Ravi Ganti – Vice President-Investor Relations Christopher M. Crane - President and CEO Jonathan W. Thayer – EVP and CFO Joseph Nigro – EVP-Exelon; CEO-Constellation Joseph Dominguez – SVP-Federal Regulatory Affairs & Public Policy.

Dan Eggers – Credit Suisse Steve Fleishman – Wolfe Research Greg Gordon – ISI Jonathan Arnold – Deutsche Bank Hugh Wynne – Sanford Bernstein Angie Storozynski – Macquarie Capital.

Good morning, my name is Amy, and I’ll be your conference operator today. At this time, I would like to welcome everyone to the second quarter 2014 earnings call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions) Thank you. Mr.

Ravi Ganti, you may begin your conference..

Thank you, Amy. Good morning everyone, and thanks for joining our second quarter 2014 earning conference call. Leading the call today are Chris Crane, Exelon’s President and CEO; Jack Thayer, Exelon’s Executive Vice President and CFO, and Joe Nigro, CEO Constellation.

They are joined by other members of Exelon’s senior management team, who will be available to answer your questions following our prepared remarks. We issued our earning release this morning along with a presentation, each of which can be found in the Investor Relations section of Exelon’s website.

The press release and other matters that we discuss during today’s call contain forward-looking statements and estimates that are subject to various risks and uncertainties.

The actual results could defer from our forward-looking statements, based on factors and assumptions discussed in today's earning release, comments we do in this call, and in the risk factors section of the earnings release.

Please reported today's 8-K and Exelon’s other fillings for a discussion of factors that may cause the results to differ from managements projections, forecasts, and expectations. Today’s presentation also includes references to adjusted opening earnings which is a non-GAAP measure.

Please report to the information contained in the appendix of our presentation and the earnings release for reconciliation between the non-GAAP measures to the GAAP earnings. We have scheduled 60 minutes for this call. I’ll now turn the call over to Chris Crane, Exelon, CEO..

Oyster Creek, Quad Cities, and Byron, five in total did not clear the auction. For Quad Cities and Byron, these units are important for grid reliability, environmental and from an economic standpoint, are especially critical in helping Illinois meet its environmental goals in light of the recent EPA rules.

To that extent, Illinois House passed a House Resolution 1146 in May recognizing the value of nuclear energy for its reliability and its carbon-free benefits and urged the expiration of our opportunities to avoid closing nuclear plants.

We have agreed not to make any decisions about retiring these units until June of next year to allow for the Illinois legislature time to enact market-based reforms at the state level that this could be items such as joining Reggie or a clean energy standard.

However, as we’ve said in the past, if we are unsuccessful and we do not see a path to sustain profitability for these units in question, we will be forced to retire them to avoid long-term losses.

I do want to be clear, again, about one thing, we are not looking and do not want contracts for subsidies from Illinois, only contracts that recognize the environmental benefit in the reliability of the assets. To wrap up, we’re confident our fleet operations in our portfolio management to deliver our earnings expectations for the full year.

A key area of focus for us during the second half of this year is to continue working through regulatory approvals to close the Pepco transaction. We will continue to look for opportunities to invest in assets that add value to Exelon and to its shareholders and ways to diversify our portfolio.

With that, now I’ll turn over to Joe Nigro to share his views on the commodity markets..

Thank you, Chris. Good morning, everyone. We wanted to take some time to talk about power markets developments this quarter, as well as year-to-date. I will also touch on our generation hedging strategies, discuss the results of the 2017-2018 PJM capacity auction, provide an update on those margins.

And finally, tell you how this translates to our gross margin forecast. Moving to Slide 3, the spot power markets in the first half of the year have been defined by volatility. We have had six months of very constructive spot market signals, followed by July weakness due to weather conditions.

In the first quarter of this year, the polar vortex led to higher spot prices in PJM, as we observed the growing reliance on resources such as natural gas units, demand response and oil peakers. Throughout the second quarter, we saw spot power prices were higher than what we saw during the same period in 2012 and 2013.

Expanding heat rates have been observed under most load conditions. These higher delivered heat rates can be attributed to the change in generation stack. During July, we’ve experienced, unusually mild weather leading from lower spot power and deliver natural gas prices across the board.

Cooling degree dates are trending approximately 10% below normal at a national level, and 35% below normal in the NI Hub area. Due to the lack of weather related demand in July, spot prices in PJM have been clearing lower than the previous two years. Moving to slide 4, I’ll discuss the forward market and its impact on our hedging profile.

It has been a volatile year for forward power prices. The second quarter of 2014 was a continuation of the trend we saw in the first quarter, in terms of an increase in both power prices and heat rates at the NI Hub and West Hub markets.

During the second quarter, forward NI Hub, around-the-clock prices for 2015 and 2016 increased approximately $2 to $3 per megawatt hour, while West Hub prices increased by close to $2.

A lot of the increase with in line with our long-held that power prices should increase, giving the ongoing changes to the generation stack associated with coal plant retirements, and an increased reliance on natural gas supply and other high priced, non-based load resources.

During the second quarter, we were able to take advantage of the rising power prices and move our behind ratable strategy, as well as our cross-commodity hedge position closer towards ratable.

And we have been operating behind our ratable hedging strategy for some time as we felt the upside in the market of both NI hub and West Hub warranted a more open position. During the quarter, we captured the running forward prices increasing our hedge generation by approximately, 11% in 2015 and 9% in 2016.

We also took advantage of market conditions by reducing the amount of our portfolio that was hedged with natural gas from near 10% to below 5% in both 2015 and 2016. In total, we reduced our power price exposure in 2015 and 2016 by 17% and 12% respectively.

Our generation fleet is now hedged between 92% and 95% in 2014, 75% and 78% in 2015, and 46% and 49% in 2016. Since the end of the second quarter, we have seen forward markets soften due to the weather-related weakness in spot market. Forward prices for natural gas – natural gas basis, and power are down during the month of July.

The move down is largely driven by decline in the prices for the winter delivery months. Specifically, PECO M3 natural gas basis is declined heavily in the winter months, which is led to a corresponding decrease in both West Hub and NI Hub power prices.

Spot natural gas basis prices were strong in Q1, driven by weather conditions, but were lower in Q2 as weather driven demand backed off. The forwards responded accordingly with 2015 gas basis increasing through the first part of the year, only to decline during May and June. Our gas basis dues split into a short-term and long-term view.

Over the next two years, we expect volatility to continue; while longer-term, we expect the stability in the Mid-Atlantic base is driven by the development of the infrastructure to transport gas away from the Marcellus shale area, expanding LNG exports, exports to Mexico, industrial expansion and gas demand for power generation.

With respect to the forward power market, we still see upside price opportunity in certain non-winter months and seasons where we believe the markets are undervalued.

While we have moved our hedging strategy closer to ratable, and more neutral across the calendar years in 2015 and 2016, we think there is an opportunity to benefit from power price upside in those delivery periods. We will continue to set our hedging strategy according to this view. Fundamentally, our view of power price upside has not changed.

We understand that there are very short-term factors that can impact spot and forward prices, as we saw in the winter and then again, in July this year, weather by itself can have a significant short-term impact on the market. However, our view is grounded in the fundamental changes that are taking place in the market.

Specifically, we expect about 30 gigawatt of coal generation to require – to retire across the Eastern Interconnect, by next year, with which approximately 14 gigawatts will be in PJM. Changes in this supply stock and more disciplined load pricing are just a few of the fundamental market changes we have witnessed this year.

Before moving onto our gross margin update, I want to touch on the PJM capacity auction and then an update on our retail margins. The PJM auction cleared at $120 per megawatt day in both the RTO and NERC regions.

The RTO clearing price doubled from the previous year’s auction, indicative of tighter supply demand fundamentals following coal retiring announcements. The clearing prices were primarily driven by 3,000 megawatts at lower imports, 1,400 megawatt of lower demand response, and participants bidding behavior.

These drivers were partially offset by nearly 6,000 megawatts of new generation that cleared. There are further potential market design changes that we will continue to monitor, which will impact future capacity prices as well.

Some examples of this include uncertainly regarding the impact on capacity and energy markets of the DC Circuit Court vacating FERC Order 745, as well as FERC in PJM working to curve speculation, potential changes to the shape of the demand curve and potential changes due to cold weather reforms.

This was the first option that we did in some of our nuclear units at the rate CRs. And as a result, Quad Cities units one and two fired in units, one and two and Oyster Creek did not clear. As Chris mentioned, the failure of these units to clear will be a key factor in our decision and whether or not to shut down the plants.

Our nuclear plants rely on the capacity market for revenues, and without those revenues, their economics will be stressed even more. We have committed that no decision will be made on any of our Illinois units before June 2015. Moving onto our load margins.

So far this year, we began to see increases in both our wholesale and retial load margins, as providers become more disciplined in their pricing assumptions. We have and will remain disciplined in our list-premiums and will not chase volumes for the sake of volume.

We continue to see an improving retail market developing to longer-term contracts and competitor consolidation. As many of you may have heard, yesterday, we announced the agreement to acquire Integrys Energy Services, a leading retail power and natural gas provider serving 1.2 million customers across 23 states and the District of Columbia.

The Integrys portfolio adds further scale to our retail power and natural gas business and provides generation and load-matching benefits to our portfolio. We expect the transaction to close in the fourth quarter of this year or the first quarter of 2015.

Turning to slide 5, I will review our updated hedge disclosure, and some of the significant changes given the events for the second quarter.

Focusing on 2014, we have a net $50 million increase to gross margin, since the end of the first quarter, driven primarily by the elimination of deal in nuclear waste in, partially offset by an extended outage at Salem.

As I mentioned before, our portfolio management teams performed very well in managing our portfolio generation and load given the volatile market. This contributed to us executing on $100 million of our power new business targets and $50 million of our non-power new business targets during the second quarter.

For 2015, we saw pricing increase across most regions. The increase is around $2 per megawatt hour in the Mid-Atlantic and the Midwest. This along with the DOE fees resulted in an increase in our open gross margin of $450 million.

Given our hedge position and our execution of $100 million of power new business, our total change in gross margin with an increase of $300 million. For 2016, prices increased by $2 to $3 per megawatt hour.

This resulted in an increase of $600 million in our open gross margin, with a hedge position of between 40% to 50% for the quarter, and an execution of $100 million in power new business, our total change in gross margin with an increase of $450 million. Overall, the first half of 2014 has resulted in higher prices from where we began the year.

While mild weather increased gas production and falling natural gas bases prices have challenged power prices during July. Although volatility in the market is likely to persist, we are also confident that gas and power markets are fundamentally stronger and were just a year ago at this time.

Now, I will turn it over to Jack to review the full financial information for the quarter..

Thank you, Joe and good morning everyone. I will cover Exelon’s financial results for the quarter. Our third quarter guidance range and update our cash outlook for 2014 including a discussion at the financing for the Pepco Holdings acquisition. I will start on slide six.

As Chris mentioned earlier, Exelon delivered second quarter earnings of $0.51 per share, exceeding our guidance range of $0.40 to $0.50 per share. This compares to earnings of $0.53 per share in the second quarter of 2013.

The key drivers of the reduction in earnings quarter-over-quarter were lower realized energy prices at Exelon Generation, offset by increased distribution revenue at the utilities. The cost of the extended outage at Salem, during the second quarter is offset by the elimination of DOE Nuclear Waste fee.

I will go into greater detail on the quarter drivers at each of the utilities in a few moments. For the third quarter we are providing guidance of $0.60 to $0.70 per share. In April, Exelon received the operating licenses for the CEMG nuclear fleet and began operating those plants.

Prior to closing, Exelon and Generation each accounted for its investment in CEMG under the equity method of accounting. After the close, we moved to a consolidated method of accounting and recorded all assets, liabilities, and EDF’s non-controlling interest in CEMG at fair value on Exelon and Generations balance sheet as of April 1.

Ongoing operations will be included in the consolidated Exelon and Generation financial statements. However, these accounting changes do not materially change the earnings and cash flow for Generation and Exelon. For the full-year, we are reaffirming our guidance range of $2.25 to $2.55 per share.

This guidance includes the impact of the elimination of DOE Nuclear Waste fee and is partially offset by increased outages primarily in the nuclear fleet at Calvert Cliffs and Salem. These outages and their impacts are expected to be a $0.12 per share drag for the year.

As we stated before the full-year benefit of the fee expiration is around $150 million per year or approximately $0.11 per share. We do not expect Congress to act to re-instate this fee in the immediate future and therefore have removed it from all years of our gross margin disclosures.

Turning to the utilities on slide seven, they delivered combined earnings of $0.25 for the quarter. Before explaining the drivers of each utility, let me provide a brief update on our latest load forecast. In general, we are seeing load growth year-over-year at ComEd and PECO. While BGE growth is flat for 2013.

ComEd is seeing positive load growth of 0.8% across all three customer classes, led by 1.2% in the residential sector. PECO's overall load growth of 0.7% is led by 1.2% growth in the large commercial and industrial sector and offset by a decline in load in the small commercial and industrial sector.

You can find our latest full-year load estimates in the appendix on slide 18. For the second quarter ComEd earned $0.13 per share compared to a $0.11 per share in the same quarter last year. The increase is primarily related to higher distribution revenues due to rate base growth from higher capital investment.

PECO’s earnings were $0.10 per share for the quarter; this is up $0.01 per share from the second quarter of 2013, due to decrease income tax expense primarily due to additional tax repair benefits from February and July’s storms and redemption of preferred securities which resulted in a reduction of preferred dividends.

As Chris mentioned earlier, PECO had two significant storm events in early July. Combined, these storms had a total incremental O&M cost of $10 million to $20 million and incremental capital cost of $10 million to $20 million. Despite these storms, and the ice storm in February, we are comfortable that PECO can still meet its full-year guidance range.

BGE delivered earnings of $0.02 per share in the first quarter, a decrease of $0.01 from the same period in 2013, due to the increased O&M cost primarily due to bad debt expense, and labor, contracting, and materials partially offset by the increased distribution revenue.

Earlier this month, BGE filed a rate case with Maryland PSC asking for increases of $117.6 million for electric and $67.5 million for gas. We expect the final order in late January 2015 with new rates going into effect shortly thereafter.

As you know ComEd filed its annual formula rate case in April and we expect a decision from the ICC by December 12. And the new rates will go into effect in January of 2015. More information about the filings can found in the appendix, on slides 19 and 20 for ComEd and BGE respectively.

Slide 8 provides an update of our cash flow expectations for this year, we project cash from operations of $6.975 billion, this compares to $6.2 billion last quarter. The variance is primarily driven by proceeds from divestitures and a decrease in OPEC contributions.

As you know, we had a busy quarter, working on financings for the Pepco Holdings acquisitions. on May 30 2014, we announced that we had entered into a $7.221 billion bridge loan facility to support the transaction and provide flexibility for timing of permanent financing.

We executed the first portion of the permanent financing with a successful equity issuance via forward sale, which priced on June 2011.

we issued $1.2 billion in mandatory convertible units, and $2 billion in equity forward contracts, each of these transactions including green shoes, the proceeds of which may be utilized for accretive growth opportunities. As a result of the equity issuances, we reduced the bridge loan facility to $4.2 billion.

We are well down the road with our asset sale program. in May we sold our Safe Harbor hydro facility to Brookfield capital for $613 million, or $375 million after-tax with an expected close in the third quarter. We’re also proceeding with efforts to divest Fore River, Quail Run, Hillabee and Keystone Conemaugh.

We anticipated raising greater than $1 billion in after-tax proceeds from the divestitures, with the excess proceeds funding future invested growth. As a reminder, I’d like to point out a few changes made to the presentation of the projected sources and uses of cash from the first quarter due to the consolidation of CENG of Exelon.

For the fourth quarter of 2013, 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 the first quarter, we have kept the CENG distribution to EDF in the other line.

However we now include 50% of CENG’s CapEx in investing, while leaving all other CENG cash flows, net of distributions and cash from operations. As a reminder, the appendix includes several schedules that will help you in your modeling efforts.

Now before I open the call for questions and answer, Q&A, I want to acknowledge that this is Ravi Ganti’s last call as VP of IR. Ravi is moving back East to become the Senior Vice President and Chief Commercial Risk Officer. I thank you for representing Exelon for the past two years. I also want to welcome Francis Idehen as the new VP of IR.

Many of you on the phone have met Francis, and we at Exelon are excited to have him in this new role. That concludes my remarks. Operator, we’d like to turn it over to Q&A..

(Operator Instructions) Your first question comes from the line of Dan Eggers with Credit Suisse..

Hey, Dan..

Can we talk a little bit more about kind of what’s going in the retail markets, (a) as far as what kind of margins and profitability you guys saw in the quarter.

And then with the Integrys acquisition, how you think about the scale of selling power through retail channels relative to other ways of hedging your exposure?.

Yes. Joe will take that..

Good morning, Dan. The retail market remains very competitive. As you know, there’s a number of participants in all the areas that we’re in. I would say however since January, we have seen improvement in all of the retail markets. And it’s really happened on two fronts from our perspective.

The first is just the premium – the rich premiums charge to serve load. And I’m talking both in the retail markets as well as on the polar side, have gone up with the increased volatility we’ve seen in the market. And then in addition to that, we have seen our margins on the C&I origination on the power side expand as well.

And I think both of those things are positive. We have been saying for some time that we expected to see this happen, because we couldn’t get our hands around where the market was trading at effectively.

I think from the Integrys perspective, it’s a really good [depth] [ph] for our portfolio from the standpoint of – the core products are power and gas, which dovetail nicely into our existing retail business.

The 22 states that they’re in, also fit nicely with the geographies that we are in, and it is just a natural opportunity for us to grow the business that you see some of the competitors scale back..

The only thing I’d add to that, the nature of the business is still very competitive, as Joe said, there’s dozens and dozens of participants that are still in markets like northern Illinois. We expect upon closures that our combined footprint would be about 29%. I think it’s been over reported in a few outlets.

And so 28% to 29%, but there again, as the contracts come up, it will be – that will be processed in a very competitive way. So we feel strong about the acquisition and we still think it supports a very competitive market..

You guys have historically talked about kind of $2 to $4 margins for the retail business, where are you seeing new business fall within that continuum?.

Dan, we’re seeing – we’ve mentioned previously in the last six months that at one point, we were slightly below that $2 to $4 threshold for C&I originations. We’re now back over that $2 threshold that [core load] [ph] mid $2 and we’ve seen improvement.

and as I mentioned in addition to that, on top of that, we’ve seen the actual risk premiums increase. So the increases did really on two fronts, but our margins alone are above that $2 threshold..

And I guess one other question kind of after the Pepco deal there was talked about, looking to buy more generation assets prospectively as well and maybe the asset sales freeing up even more balance sheet room.

Can you just walk through the criteria, you guys expect as you look at buying assets in this market, and then with the volatility and power markets, we’ve seen in the last few months.

How is that maybe affecting decisions or where you might want geographic exposure?.

We continue to look at growing both sides of the business either through on the generation side, either through acquisitions or potential development projects. but they have to pass the test of accretion and over the period and a value proposition, a positive NPV, a contribution to earnings and free cash flow or EPS.

We participate as assets come more recently. Assets have been going at higher valuations than we would put them in the portfolio for, but it will continue to watch as things come to market and run them through our models.

They need to be generally in the markets that we’re serving and trying to grow into some of the asset optimization there we’re going through now.

It is fairly back on a few of the assets that don’t have the good well run assets, good employee base highly reliable, but they don’t have the value creation in our portfolio, so continuing to optimize the assets as we go forward.

As we’ve said previously, really interested in the Texas market, we see the economy there strengthening, we see the demand although not as fast as previously reported presenting opportunities for further growth in the wholesale, and retail opportunities, which would – with our business model, we’ve tried to match as much as we can the generation to the load and the portfolio..

Okay. Thank you, guys..

Your next question comes from the line of Steve Fleishman with Wolfe Research..

Yes. Hi, good morning..

Hi, Steve..

Hi.

just first on the guidance for this year, have you incorporated any of this bad July weather, or August forecast in the range or not?.

Yes..

Okay, good.

Is that that’s in your Q3 forecast as well?.

Yes. But one of us said, yes. (Indiscernible).

Okay. Good, and then just going back to the TEG transaction, retail.

can you give us maybe any sense of the metric of what kind of valuation you might have paid for that business?.

Well, as we mentioned in the press release, Steve, we paid $60 million for Integrys, and assumed the working capital of approximately $180 million or so. I would say on an EBITDA multiple basis it’s close to or less than 2 times on an EBITDA multiple basis..

Okay. And then this might be a bit of a farfetched question. But just curious, because you’ve been growing your renewable business at a decent amount and contracted generation.

What’s your kind of take on this yield curve trend and is this something you’d want to kind of sell your assets to, given that you are probably selling for a lot now or you want to keep trying to grow the business, just how are you thinking it about it?.

We like the business on the projects that you can get for the right value. It is on the renewables a free cash flow play and with the current tax rules that are there it’s a tax play. We have leaned more towards project financing.

And we think that fits our needs better than a yieldco and in the long-term with what we see for the tax environment for these assets going forward. So we’re not heading towards yieldco or pushing assets into the yieldcos, we’re more continuing development in project financing assets..

Okay. Thank you..

Your next question comes from the line of Greg Gordon with ISI Group..

Thanks. A couple of questions, first, I know you had a good update on cash flow in part from tax.

Though, were those tax inflows contemplated as possible to the beginning of the year and you just excluded them from your guidance, because of you are uncertain on timing, or were they something new that developed over the quarter, and then should we assume a normal effective tax rate in the subsequent quarters in the next couple of years?.

Greg, I’d say some elements were, I would say on the opportunity side. So we had some visibility. We had about $100 million improvements based on tax reimbursement for decommissioning trust funds. The Safe Harbor sale allowed us to accelerate some tax credits, so that pulled forward about $175 million.

So we have had some elements that we had some visibility might come to fruition and with some successful settlements with the IRS, as well as very successful sale of Safe Harbor have created incremental opportunity there.

On the effective tax rate side, we would anticipate about 31% to 32% consolidated effective tax rate on operating earnings for the year. And on the GAAP side mark-to-market earnings kind of caused that to have some variability around it. About the modeling purposes, I think you can safely assume the 31% to 32%..

And in subsequent years, is that a reasonable bogey, or is it – should we assume something higher in lieu of any one-time tax monetization?.

I think that’s a fairly reasonable level..

Okay. So consistent at that level..

Yes..

Okay. And then can we talk a little bit about gas and gas basis, working here with John we watched not just strip, but the monthly is in you have still got a pretty positive winter basis and a pretty negative summer basis that take along the three. But then at the Chicago City Gate basis hasn’t been nearly as volatile.

What’s your – what is going on in the real-time market and what is your point of view on how – Exelon’s point of view on how we ought to think about gas basis?.

Yes. Good morning, Greg. It’s Joe. I think from the gas basis perspective, your point is right on. We’ve seen the Nov-March strip for next year, the M3 basis dropped since the end of June about $0.50, and inversely as we tied in early May, it’s dropped almost $1.

and to your point, really the summer periods since the end of June for that M3 basis hasn’t fallen at all, we’ve dropped some, since the high at the end of May; Chicago has been much more stable.

From our perspective, there’s a couple of things obviously, the strong Q1 spot prices had a big impact on driving the forward prices higher, both in the winter and summer period. Most we’re seeing an impact that drag through to the forward curve on what’s going on in the spot market.

I mentioned in my prepared remarks how we’re 35% down on cooling degree days in Chicago and 10% national. That’s having an impact in the gas market, both the NI Hub and drag through the basis. I think specifically, the M3 basis, where it’s going to continue to see some of this volatility in the next two years or so.

As we continue to produce more gaps with the Marcellus shale, we’re producing about 15 Bcf a day. In Marcellus, we just don’t have the takeaway capacity and move that gas efficiently.

As we get out towards 2017, we really expect that gas demand and supply demand balance that Marcellus could come into much better equilibrium, when you think about some of the pipeline reversals in TransCo and Texas Eastern and Rockies Express, which will provide an uptick and more stability to that gas basis..

So, when will you guys roll out how you’ve positioned yourselves for 2017 vis-à-vis hedging, and would we expect that perspective to be reflected in your positioning when you do so?.

Yes. I think the way I would answer that is, first is, we’ll roll out 17 like we do every year with EER. And we do have a ratable program for 2017 began this year. We are impacted by gas basis just like everyone else by our open position.

But I would also say as we convert to power sales obviously, we don’t have as big an impact on the gas basis doesn’t have as big an impact on us, once we sell the power, because we have so much long base load nuclear generation that it’s not impacted once the power sold..

But 17 will come out in EER..

Thank you, gentlemen. .

Your next question comes from the line of Jonathan Arnold with Deutsche Bank..

Good morning, guys..

Good morning..

Could I just ask you to give us an update on how you see the whole kind of discussion in Illinois around these market base solutions playing out? I guess you said you weren’t taking any action on plans till middle of 2015. The legislature is going to come in for a veto session in November, and then be back in the early part of next year.

What’s going on currently, if anything, and how is this actually going to move forward?.

I’ll get Joe Dominguez just to cover his action..

Sure. What’s going on currently is that the Illinois stakeholders are taking a look at the 11B proposed rule, which obviously, provide the strong signal to the states to preserve nuclear as part of their compliance plan.

The other thing that is happening is part of the resolution that Chris mentioned at the asset, state agencies are drafting a number of reports that will look at the economic value of the units to the local communities, jobs, the value of the energy produced, the value of the low resources.

And so we expect those reports to be completed sometimes around November or December positioning us for a discussion of solutions in the spring session. So I think the first time we'll see the actual legislation and different proposals will be in the spring.

As Chris mentioned, we're looking for a market solution to the extent that low carbon resources, enhanced reliability, or attributes. We'll expect the compensative for those attributes and we’ll expect that competition really at all of the plants and not just the plants that are in jeopardy. So that’s our go-forward plan. I think that’s the timing..

So the next thing we’ll probably see will be this reports coming out towards the end of the year..

That’s right..

And then, would you say that the stakeholders’ interest in that is entirely dependent on 1011D, well does that kind of run.

Is there a chance we move on this regardless of what happens with EPA and carbon?.

The state has long positioned itself as focused on environmental issues. And they have individually, as the state take actions and advance of 1011D and looking at different programs that they maybe able to participate in, and we see this is helping them with the road map on going forward. So there is an interest within the state for that.

There is also an interest within the stake holder body to secure the long-term viability of these assets, they’re greatly highly critical to the economy, local economy in which they are located in serving as tax basis, job basis, economic support for the community.

So it’s a multifaceted view, but the environmental support has been a long-term focus for the state..

Okay. Thanks, Chris.

Can I just ask similar idea on a different topic on the various set of avenues you are pushing forward in terms of PJM market structure reform, could you give us an update on which of those is getting the most attraction and what your expectations are around timing and process there as well?.

Joe you want to….

So there is some unfinished business around the speculation reforms that have been proposed in advance of the last auction and set up some sessions to deal with that. We think that ultimately revise some of those speculation reforms for approval and advance the next auction.

The other issue that is gaining a lot of attention, it’s an examination of the winter on a reliability situations I think has revealed some gaps in the capacity product that we have purchased thus for (indiscernible) consumers.

So I think PJM is going to be looking at something that procures some additional commitments around high availability resources. I think that’s going to look a lot like resources that have firm fuel, like our nuclear plants.

And I think it’s going to be characteristic approach where there will be additional compensation those units or enhanced reliability. And there is also going to be some enhanced penalties. And I think as an early model one might look to in that regard is what New England has done. I think PJM is going to look very carefully at that.

So there will be some more money in the session, but also some more penalties for people who don’t perform. I think generally speaking PJM wants to be added a business of managing fuel supply for gas generators that has become a big issue and will become a bigger issue as the staff changes.

And the other thing we saw is obviously generator non-performance in the winter, which really threatened the reliability of systems. So I figure we will see a proposal sometime in the next month from PJM with action bringing something to firm potentially by the end of the year depending on what the analytics look like..

Would that run on typical PJM PRA schedule with an auction I guess second quarter or you see that happening on a different time frame?.

Well. I think in the long run it’ll do just that, it’ll be part of the PRA and planning perimeters, we see going into the PRAs. But there is a question about these next few winters before we can catch up with the PRA schedule. So I think there's going to need to be something that will be supplemental for the coming winters.

But, again, we need to see what PJM proposes. But I don't think it just truly to PRA plan. I think it’s going to be back in the next few winters as well..

Okay. So the next month, you think that proposal is in that….

Yes..

Thank you very much..

Your next question comes from the line of Hugh Wynne with Sanford Bernstein..

Good morning..

Good morning..

Good morning..

I wanted to follow-up on some of the discussion regarding Illinois response to 1011D. I think you had mentioned that rule provides an incentive to preserve the capacity of the nuclear fleet, and one point I also heard mention the possibility that Illinois might join RGGI.

Could you comment more directly on what you've heard regarding the strategies of Illinois and Pennsylvania with a respect to their possible response to 1011D, their state implementation project?.

I would say just first of all it's very preliminary. So I think there’s a couple of things that folks are looking for. It’s pretty clear that if you lose nuclear plants your ability to comply with any carbon regime going forward is going to be jeopardized.

So plants produced tremendous amount of zero carbon energy, and so if you lose those you are going to see a big uptick taking in carbon efficiency and we see that states – were plants have actually retired. I think that's been fully recognized. What the vehicle for compliance will be is going to be the subject of discussions.

I would guess at least a year and possibly longer. So I just think it’s too early to speculate on where they are going to go. I think some stake holders and see what’s been done in the RGGI states and find that appealing. But, we are there's a lot of grain before we get the solution on that..

I think the other thing to add is in conversation, this is a very complex rule and it takes time to digest as I think the state ones to ensure they understand the allotment are reduction goals they have given that they ensure that as they are given a fair shake in that, but it will be as Joe said it take a while..

If I could just add you asked about Pennsylvania as well. There I think the administration has not been predisposed to joining RGGI that the other candidate for Governor as indicated as part this platform that he would win RGGI if he is elected, so mostly what the elections results look like in November, and that will probably charge path there..

Can I just ask a question on that front? The portion of your fleet that's in New York and in Maryland, of course, is already governed by RGGI.

Is it important to you, and are you making initiatives to see that the rest of your fleet is also governed by similar rules? Or do you feel that PJM can operate flexibly with different state implementation plans in different states?.

I think we believe later. I think RGGI is a good choice. RGGI is just one of choices, as clean energy standard can work, a dispatch model where we pricing carbon and then dispatch resource through the RTOs, it works. There are a lot of solutions out there.

We have supported the RGGI platform and the model of improvements and we’ll continue to support those states that are interested in that model. But it’s not the only solution. .

Great. Thank you very much. .

Your next comes from the line of Angie Storozynski with Macquarie Capital..

Thank you. Good morning. So, I wanted to go back to the questions about Integrys. I know a lot of questions have been asked.

Have you incorporated the projected uptick in volumes and margins to your retail business in your gross margin projections?.

No. Angie, we have not..

How should we think about it? How big of a swing could it be? Also, is this for short power?.

First of all, I think the first question is the uptick in volume would probably be approximately 15% to our retail power volumes. And our existing constellation retail power volumes, on the gap side the uptick in volume would be approximately 30% to the existing constellation volumes..

Okay.

And I’m just trying to figure out if this very low multiple – does this very low multiple have to do with the fact that the portfolio was short – the 2 times EV to EBITDA?.

Yes, Angie, this is Jack. Clearly, Integrys didn't own generation to support that portfolio they had acquired has been hedged via the open market. It fits nicely with our generation footprint in the state that are active. And this will be an incremental avenue for us….

Yes. And I would add to that Angie, the purchase with the mark-to-market exercise, so regardless if they were long or short, it would be an exercise in just mark-to-market, whatever positions they had on. It’s hard to speculate and then provide a more information to that..

Okay. That's fine.

Now, should we expect that you will give us an updated projections for volumes and then margins for the retail business during the EEI?.

Yes. That is correct. We will update it for EEI..

Okay.

Then, given the correction in forward power curves since June 30, could you give us a sense roughly how big of a swing we are seeing currently in your total gross margin for 2015 and 2016 versus what you're showing from the slides?.

Yes. If you are look at our sensitivity tables that we provide in our hedge disclosures.

We show you a $5 change in power crises for 2014, 2015, 2016 respectively for PJM west and for NI-Hub, and we were roughly down about $3 in 2015 and 2016 respectively, so just backing into the math it’s approximately $150 million in 2015 and approximately $250 in 2016 and you could see that in the sensitivity tables we provide..

Okay. And then again going back to the retail business, I mean just to reconcile your views, so you are expecting, as we do, a growing volatility in power prices, and yet you are bulking up your retail business, which tends not to do well in a volatile power place environment.

So are you comfortable with this strategy because you're still long power, or is it that you think that you're the last man standing in the retail business, and thus you will be paid for this additional risk that you're assuming?.

It’s definitely not the last man standing. It’s a (indiscernible) market with many participants in it. So I think, Joe could continue to cover this strategy, you touch that..

Yes. I think Angie there is a couple of things. I think the first is intrinsically we believe in the logic of matching generation and load. And there is a number of reasons to do that it’s beneficial for us, because we don’t have to take our power output, over the counter market.

The optionality of our units is efficiently matched with these load contracts. The locations in which we’re selling the load contracts matches nicely to our generation output generally. I think the second; the other side of it is the volatility piece.

These contracts are renewing in a relative frequent period, that touch the phase and the volatility is reflected in those contracts. So it’s not like for being exposed that. If you go back six months ago, we were saying we didn’t think the market was accurately pricing the volatility in the right way.

And when I was impacting the way we were executing our own quantity to retail. We have seen that improved and we thought it would improve and we are comfortable with it because it an efficient hedge for our total portfolio. And the margins had continued to expand..

Okay. My last question, not related to the generation business for once, we're still missing a filing in Maryland for your Pepco acquisition.

Is there any reason why you're waiting to file in Maryland?.

Yes. As we previously said we have multiple filings in at Maryland. And we had to time ourselves in our own workload. So we prepare the other one, first Maryland’s on a clock its 225 days, so we’ll be filing that one very shortly.

But it is just the execution of the work we already have, in front of the commission in Maryland the work that we needed to do in front of the other commissions..

Thank you..

Thank you. There are no further questions at this time. I would like to turn the call back over to Ravi Ganti..

Thank you, Amy. That brings us to the end of the call. Thank you for joining us. If you have any follow-up questions please contact the IR department. Thank you..

Thank you. This concludes today’s conference call. You may now disconnect..