 New England (5) $5.50 $3.50 $3.50 2013 2Q Earnings Release Slides (1) Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity. Expected generation is 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 12 refueling outages in 2013 and 14 refueling outages in 2014 and 2015 at Exelon-operated nuclear plants, Salem and CENG. Expected generation assumes capacity factors of 93.8%, 93.8%, and 93.3% in 2013, 2014 and 2015 at Exelon-operated nuclear plants excluding Salem and CENG. These estimates of expected generation in 2014 and 2015 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2) Includes 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. Uses expected value on options. (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 and RPM capacity revenue, 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. 2013 2Q Earnings Release Slides |
15 ExGen Hedged Gross Margin Sensitivities Gross Margin Sensitivities (With Existing Hedges) (1, 2) 2013 2014 2015 Henry Hub Natural Gas ($/Mmbtu) $35 $190 $430 $(20) $(130) $(370) NiHub ATC Energy Price $10 $130 $355 $(5) $(125) $(350) PJM-W ATC Energy Price $0 $75 $205 $5 $(75) $(200) NYPP Zone A ATC Energy Price $0 $10 $25 $0 $(10) $(25) Nuclear Capacity Factor (3) +/- 1% +/- $20 +/- $40 +/- $45 2013 2Q Earnings Release Slides (1) Based on June 30, 2013 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 prices sensitivities are derived by adjusting the power price assumption while keeping all other prices 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. (2) Sensitivities based on commodity exposure which includes open generation and all committed transactions. (3) Includes CENG Joint Venture. + $1/Mmbtu - $1/Mmbtu + $5/MWh - $5/MWh + $5/MWh - $5/MWh + $5/MWh - $5/MWh 2013 2Q Earnings Release Slides |
16 Exelon Generation Hedged Gross Margin Upside/Risk $6,000 $6,500 $7,000 $7,500 $8,000 $8,500 $9,000 $9,500 $10,000 2015 $8,700 2014 $8,150 2013 $8,150 $7,850 $7,250 $6,750 (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 2014 and 2015 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 June 30, 2013 (2) Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions. 2013 2Q Earnings Release Slides |
17 Illustrative Example of Modeling Exelon Generation 2014 Gross Margin Row Item Midwest Mid- Atlantic ERCOT New York New England South, West & Canada (A) Start with fleet-wide open gross margin $5.70 billion (B) Expected Generation (TWh) 97.1 72.6 17.8 12.1 14.8 (C) Hedge % (assuming mid-point of range) 78.5% 83.5% 78.5% 82.5% 72.5% (D=B*C) Hedged Volume (TWh) 76.2 60.6 14.0 10.0 10.7 (E) Effective Realized Energy Price ($/MWh) $34.00 $46.00 $9.00 $37.00 $3.50 (F) Reference Price ($/MWh) $29.90 $37.26 $7.90 $35.40 $4.59 (G=E-F) Difference ($/MWh) $4.10 $8.74 $1.10 $1.60 $(1.09) (H=D*G) Mark-to-market value of hedges ($ million) (1) $315 million $530 million $15 million $15 million $(10) million (I=A+H) Hedged Gross Margin ($ million) $6,550 million (J) Power New Business / To Go ($ million) $550 million (K) Non-Power Margins Executed ($ million) $150 million (L) Non- Power New Business / To Go ($ million) $450 million (N=I+J+K+L) Total Gross Margin $7,700 million (1) Mark-to-market rounded to the nearest $5 million. 2013 2Q Earnings Release Slides |
18 Additional Disclosures 2013 2Q Earnings Release Slides |
BGE 2013 load growth largely driven by the idling of RG Steel and energy efficiency partially offset by improving economic conditions 19 Exelon Utilities Weather-Normalized Load 2013E 0.4% 0.2% 2012 0.2% -0.6% -0.1% Large C&I Small C&I Residential All Customers Notes: Data is not adjusted for leap year. Source of 2013 economic outlook data is Global Insight (May 2013). Assumes 2013 GDP of 1.8% and U.S unemployment of 7.6%. ComEd has the ROE collar as part of the distribution formula rate and BGE is decoupled which mitigates the load risk. QTD and YTD actual data can be found in earnings release tables. BGE amounts have been adjusted for unbilled / true-up load from prior quarters. ComEd 2013 load growth is similar to 2012, driven by improving economic conditions & positive residential load growth partially offset by energy efficiency 2013E 1.7% 0.5% 2012 -2.3% -2.2% PECO 2013 load growth driven by oil refinery and economic conditions & customer growth, offset by energy efficiency 2013E -2.5% -1.0% 2012 -2.8% -1.5% Chicago GMP 1.7% Chicago Unemployment 9.4% Philadelphia GMP 1.7% Philadelphia Unemployment 7.9% Baltimore GMP 1.8% Baltimore Unemployment 7.3% 2013 2Q Earnings Release Slides 0.8% -0.3% -0.6% 0.4% -1.7% -2.7% -2.3% -2.1% -0.2% 0.4% 0.9% |
20 Exelon Utilities Rate Base and ROE Targets 2013E Long-Term Target Equity Ratio ~50% ~53% (3) Earned ROE 7-8% 2013E Long-Term Target Equity Ratio ~46% ~53% (1) Earned ROE 8 -9% Continued investment in Utilities will provide stable earnings growth Based on 30-yr. US Treasury (2) ($ in billions) $1.1 $0.7 $1.1 2012 $5.1 $3.3 $0.7 $5.9 $3.9 2015E $1.3 $0.7 $1.2 2013E $5.3 $3.5 2014E $5.7 $3.8 $0.7 Electric Distribution Electric Transmission Gas Delivery $2.1 $7.6 $2.7 2014E $8.7 $7.1 $2.3 2013E $9.4 $6.6 $10.3 $6.4 2015E $8.5 $2.1 2012 Transmission Distribution $5.1 $3.2 $0.6 $4.4 $0.7 $1.1 $1.2 2013E $3.0 2014E $0.6 $1.0 $2.8 $4.7 2012 $5.3 2015E $1.2 $3.3 $0.8 Electric Distribution Gas Delivery Electric Transmission 10% All rate base amounts are presented as year-end rate base. (1) Exelon Utilities sets first quartile goals. The timing of the achievement of each goal will depend upon specific jurisdictional nuances to each company and how they impact the desired structure. The current distribution equity ratio for ComEd is ~46% and ComEd will look to grow this ratio over time. Currently, ComEd's Transmission capital ratio is limited to 55%. (2) Earned ROE will reflect the weighted average of 11.5% allowed transmission ROE and distribution ROE resulting from 30-year Treasury plus 580 basis points for each calendar year. (3) Per MDPSC merger commitment, BGE is precluded from paying dividends through 2014. Per MDPSC orders, BGE cannot pay out a dividend to its parent company if said dividend would cause BGE’s equity ratio to fall below 48% or if BGE is downgraded by two of three rating agencies. 2013E Long-Term Target Equity Ratio ~55% ~53% Earned ROE 11.5 – 12.5% 10% 2013 2Q Earnings Release Slides |
2013 2Q Earnings Release Slides 21 ComEd May 2013 Distribution Formula Rate Updated Filing Note: Disallowance of any items in the 2013 distribution formula rate filing could impact 2013 earnings in the form of a regulatory asset adjustment. Docket # 13-0318 Filing Year Reconciliation Year Common Equity Ratio ROE Rate Base Revenue Requirement Increase Timeline The 2013 distribution formula rate filing establishes the net revenue requirement used to set the rates that will take effect in January 2014 after the ICC’s review. The filing was updated to reflect the impact of Senate Bill 9. There are two components to the annual distribution formula rate filing: Filing Year: Based on prior year costs (2012) and current year (2013) projected plant additions. Annual Reconciliation: For the prior calendar year (2012), this amount reconciles the revenue requirement reflected in rates during the prior year (2012) in effect to the actual costs for that year. The annual reconciliation impacts cash flow in the following year (2014) but the earnings impact has been recorded in the prior year (2012) as a regulatory asset. 04/29/13 Filing Date 240 Day Proceeding ICC order by year end; rates effective January 2014 2012 Calendar Year Actual Costs and 2013 Projected Net Plant Additions are used to set the rates for calendar year 2014. Rates currently in effect (docket 12-0321) for calendar year 2013 were based on 2011 actual costs and 2012 projected net plant additions. Reconciles Revenue Requirement reflected in rates during 2012 to 2012 Actual Costs Incurred. Revenue Requirement for 2012 is based on dockets 10-0467, 11-0721 May Order and 11-0721 October Re-hearing Order. ~ 45% for both the filing and reconciliation year 8.27% for both the filing and reconciliation year (2012 30-yr Treasury Yield of 2.92% + 580 basis point risk premium). For 2013 and 2014, the actual allowed ROE reflected in net income will ultimately be based on the average of the 30-year Treasury Yield during the respective years plus 580 basis point spread. ~7% For the both the filing and reconciliation Year $6,717 million $359M capital additions). 2013 and 2014 earnings will reflect 2013 and 2014 year-end rate base respectively. - Reconciliation year (represents year-end ate base for 2012) $6,390 million ($165M is due to the 2012 reconciliation, $194M relates to the filing year). The 2012 reconciliation impact on net income was recorded in 2012 as a regulatory asset. This increase also reflects the decrease in 2013 rates as a result of Senate Bill 9. Filing year (represents projected year-end rate base using 2012 actual plus 2013 projected Requested Rate of Return Given the retroactive ratemaking provision in the EIMA legislation, ComEd net income during the year will be based on actual costs with a regulatory asset/liability recorded to reflect any under/over recovery reflected in rates. Revenue Requirement in rate filings impacts cash flow. |
22 BGE Rate Case Rate Case Request Electric Gas Docket # 9326 Test Year August 2012 – July 2013 Common Equity Ratio 49.8% Requested Returns ROE: 10.5%; ROR: 7.75% ROE: 10.35%; ROR: 7.67% Rate Base (adjusted) $2.8B $1.1B Revenue Requirement Increase $101.5M $29.7M Proposed Distribution Increase as % of overall bill 3% 4% Timeline •5/17/13: BGE filed application with the MDPSC seeking increases in gas & electric distribution base rates •8/5/13: Staff/Intervenors file direct testimony •8/23/13: Update 8 months actual/4 month estimated test period data with actuals for last 4 months (March - July 2013) •9/17/13: BGE and staff/intervenors file rebuttal testimony •10/3/13: Staff/Intervenors and BGE file surrebuttal testimony •10/15/13 – 10/29/13: Hearings •11/12/13: Initial Briefs •11/22/13: Reply Briefs •12/13/13: Final Order •New rates are in effect shortly after the final order 2013 2Q Earnings Release Slides |
2Q GAAP EPS Reconciliation Three Months Ended June 30, 2013 ExGen ComEd PECO BGE Other Exelon 2013 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.32 $0.11 $0.09 $0.03 $(0.01) $0.53 Mark-to-market impact of economic hedging activities 0.30 - - - (0.01) 0.30 Unrealized gains related to NDT fund investments (0.03) - - - - (0.03) Constellation merger and integration costs (0.01) - (0.00) (0.00) - (0.02) Amortization of commodity contract intangibles (0.13) - - - - (0.13) Amortization of the fair value of certain debt 0.00 - - - - 0.00 Long-lived asset impairment (0.07) - - - (0.01) (0.08) 2Q 2013 GAAP Earnings (Loss) Per Share $0.38 $0.11 $0.08 $0.03 $(0.03) $0.57 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 June 30, 2012 ExGen ComEd PECO BGE Other Exelon 2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.47 $0.05 $0.10 $0.02 $(0.02) $0.61 Mark-to-market impact of economic hedging activities 0.14 - - - 0.00 0.15 Unrealized losses related to NDT fund investments (0.02) - - - - (0.02) Plant retirements and divestitures 0.00 - - - - 0.00 Constellation merger and integration costs (0.07) - (0.00) (0.00) (0.01) (0.08) Amortization of commodity contract intangibles (0.33) - - - - (0.33) Amortization of the fair value of certain debt 0.00 - - - - 0.00 Non-cash remeasurement of deferred income taxes - - - - 0.00 0.00 2Q 2012 GAAP Earnings (Loss) Per Share $0.19 $0.05 $0.09 $0.01 $(0.02) $0.33 2013 2Q Earnings Release Slides 23 |
2Q YTD GAAP EPS Reconciliation Six Months Ended June 30, 2013 ExGen ComEd PECO BGE Other Exelon 2013 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.71 $0.22 $0.23 $0.11 $(0.03) $1.23 Mark-to-market impact of economic hedging activities 0.02 - - - 0.00 0.02 Unrealized gains related to NDT fund investments 0.02 - - - - 0.02 Plant retirements and divestitures 0.02 - - - - 0.02 Constellation merger and integration costs (0.05) - (0.00) 0.00 (0.00) (0.05) Amortization of commodity contract intangibles (0.28) - - - - (0.27) Amortization of the fair value of certain debt 0.01 - - - - 0.01 Remeasurement of like kind exchange tax position - (0.20) - - (0.11) (0.31) Long lived asset impairment (0.09) - - - (0.01) (0.10) YTD 2013 GAAP Earnings (Loss) Per Share $0.36 $0.02 $0.23 $0.12 $(0.15) $0.57 Six Months Ended June 30, 2012 ExGen ComEd PECO BGE Other Exelon 2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $1.03 $0.17 $0.23 $0.04 $(0.03) $1.44 Mark-to-market impact of economic hedging activities 0.20 - - - 0.01 0.21 Unrealized gains related to NDT fund investments 0.02 - - - - 0.02 Plant retirements and divestitures (0.01) - - - - (0.01) Constellation merger and integration costs (0.13) (0.00) (0.01) (0.00) (0.09) (0.23) Maryland commitments (0.03) - (0.11) (0.16) (0.29) Amortization of commodity contract intangibles (0.46) - - - - (0.46) Amortization of the fair value of certain debt 0.00 - - - - 0.00 FERC Settlement (0.22) - - - - (0.22) Non-cash remeasurement of deferred income taxes 0.02 - - - 0.14 0.16 Other acquisition costs (0.00) - - - - (0.00) YTD 2012 GAAP Earnings (Loss) Per Share $0.43 $0.17 $0.22 (0.07) $(0.13) $0.62 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. 2013 2Q Earnings Release Slides 24 |
GAAP to Operating Adjustments 2013 2Q Earnings Release Slides • Exelon’s 2013 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following: Mark-to-market adjustments from economic hedging activities Unrealized gains and losses from NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements Financial impacts associated with the sale or retirement of generating stations Certain costs incurred associated with the Constellation merger and integration initiatives Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date Non-cash amortization of certain debt recorded at fair value at the merger date, which was retired in the second quarter of 2013 Non-cash charge to earnings resulting from the remeasurement of Exelon’s like-kind exchange tax position Non-cash charge to earnings related to the cancellation of previously capitalized nuclear uprate projects and the impairment of an investment in a long term lease. Other unusual items 25 |