Exhibit 99.3

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, 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 2013 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 22; (2) Exelon’s First Quarter 2014 Quarterly Report on Form 10-Q (to be filed on April 30, 2014) 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 15; 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 presentation. 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.

Exelon Corporation First Quarter 2014 Earnings

Comments from Constellation CEO Joseph Nigro and Exelon CFO Jonathan W. Thayer

Mr. Nigro’s Comments, as Prepared for Delivery:

My comments will address market events during the first quarter and what they mean for our commercial business going forward, some capacity market updates, our updated fundamental view and hedging strategy. In addition, I’ll cover our updated hedge disclosures.

Market Overview – Slide 3

The energy markets experienced a very volatile first quarter, driven by extremely cold weather, I’ll address some of the impacts from these events and what we could see as a result.

While some of these statistics are not new to many you, I want to set the context for just how extreme this winter was.

We successfully managed this volatile environment, where generation availability is of utmost importance and fixed price load obligations can prove to be extremely difficult to manage. Our strategy, and one of the reasons for our merger with Constellation, is to have a balanced portfolio of generation and load. This strategy is beneficial because our baseload nuclear fleet provides a reliable source of generation through all market conditions because of its firm fuel on site, while our dispatchable fleet helps us manage our load obligations throughout peaking periods.

For instance, our approximately two gigawatts of oil or dual-fuel plants in PJM provide value during extreme peaking periods from an energy and ancillary perspective. Load is an excellent channel to market with benefits ranging from incremental margin to offsetting collateral requirements, but comes with significant risks when markets turn volatile, as they did this past quarter. Not only is there significant energy price risk, but there are ancillary cost risks as well. Key components to managing through the volatility in the first quarter are Constellation’s portfolio management team and platform, which we leveraged to effectively optimize the portfolio during these periods.

Our portfolio management team managed through this volatility extremely well, and we would have had an even more positive quarter except for outages that required us to purchase replacement power in the spot markets. Calvert Cliffs was out for five days during the first extreme cold period in January, and was followed by a few other less impactful outages. This served to highlight the importance of having a balanced and diversified portfolio in fuel type, geography and commodity. While we are best known for our PJM based operations, we have sizeable positions in both ERCOT and New England. We also are expanding our natural gas-based operations in storage and transport,

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which performed very well during the extreme weather. We plan to continue to expand these operations as evidenced by our ProLiance acquisition, which while small from an immediate contribution perspective, has the potential to add more value through optimization opportunities. I will discuss how these events show up in our numbers when I review the hedge disclosures.

Looking at the generation stack, existing infrastructure will be undergoing significant changes as base load coal plants retire and are replaced by some new, more variable generation and an increased reliance on imports and demand response. We have also seen comments from other companies that a significant portion of the coal plants that are expected to be retired were called upon during this period. While this winter’s volatility was driven by extremely cold weather, it served to highlight that the changing nature of the grid will likely produce greater volatility during peak winter and summer events signaling where and when new resources are needed.

As you know, forward markets tend to follow the spot markets, so I will now discuss some of the resulting impacts on the forward markets. In the first quarter, while natural gas prices remained relatively flat, power prices at West Hub and NiHub increased $4.13/MWh and $1.55/MWh in 2015, and $2.92/MWh and $1.53/MWh in 2016. We have also observed an increase in the forward market for volatility as option market prices have increased over the last quarter.

We’ve seen some positive trends in the load markets. Some of the larger wholesale load auctions, like BGS & Ohio, trended favorably in total price of cost to serve and margin, helping to set some price formation for other transactions in the market, such as in the retail space. While it is a little too early to say with any certainty that margins are trending positively in retail, we have seen some signs that indicate pricing is beginning to reflect the appropriate risk premiums. Several retail providers have recently opted to leave the retail space by selling their books of business or announcing their intention to exit. We continue to believe that volatile markets will drive consolidation in this space, which will ultimately lead to more rational pricing behaviors that include the appropriate risk premiums.

Capacity Market Developments – Slide 4

Turning to slide 4, and a discussion of some of the capacity market developments during the first quarter. We have seen capacity markets improve in New England and New York. The New England auction cleared significantly higher, as a result of a tighter supply and demand situation after the announcement of unit retirements; next year will feature a sloped demand curve for Rest of Pool while NEMA will continue to have a vertical demand curve.

Of course, the auction results that everyone is waiting to see will come next month at PJM. FERC has approved two rule changes for the upcoming auction – a cap on sub-annual demand response products, which should limit the total DR volume consistent with reliability limits, and a cap that limits imports. We also are expecting to hear from FERC on one other proposed rule change that would help curb speculation and result in more disciplined bidding behavior.

Hedging Activity and Market Fundamentals – Slide 5

Turning to slide 5, I’ll discuss what the latest market changes mean for our hedging strategy and where we now see fundamental prices.

Power prices and heat rates expanded during the first quarter as a result of the polar vortex, and perhaps recognition of the generation stack changes that have begun and will continue through 2015. As of the end of the first quarter, the market seems to be incorporating some of our fundamental upside view. This is especially true in the PJM West Hub market and more so in the winter months. While there has been an increase in power prices in the PJM NIHUB market as well, we believe there is further upside in NIHUB market prices.

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Given our view and the current markets, we have fallen further behind ratable and continued to use a significant amount of cross-commodity hedges, primarily in the Midwest. While a ratable approach would lead us to be approximately 75% hedged at this point in time, we are approximately 65% hedged in 2015 and only around 55% hedged when you remove our cross-commodity hedges in 2016. We will continue to evaluate the amount of upside we see in prices and carry positions that will allow us to benefit as much as possible.

Finally, I’d like to touch on the changing dynamic around natural gas basis. The past quarter showed that while natural gas surpluses in the Marcellus footprint can drive prices to be negative to Henry Hub, periods of high gas demand can cause prices to spike to extreme levels. We saw Tetco M3 prices spike to $75 per mmbtu and the average January basis spread to Henry Hub reached $16.50. We continue to believe that new infrastructure will be built and the natural gas transport market will continue to evolve to meet the changing market over the next several years. This recent quarter only served to show that, much like the power market, pricing all energy products without the appropriate risk premiums can be dangerous.

Along with appropriate seasonal pricing of delivered natural gas, we still believe that expanding LNG exports, exports to Mexico, industrial expansion and gas demand for power generation will play a role in stabilizing Mid-Atlantic basis and provide support to overall natural gas prices in the near future.

Constellation Update/Gross Margin Update – Slide 6

Turning to slide 6, I will review our updated hedge disclosure and some of the significant changes given the events of the first quarter.

Focusing on 2014, we had several very large impacts to the disclosures that have netted to a $50 million decrease in our expected gross margin, driven by generation performance. As I mentioned before, our portfolio management teams performed very well in managing both our power portfolio of generation and load, and our natural gas portfolio of transport and storage, given the volatile market. This contributed to us executing on $100 million for our power new business targets and $150 million for our non-power new business targets for the year.

As I discussed earlier, the impact from plant outages was approximately $125 million, primarily at Calvert Cliffs. With the higher spot prices experienced during the quarter, an outage for a short duration can have a significant impact. Given our portfolio management performance in the first quarter, we have largely been able to cover most, but not all, of this impact. The change of $50 million in the total gross margin line largely reflects the remaining impact that was not completely covered by our favorable first quarter performance. However, with our set-up for the balance of the year situated to take advantage of volatile events and the diversification across our portfolios, we are confident that we will execute on our remaining new business to-go targets.

For 2015, we saw prices increase across all regions – increasing as much as $4 per megawatt hour in the Mid-Atlantic and New York, and between $1-$2 per megawatt hour in the other regions. This resulted in an increase in our open gross margin of $650 million. Given our hedged position and our execution of $50 million of power new business and $50 million of non-power new business, our total change in gross margin for 2015 was an increase of $200 million.

For 2016, prices increased between $1-$3 per megawatt hour. This resulted in an increase of $600 million in our open gross margin. With a hedged position of between 30%-40% for the quarter and an execution of $50 million in power new business, our total change in gross margin was an increase of $400 million.

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As noted on our slides, all of this information is as of March 31, 2014. Power prices have continued to increase over the last month, with our Mid-Atlantic and Midwest regions up over $2 per megawatt hour in 2015 and 2016. A rough estimate on the increase in open gross margin from such a move would be another $400 to $500 million. Net of hedges, you should see gross margin increase by $225 million and $350 million in 2015 and 2016, respectively.

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Mr. Thayer’s Comments, as Prepared for Delivery:

I will cover Exelon’s financial results for the quarter and our second quarter guidance range, and update our cash outlook for 2014.

Key Financial Messages – Slide 7

I will start with our financial results on slide 7. Exelon delivered first quarter earnings of $0.62 per share. Our balanced generation to load strategy, as well as our geographic and commodity diversity, served us well during a challenging quarter.

Our earnings are consistent with our expectations despite the extreme weather during the quarter and operational challenges across the business, including the Calvert Cliffs outage and significant winter storms in the East – including the costliest and second largest storm in PECO’s history. Although we delivered on our financial commitments for the quarter, our earnings would have been around $0.12 higher without the outage at Calvert Cliffs and PECO ice storm.

This compares to earnings of $0.70 per share in the first quarter of 2013. The key drivers of the reduction in earnings quarter over quarter were lower gross margin at ExGen and higher storm costs at PECO. I will go into greater detail on the quarter drivers at each operating company below.

For the second quarter, we are providing guidance of $0.40 to $0.50 per share. This compares to our realized earnings of $0.53 per share in the second quarter of 2013. The main drivers of this anticipated decline are lower ExGen gross margin driven by lower energy prices, offset by higher revenue net fuel (RNF) at ComEd and BGE.

For the full year, we are reaffirming our guidance range of $2.25-$2.55 per share.

Utilities Results – Slide 8

Turning to the utilities on slide 8, they delivered combined earnings of $0.31 for the quarter. As you know, the quarter was memorable for both its frigid temperatures and severe winter storms. Heating degree days this quarter were between 15%-25% above normal across our three utilities, and all three set new winter electric peaks and a new gas peak at PECO due to the polar vortex. As I mentioned earlier, PECO and BGE faced winter storms with substantial customer outages with PECO being hit hardest by the ice storm in early February. You can find our latest full year load estimates in the appendix on slide 20.

For the first quarter ComEd earned $0.11 per share compared to $0.10 per share in the same quarter last year. The increase is primarily related to higher distribution revenue due to higher investment and higher allowed ROE, and weather.

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PECO’s earnings were $0.10 per share for the quarter. This is down $0.04 per share from the first quarter of 2013 as a result of the ice storm in February. We are comfortable that PECO will be able to meet its full year-guidance range, which we provided last quarter, due to the impacts of favorable weather on revenue net fuel in the first quarter, favorable tax repairs impact related to the storm, and cost management initiatives elsewhere in the business.

BGE delivered earnings of $0.10 per share in the first quarter, an increase of $0.01 from the same period in 2013, due to higher distribution revenue which was partially offset by increased storm costs.

On April 16, ComEd filed its annual formula rate update with the Illinois Commerce Commission (ICC). ComEd requested a total increase to the net revenue requirement of $275 million. We expect a decision from the ICC in December and the new rates to go into effect in January 2015. More information about the filing can be found in the appendix on slide 21.

ExGen Results – Slide 9

Slide 9 covers Exelon Generation’s financial results for the first quarter. ExGen’s earnings were $0.09 per share lower than the same quarter in 2013. The quarter over quarter decrease is related to lower gross margin primarily from the Calvert Cliffs unplanned outage which resulted in higher replacement power costs and lower realized energy prices. These were partially offset by higher capacity prices. However, ExGen remains on plan for the year despite the operational challenges some plants faced in the first quarter.

Turning briefly to the nuclear waste fee issue. We do not believe that Congress will act to reinstate the fee, and indications are that it will be set to zero in mid-May consistent with the Circuit Court’s decision. As a reminder, our current earnings guidance assumes that the fee would not expire, so we will benefit once the fee expires. A full year benefit would be about $150 million per year.

Cash Flow Summary – Slide 10

Slide 10 provides an update of our cash flow expectations for this year. We project cash from operations of $6.2B. This compares to $6.1B last quarter.

I would like to point out a few changes to the projected sources and uses of cash we made as a result of the consolidation of CENG into Exelon. Last quarter, we showed 100% of CENG cash flows (net of distributions) reflected in the cash from operations line, and the CENG distribution to EDF in the Other line. Starting this quarter, we have kept the CENG distribution to EDF in Other, however we have now included 50% of CENG’s capex in investing, while leaving all other CENG cash flows (net of distributions) in cash from operations. The reclassification of CENG’s capex drives the quarter over quarter variance in cash from operations.

As a reminder, the appendix includes several schedules that will help you in your modeling efforts.

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