Denis O'Brien - Executive Vice President, Chief Executive Officer of PECO Energy, President of PECO Energy and Director of PECO
Stacie Frank - Vice President of Investor Relations
Kenneth Cornew - Senior Vice President and President of Power Team
Joseph Dominguez - Senior Vice President of Federal Regulatory Affairs & Public Policy and General Counsel of Exelon Generation
John Rowe - Chairman, Chief Executive Officer, Chairman of PECO, Chairman of Exelon Enterprises, Chairman of Exelon Energy Delivery and President of Exelon Generation
Matthew Hilzinger - Chief Financial Officer and Senior Vice President
Michael Lapides - Goldman Sachs Group Inc.
Dan Eggers - Crédit Suisse AG
Jonathan Arnold - Deutsche Bank AG
Steven Fleishman - BofA Merrill Lynch
Hugh Wynne - Bernstein Research
Exelon (EXC) Q2 2010 Earnings Call July 22, 2010 11:00 AM ET
Good Morning. My name is Cynthia, and I will be your conference operator today. At this time, we would like to welcome everyone to the Exelon Corp. Second Quarter Earnings Conference Call. [Operator Instructions] I would now like to turn today's call over to Stacie Frank, Senior Vice President of Investor Relations. Please go ahead, ma'am.
Good morning. Welcome to Exelon's Second Quarter 2010 Earnings Review and Conference Call Update. Thank you for joining us today. We issued our earnings release this morning. If you haven't received it, the release is available on the Exelon website at www.exeloncorp.com.
Before we begin today's discussion, let me remind you that the earnings release and other matters we will discuss in today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties, as well as adjusted non-GAAP operating earnings. Please refer to today's 8-K and our other filings for a discussion of factors that may cause results to differ from management's projections, forecasts and expectations, and for a reconciliation of operating to GAAP earnings.
Leading the call today are John Rowe, Exelon's Chairman and Chief Executive Officer; and Matthew Hilzinger, Exelon's Senior Vice President and Chief Financial Officer. They are joined by other members of Exelon's senior management team who will be available to answer your questions.
I will now turn the call over to John Rowe, Exelon's CEO.
Thank you, Stacie. Good morning, everyone. As you all know from our press release, our second quarter performance exceeded both our own earlier expectations and your estimates. Exelon turned in operating earnings of $0.99 per share compared to our earlier estimates at $0.80 to $0.90 per share. Matt will explain how we were able to do this in more detail, but constant attention to operating performance across all of our business units were a big part of the story, and so we're improving power market conditions. The weather also helped. We've had so much heat in Philadelphia, almost twice the normal level, Denis O'Brien, who is a bit of a skeptic looked at me the other day and said, "John, if this stays up, I'm going to believe that climate problem you've been working on is real." It is, and we might be even be seeing it. As a result of our strong first half, we are raising our operating earnings estimate for the year to $3.80 to $4.10 per share.
Now normally, on these calls, I spend most of my time talking about the highlights of the quarter. I'm going to leave that to Matt Hilzinger today and talk about the subject that most of you are asking us to address. That is our longer-term earnings potential. Most of you tell us that you respect our operating performance. We appreciate that, I think we deserve it. Most of you described our assets as a solid foundation for future earnings growth. That's true too. Most of you recognized that we have some upside next year, as the full requirements contract expires between Exelon Generation and PECO.
But you'll likely question how two, three, four years from now, we will be able to prosper in a world of low gas prices and dimming prospects for carbon legislation. That is precisely what I want to address this morning. Put simply, we expect some drop in 2012 earnings. But we believe by that time that the trough in our revenues will be nearing its end. This morning, I'm going to cover three reasons why we believe that.
First, EPA regulations will affect both capacity and energy markets and we'll do so sooner than many think. Second, there are already tangible signs that power markets are recovering. And third, Exelon's investments and rate cases over the next few years give us further opportunities for income enhancement.
Exelon is not a passive beneficiary of changing circumstances. Our confidence in the long-run value of our property and our operations is a product of envisioning a cleaner energy future and acting on that vision since we formed Exelon 10 years ago.
These actions include forming Exelon Generation as a separate company, thereby, giving our shareholders the upside; selling the ComEd fossil fleet; continuously upgrading our nuclear fleet and most recently, planning the retirement of fossil units at our Eddystone and Cromby stations. Our approach is laid out in Exelon 2020, our path to a low-carbon future. While it is an advocacy piece, it is not just an advocacy piece. It is a way of capitalizing on Exelon's nuclear fleet and a way of positioning our investments to add value for our investors in a world that demands cleaner power.
Now let me start with what we see from EPA regulation. Slide 3 of our deck illustrates in a simplified form the welter of regulations that are coming to the nation's coal-fired generation fleet over the next few years. You all know, you're going to make your own estimates of how much Exelon could benefit from climate change legislation, and you all know that, that is not very likely in the near term. But EPA regulation of traditional pollutants, regulations that are now being issued, regulations that are required by existing statutes and court decisions are far more imminent and far more certain, and carry similar positive benefits to Exelon over the next few years.
In May, the EPA issued its proposed coal combustion waste rule making, compliance with the final rule likely will be required by early 2015. Depending on the ultimate approach, EPA estimates compliance costs of up to $20 billion.
In June, EPA issued new measurement and monitoring requirements for sulfur dioxide. It estimates that those requirements will cost the industry approximately $1.5 billion.
And in early July, EPA issued the CAIR replacement rule, now called the Transport Rule, to regulate NOx and SOx. Emission reductions are required as soon as 2012, with further reductions required by 2014 and 2015. EPA estimates a compliance cost of $2.8 billion per year.
Now EPA is also under court order to issue hazardous air pollutant regulations, which include both mercury and acid gas. It must do that by March of next year, and compliance is mandated by late 2014. The hazardous air pollution regulations are likely to be the most challenging and most costly for coal generators to address.
Now these regulations benefit Exelon in two ways. First, when investments are made in control technology to address these regulations, they increase operating costs for the coal-fired generators and ultimately increase the clearing price for energy.
And second, for many small units, which cannot economically meet these requirements, they will have to shut down. And the loss of this capacity should begin to be apparent in capacity auctions as early as next May.
Now you all have seen estimates from various sources, so have we, that try to determine the magnitude of these impacts. The Petroleum Industry Research Association, which many of us use as a consultant, predicts that as many as 30,000 to 40,000 megawatts of coal generation will be retired. PIRA predicts that about 14,000 of these megawatts will be in PJM. Some of you have predicted that larger numbers will be retired.
After last year's capacity auction, the PJM Market Monitor concluded that over 11,000 megawatts of coal already did not recover their avoidable cost and that is even before the new EPA regulations take effect.
This leads to three obvious questions. How much coal will retire, particularly in PJM? How soon will those retirements occur? And what effect will this retirement have on capacity and energy markets? We know they will be substantial. We know they will be relatively soon. We know they will continue throughout most of the decade. The issue is just how much, how fast.
When we at Exelon look at these issues, we are mindful of the fact that these regulations must take into account the need to ensure continued reliability of the system. Localized transmission upgrades will be necessary in certain situations. There will be some short-term reliability must-run agreements, while upgrades are completed or new peaking capacity is installed. But we expect EPA to want those agreements to do what is necessary to keep capacity available and not to incent them to run excessively.
Reserve margins in PJM are generally sufficient to enable orderly retirement of coal generation, as these localized transmission issues are addressed. And while some of the EPA regulations will be challenged, this is very different than cap-and-trade. Cap-and-trade required Congressional action to be sent [ph]. New EPA regulations will take effect unless Congress takes steps to stop them and neither political party wants to be against clean air.
Coal operators are already reacting to the scissors of low market prices and possibly new regulations. In PJM, coal generators have already announced close to 4,000 megawatts of retirements or restricted operations, these include our own Eddystone and Cromby units and several AEP units.
Outside of PJM, Xcel Energy and Progress have also announced substantial retirement plans. More tough decisions will be made in the near term, and they will have to be made well in advance of the final compliance deadlines.
The next PJM capacity auction in May of 2011 covers the period from mid-2014 through mid-2015. That is precisely the period when coal ash, the transport regulations and hazardous air pollutant compliance will be required. These will have significant consequences to clearing prices, and the upside to Exelon is unmistakable. Every $50 per megawatt day as a change in capacity prices, translates to almost $350 million of additional capacity revenue for Exelon in 2014 and subsequent years.
Beyond the capacity market, energy prices will also rise from higher operating costs for coal-fired generators. Coal-fired generators set the margin in PJM around 50% at a time. Energy prices also rise from a change in the dispatch stack as coal is retired and replaced with natural gas. These changes add up quickly. A $5 per megawatt-hour increase in energy prices would be $700 million to $800 million of incremental annual revenue to Exelon on an open basis. We expect that at least some of that upside will be realized in the next two to four years, as operating cost increase for coal-fired generation.
Some of that uplift will come in 2012 from the cost of new allowances for SOx and NOx under the Transport Rule. Based on EPA's estimate of allowance pricing, and EPA generally has the incentive to make its estimate low, these increases could be from $2 to $3 per megawatt hour as early as 2012 and 2013.
Now calculating the effect on Exelon is not as simple as it is for a hypothetical level of carbon legislation. But all of this adds together to say Exelon's clean generation will grow in value in a relatively short time. We are of course positioning our portfolio to capture that value. We do that through a continued top performance of our nuclear fleet. Chip Pardee and his team achieved the capacity factor of 94.8% in the second quarter.
We do this through our nuclear uprate program, which will add 1,300 to 1,500 megawatts of baseload nuclear power and support reserve margins as coal plants begin to retire. And we do that through our utilities' industry-leading energy efficiency and Smart Grid programs.
Now let me turn to the second reason why I have confidence, which is we are already seeing some signs of power market recovery. While natural gas is the least exciting area that we look at, natural gas prices on the forward curve are remaining consistent with Exelon's long-term fundamental view.
While we have seen lower spot market gas prices, we continue to believe that long-term prices will lead to reflect long-run marginal cost and the uncertainties associated with that. But more importantly, market implied heat rates in NiHub have already improved in the spot market. They have improved in the forward bases since last quarter, and we believe there is still modest upside in forward market heat rates. This means that even without changes in gas prices, forward energy prices at NiHub could increase by several dollars per megawatt hour for this reason alone.
And finally and most tangibly, the PJM capacity auction results announced in May, showed that the competitive markets are working. About half of our capacity is in the eastern zones of PJM. Prices there increased by $100 per megawatt day, just since last year.
In the Midwestern RTO ranges, prices started much lower but they increased about $10 per megawatt hour. The demand forecast was up by 1.7% over last year's auctions, and net demand increased by 2,000 megawatts as a result of FirstEnergy's entry into PJM.
The higher clearing prices across PJM translate to about $400 million in incremental annual revenue to Exelon as compared to the auctions a year prior. Looking ahead, we project that the May 2011 RPM auction will result in further increases in price across our region. In other words, an even better price than 2010. Exelon Generation is of course poised to capture that value.
Our hedging program protects the cash flows of the company, so that we can invest in the system, support the dividend, maintain our investment grade ratings, all of which are critical to maximizing the value of our utilities and our nuclear fleet.
But we also retained the most upside to recovery of any merchant generator. Our 2012 open position is still 50% larger than that of the next largest merchant generator. And to further capitalize on our fundamental view of heat rate expansion, while protecting ourselves against decreases in underlying commodities, we use both gas and power put options, approximately 10% of our expected generation in 2011 and 7% in 2012.
Our third reason for optimism is our plan for organic growth. You are all familiar with our nuclear uprate program. In the second quarter, we brought about 30 additional megawatts online at our Quad Cities nuclear station. In transmission, we continue to evaluate and invest in projects that improve reliability and relieve congestion.
Exelon Generation has an agreement with Ameron to install a new transformer in early 2012 that will relieve congestion around our Clinton Station and improve pricing for our Midwest fleet in 2012 and beyond. Ameron has already made the requisite FERC [Federal Energy Regulatory Commission] filings for the upgrades, and we expect FERC approval later this summer.
Exelon Transmission and various other participants in what is called the Smart Study have completed the first phase of an analysis, which identifies three alternatives for high-voltage transmission lines to connect from Illinois eastward in PJM. Going forward, the Exelon Transmission team will tighten its focus on near-term projects and continue to assess where transmission value can best be captured within Exelon.
ComEd filed with the Illinois Commerce Commission last month to invest $178 million in reinforcements to our downtown Chicago transmission system, this would ensure reliability in the event of equipment failures and also in the event some generating units serving the loop are shut down.
PECO is already pursuing about $70 million of transmission upgrades near Eddystone and Cromby stations, which are necessary to ensure localized reliability after these units retire. And at our utilities, we are following our respective state policies and developing a balanced approach to our Smart Grid spend.
In Pennsylvania, we are required to build out a complete system. In Illinois, we are trying to do various substantial demonstration project, and to seek to understand the technology and its effect on our distribution network and customers.
Both PECO and ComEd are pursuing new base rates in their distribution business. We expect that these rate filings, along with reasonable load growth over time will position both utilities to continue to achieve earned returns on equity in the 10% range.
In summary, whether one is taking a hard look at future EPA regulations, acting on what is happening in the power markets today, we're pursuing a disciplined organic investment approach to our system. Exelon has and is taking advantage of the best upside position in our industry.
I will now turn the call over to Matt, who will talk in greater detail about our financial performance for the quarter and our outlook for the remainder of 2010.
Thank you, John, and good morning, everyone. As John mentioned, that I will provide an overview of the results for the quarter and highlight a few key drivers compared to our earnings guidance, and how we expect the results will affect us for the rest of the year. I will also give a brief update on our hedging activity and load forecast. The key messages for today's call can be found on Slide 6.
I echo John's sentiment on this quarter's performance. It was exceptional. We recorded operating earnings of $0.99 per share, well above our guidance for the quarter, primarily due to two drivers. First, higher rev net fuel at ExGen, mainly attributable to increase nuclear volumes and improved market conditions, and second, favorable weather at PECO and ComEd.
Our second quarter results were achieved despite incurring $0.03 per share of cost for severe storms that hit the ComEd and PECO service territories. With respect to the storms, thousands of dedicated employees under the leadership of Denis O'Brien, Frank Clark and Anne Pramaggiore, worked tirelessly to repair damage resulting from severe storm activity in late June. ComEd restored 90% of the 800,000-plus customer outages, resulting from two waves of storms within 24 hours. PECO mobilized its emergency response organization to restore service to the 330,000 customers affected by one storm that lasted 30 minutes. Both ComEd and PECO continue to raise the bar for rapid storm response and delivering on our commitment to keep the lights on.
Our quarter-over-quarter drivers for the operating companies can be found on Slide 8, 9 and 10. In lieu of walking through the quarter-over-quarter results, I'll spend my time providing additional insight into the two drivers that led to the second quarter earnings being above our guidance.
Starting with PECO on Slide 11. PECO's demand was higher than our plans for the quarter due to favorable weather. During the quarter PECO's actual cooling days were approximately 77% above normal. On a weather-normalized basis, PECO's second quarter load results for the large C&I class was above our last forecast, with most of the improvement coming from the Manufacturing segment, primarily steel and petroleum.
The second quarter results for the residential and small C&I classes were less than our last forecast due to continued high unemployment and the impact of PECO's Act 129 Energy Efficiency program. After updating the full year load forecast to reflect second quarter results, PECO's full year load growth estimate is now 0.1%, which still reflects second half load growth largely consistent with what we told you in our last earnings call in April.
Turning to ComEd's load update on Slide 12. ComEd's territory also experienced warmer-than-normal weather conditions. As a result, ComEd's actual results for the quarter were above plan with cooling degree-days for the quarter at almost 40% above normal. ComEd's weather-normalized consumption total for the second quarter was slightly better than our last forecast. Load activity for the large C&I and residential classes was more positive than expected, driven by continued recovery in the Steel and Auto segments for large C&I. Based on what we saw in the second quarter and our outlook for the remainder of the year, we are maintaining our full year forecast of 0.8% at ComEd, with the second half load growth largely consistent with what we told you in April.
Moving to Generation. Generation increase in rev net fuel for the quarter as compared to plan is a result of exceptional nuclear performance and improved market conditions. Generation's plants achieved a 94.8% capacity factor for the quarter, the best quarterly factor since the first quarter of 2009. Market conditions were better than our plan for the quarter particularly in the Midwest, where spot prices were higher than planned, which enabled us to benefit from sales of our open position. Since last year, we have held the view that there is upside opportunity in Midwest power prices. We continue to see signs of that view materializing. Slide 13 gives visibility to that upside that we expected. The NiHub and PJM West 2011 and '12 off-peak energy prices increased since the first quarter. At the same time, we are seeing coal prices stabilizing. We believe that the combination of stabilizing coal prices and the modest load recovery is contributing to the upside in prices, particularly off-peak prices.
During the second quarter, we continue to execute on our ratable hedging plan. Our portfolio is now 86% to 89% hedged for 2011 and 57% to 60% hedged for 2012. In comparison to the first quarter, the Mid-Atlantic reference price increased by $3 to $5 and Midwest reference prices increased by $2 to $3. And our open gross margin band in 2012 is up $350 million. During the quarter, we sold more in the Mid-Atlantic to capture the higher increase in APC [American Power Act] energy prices compared to the Midwest through various wholesale and retail channels.
We are optimistic about further upside in energy prices for many reasons, including the improving market conditions that I just spoke about and the clear signs of recovery John spoke of, including heat rate expansion and the 2013, '14 PJM capacity results. Slide 14 provides a visual of the capacity price results, which were very positive for Exelon given our significant capacity in the eastern zones of PJM.
Turning now to regulatory and legislative matters. ComEd filed its electric distribution rate case on June 30. This is the first case filing in almost three years of ComEd. We were able to defer filing rate cases during the recession, largely due to our work to tightly manage cost in conjunction with our work with stakeholders in Illinois, to institute riders like the bad debt rider effective earlier this year.
In a separate filing later this summer, ComEd will provide an alternative regulation structure for incremental investments and projects that are outside of the traditional rate proceeding, such as further investments in Smart Grid. We expect the new rates as a result of both of these filings to be effective in June 2011.
PECO also continues with its rate cases in preparation for its transition at year's end. During the second quarter, PECO completed its third of four planned procurement events proposed 2010 supply. The next and final procurement event for 2011 electricity needs will occur in September.
Let me now turn to recent news regarding the newly passed Financial Reform Bill and its potential impact to the clearing and margin requirements of transactions commonly used in our industry to hedge commercial risk. On that point, we are confident that the hedging transactions we enter into to manage our commercial risk will be exempted from the clearing and margin requirements. And we have measures in place to manage our liquidity now and in the future to support a substantial hedging program.
I would like to discuss and address one item that impacted GAAP earnings this quarter but is excluded from our non-GAAP operating earnings. In the second quarter, Exelon recorded a $65 million after-tax charge, reducing GAAP earnings by $0.10 per share associated with the remeasurement of income tax uncertainties related to ComEd's 1999 sale of fossil generating assets previously referred to as the involuntary conversion and the like-kind exchange positions and potential CTCs received by ComEd and PECO from 1999 through 2001.
Based on the status of settlement discussions with the IRS this quarter, we've concluded that there is sufficient new information for the involuntary conversion and the CTC positions to require a change in measurement of our reserves in accordance with applicable accounting standards, and the charge to earnings this quarter reflects our view of these settlements of these issues.
With respect to the fourth position of the like-kind exchange matter, we continue to believe that we will not be able to reach a settlement on that position, and that the like-kind exchange matter will be fully litigated. Our 10-Q, to be filed later today, provides more information on the financial implications of these tax matters.
Moving to Slide 15. You can see our projected sources and uses of cash for the year. We continue to be on track for 2010 with anticipated cash from operations of $4.6 billion.
Turning to Slide 16 for an update on our 2010 full year earnings guidance. We are raising our full year earnings guidance range up to $3.80 to $4.10 per share from $3.70 to $4 per share.
We are confident that the favorability we realized in the first half of the year, coupled with our positive outlook for solid financial and operational performance during the remainder of the year support this new guidance. In comparison to the first half of the year, our second half of the year earnings will benefit from fewer planned nuclear refueling outages, increased RPM capacity revenue while maintaining a continued focus on cost control. With respect to the third quarter, we expect our earnings to be in the range of $1 to $1.10 per share, which assumes normal weather.
Finally, I want to tell you about the change in when we will announce earnings guidance. We plan to introduce full year earnings guidance in the beginning of each year, and we expect this will be our practice going forward. This timing is better aligned with our planning and budgeting processes and for that end, 2011 earnings guidance will be introduced in early 2011, not at the November EEI Conference. We will continue to update our hedging activity on a quarterly basis, which as you know, drives a significant piece of our earnings.
To summarize, we are very encouraged about the financial and operating results this quarter and our outlook for the remainder of the year. The performance I spoke about, combined with the future perspective John shared, illustrates that small changes in market conditions can make a big difference to Exelon's bottom line.
This quarter, our earnings benefited from incremental improvements in load, nuclear volumes and market conditions. We are very well positioned to benefit from continued economic recovery and imminent EPA actions. I'll now turn the call back over to the operator for Q&A.
[Operator Instructions] Your first question comes from Hugh Wynne with Sanford Bernstein.
Hugh Wynne - Bernstein Research
I wanted to ask a question about the estimated impact of the Clean Air Transport Rule that you outlined in your first slide. And I guess my question is this, how do you expect the impact to capacity prices to materialize, particularly in Western PJM, where we see some coal-fired power plants owned by Edison and Ameren and Dynegy to be particularly vulnerable to closure. And the reason I asked is because it seems to me that the scale of potential retirements in Western PJM is sufficiently large that they probably can't be permitted by PJM and maintain desired levels of reliability, and measures will have to be taken therefore to augment capacity. It might include some of the transmission upgrades that you've mentioned, also RMR contracts such as you've mentioned and maybe demand-side management initiatives, as well. And I guess my question is, could you please walk us through how the capacity impact would play out given that some of these measures may not, in and of themselves, actually lead to the withdrawal of this capacity from the auctions?
We see it about like you do. The short answer to your three questions are yes, yes and yes. The way we look at it is, there will be very substantial impacts in the Illinois, Indiana, Missouri area that you described in your comments, that those impacts will be mitigated by combinations of transmission, RMR and demand-management activities. We still see very substantial benefit here for the values of Exelon Generation. And I want to ask both Ken Cornew and Joe Dominguez to supplement my answer because we worked very hard when we developed our Eddystone and Cromby RMR proposals to make certain that we weren't asking for things that were anti-market or anti-green. There are ways to do this that helped in both regards. So let me first ask Joe to comment with his insights on your questions, and then I'll ask Ken to back cleanup here.
Thanks, John. Hugh, let me break this into pieces. First, talking about the Transport Rule, we don't see the Transport Rule as a driver for retirements, not in its present version. I think what John referenced to in his earlier remarks is that the combination of two provisions in the Transport Rule: One, that it begins in 2012; and two, that it eliminates the value of historical SO2 and NOx allowances in the banks that exist will create a new allowance market in 2012, which, based on pricing we have seen in EPA's power price modeling, we would anticipate will have an effect of $2 to $3 on market prices beginning in 2012. That does not occur as that's in the energy market. That's not capacity market. Turning to the capacity market, we have looked at a number of the analyses of retirements that we'd expect and are not anymore getting worse, as well as pirates and many others that exist. Across the country, if we look at all of the RTOs, there is about 100 gigawatts of excess capacity above and beyond the NERC reliability requirements. So that if we see all of the retirements that are predicted even in some of the more severe scenarios, we would not see a shortage of capacity that would put the system in jeopardy from an overall capacity reserve margin basis. We will see, and John alluded to this, some hotspots where transmission upgrades will have to be made before units are allowed to retire, but the timing is important here. Because the capacity auction looks three years forward, unless the RMR lasts for three years or more, you would not affect the next capacity pricing cycle. So, for example, in the case of our Cromby and Eddystone RMR, we will have to run those units for a half a year and an additional year and a half. But they don't affect capacity prices because we would not bid them into the capacity auction. It wouldn't be available for the capacity auction that would be three years forward. And as a general matter, what we've seen in terms of our RMR agreement with regard to Cromby and Eddystone and our agreement with the environmental authorities, there are two important points to make. One, is that the units -- and there's two precedents for this, there's Potomac River case, and now our case. The environmental authorities typically do not allow you to run the units in the normal dispatch curve. What they expect unit owners to do is run them for reliability purposes only. That means units in RMR status will run fewer hours of the year, and will not have the effect of distorting power price impacts and allow market price signals to reflect the actual need for replacement generation. Secondly, under the PJM rules, units that have not cleared in the capacity auction aren't required to bid into the capacity auction and therefore, they're not treated as price takers. So while you may have a number of units in RMR status at different points in time, they would not be reflected in capacity pricing because they wouldn't be bid into that market under the existing tariff and under the specific agreements that exists in the FERC precedent.
Hugh, Joe and John I think it address pretty well the retirement situation, also associated with continuing to operate coal plants and those costs ending up in the bidding structure in the capacity market for plants that actually exist. Finally, we also have to consider declining energy benefits from these plants as historical energy benefits decline that results in higher cost to bid in the capacity construct, both driven by gas prices being lower and incremental and variable cost of dispatching these coal plants. So it's not only retirement, it's also the cost structure that defines the cost-base bids for existing capacity that are likely to be pushed higher.
Our next question comes from the line of Dan Eggers with Credit Suisse.
Dan Eggers - Crédit Suisse AG
John, I appreciate the dialogue and I guess if we were to take the conversation a little further when you think about mercury and any other impacts, what it would do to plant closures and necessary rises in capacity revenues, energy revenues, that sort of thing. How do you deal with the regulators by way of managing through the magnitude of rate increases that would presumably come with the sort of earnings transfer you see out the horizon and in particular, as you look at Illinois with the power authority and their ability to contract outside of traditional auction mechanisms. Is there a risk that some of these value transferred never ends up to you because the regulators get in the way?
There is always risk but I would point out that we have a lot of room for upside in '12 and '13 and '14 before power prices get back to the levels in total and in absolute levels or the levels of increases that we were talking about in the 2006 and '07 period. But yes, of course, there is risk and Joe and Darryl Bradford and Bill Von Hoene, Paul Bonney and a whole lot of other people will both be working on managing that risk and also working on ways of handling contractual negotiations so that these increases are feathered in an orderly way. We've been fairly good in finding ways to come up with long-term agreements that soften this volatility on a year-to-year basis, and we'll continue to hunt for those ends.
Dan Eggers - Crédit Suisse AG
And I guess one other question, John. You've had a more outspoken view on where the markets are going to go because of these policy events. Are you seeing any assets out in the market that seem underpriced ahead of what could be a significant recovery as you see the market going?
It's funny, we always see assets overpriced compared to companies. And I don't think we're seeing a lot of underpriced assets out there. We keep looking but the people who have the assets that we think will flourish best in this environment continue to carry pretty good prices for those assets. So we find that chopping is -- still work for parsimonious people.
Your next question comes from the line of Jonathan Arnold with Deutsche Bank.
Jonathan Arnold - Deutsche Bank AG
My question has to do with just trying to reconcile some of the comments you've made about your optimism in terms of seeing signs of recovery in the market and then just how much additional hedging you put on during the quarter? Looked like you added the best part of 10% and when I do the math on what ratable would mean in terms of getting to 90% type range for 2012, you wouldn't have had to add anything like that much. So can you help us to reconcile the amount of hedging you did and your comments on the market outlook, which seemed, in my view, to imply optimism around the near term as well as the longer term?
I will do my best. We have lots of reasons to hedge, and of course, I'll ask Ken to supplement this. One of which is to protect the dividend and the credit ratings in downside scenarios. Another is that the further you go out, the less liquid markets are, and we don't want to be in a position where we have issues over liquid markets. But as I said in my opening comments, we try to soften the effect of the hedging by using -- put options where we can. So we kind of hedge the downside on the basic commodities, but keep a chance to get the spreads that we think will be there. It's a constant conundrum for us and if we ever abandon the basic ratable approach, we'll let you all know. But right now, we think we should, more or less, stick with ratable. We do think the upside is real, and as we become more confident of that, can take it into account when it does. Ken, can you pick that up from there because the tension you described is clear and it's just that we want to have some absolute protection on the downside.
Sure, Jonathan. John highlighted the reasons we hedged and how we align our hedging with our financial policies, and you've heard that before. And he also highlighted the size of our Merchant Generation portfolio and held us three-year ratable hedging program had tend to allow us to orderly, in an orderly fashion, sell our portfolio in orderly, strategic way. Two or three years out, the portfolio is still had substantial upside from the open position as he has indicated. Another comment we haven't talked about as much in advance is our customers, wanting to buy power in that type of work-time range also. The competitive Retail business is typically a two- to three-year business. Polar options are typically two to five years, but full requirements products being in the two- to three-year range and then Block products going out five years, in which we have an opportunity to get some upside from environmental regulation. And finally, there are plenty of wholesale customers out there that are much interested in having generation in a forward sense than in a spot sense. Don't forget the price uncertainties that still exist in this marketplace. Economic recovery, obviously, spot gas prices still tend to be weaker than forwards and we have to watch that and be sensible about that. And you know the generation supply effect doesn't react that quickly. And John talked a lot about what's going to happen to the generation spot back in the future. But it is slow to react and likely not in this three-year timeframe significantly, and we have weather uncertainty. That being said, we've stayed ratable and we've gotten ahead -- we stayed ahead of ratable with our options as we did last quarter. If you look at that hedge disclosure, we're probably slightly behind the ratable pace in the second quarter in '11, slightly ahead in '12, and we did a lot of hedging in '12 in the Eastern part of our portfolio and very little in the Midwest part of our portfolio. So we try to balance that to keep some upside. So we continue to look at different products and locations and timing, just trying to keep as much upside as we can for you.
I would particularly note Ken's comments that some of his longer-term contracts include some premium for the environmental issues that we see.
Jonathan Arnold - Deutsche Bank AG
Could I ask a related follow-up? When you look at the forward curve for power out through PJM and NiHub and you see the kind of uptick there is in the 2014 curve, I mean, what do you attribute that to and then to what -- when you're kind of trying to deconstruct the curve, is there -- how much of that is the upside that you're describing and how much of it is just liquidity or whatever else in the curve?
Jonathan, it's obviously challenging to deconstruct, but my opinion is the majority of the movement in heat rates and power prices has been driven by spot prices and what we've actually seen this year relative to last year, we see much improvement in spot prices year-over-year. Congestion is significantly less year-over-year. We see some demand recovery, particularly off peak in industrial sectors in the Midwest. And we've actually gotten some normal weather and a little better weather. So I believe most of what you've seen so far is related to the spot market kind of rationalizing the forward prices.
Your next question comes from the line of Michael Lapides with Goldman Sachs.
Michael Lapides - Goldman Sachs Group Inc.
Two questions, not necessarily related to each other. First, demand. You're not-weather-adjusted demand trends during the quarter were pretty different, meaning, ComEd pretty strong, PECO, not so strong. Can you just talk about drivers of that and what you expect, not just kind of going forward in near term, but next few years, meaning, what are going to be the biggest drivers of demand differences across the two different regions?
I'll let Denis O'Brien from PECO and Anne Pramaggiore from ComEd pickup in this. But let me say that you accurately described the second quarter. But in the first quarter, PECO had a better pickup and on the whole, we're looking at demand growth between 0% and 1% this year, probably a little better in PECO going into the out years. ComEd, continuing in that vein unless, of course, the Air Quality Enrichment program that's going on around the country leads to consistently higher weather. But we see very soft recovery. We tend to see our very large customers coming back. A little improvement in our residential load, but what we would call the small commercial and industrial sectors remain very depressed. And with that, defers status on that end?
Philadelphia has had rather unique weather here with the first quarter having 70 inches of snow, the snowiest winter in history. A three snowstorms that stormed the region in, interesting enough. And June is the hottest month in Philadelphia in 137 years of record-keeping. So when you try to do your weather correction, you're dealing in some pretty unique space. If you put the first quarter and the second quarter together for us, residential growth is at 0% for us for the first half of the year. We see just a moderate grow from there, about 0.5% growth for the second half of the year. And a small C&I -- the second quarter did not look good when you put the two quarters together. It's about just under negative 3% growth. We saw the small C&I drop last year in the third quarter. So as we profile it from here on out, it's about a negative 0.5% from here. We see small C&I very slow in coming back. I think we're near the bottom there, but it's going to be a long way in terms of coming back. And then in the large C&I, the first half has had 1.4% growth. As Matt said, driven by the manufacturing sector. We've seen steel and petroleum, in particular, are being strong. That's been about rebuilding inventory and some benefit we've seen from consolidation of planned activities and more of those coming in to our region. The load that's coming to the region like consolidation of plants, we see that continuing on. Building of inventory, we do not really see that trailing off unless we see in the economy turn significantly. And when you add them together with some known information we have from the pharmaceutical sector, we see the large C&I pretty flat for the second half of the year in terms of -- comparison to '09. So all-in-all, we stand with our estimates, pretty flat for the rest of the year.
Michael Lapides - Goldman Sachs Group Inc.
Unrelated question -- lots of the PJM assets are either going to incur significantly more cost aka the unscrubbed coal units or shutdown. When you look outside of PJM, meaning the states to your north, to your west, and even some to your south, lots of -- have you looked at how many of those coal plant are actually being scrubbed and whether those coal plants can wheel power into Northern Illinois?
Joe Dominguez will take that.
Obviously, because of the imports into PJM, we look at retirements not just within PJM, but in MISO and to a lesser extent within SERC. So we have taken all of that into consideration. I think those are the three areas you can put your finger on that you're going to see the greatest impact in terms of coal retirements. This is certainly not a situation that's unique to PJM. I'd say, there are three NERC-reliability regions that are going to be most affected, and that's going to be PJM or RFC has called in NERC space, MISO and SERC are going to see similar numbers of retirements as a result of these new regulations, and we have considered that in our modeling space.
Michael Lapides - Goldman Sachs Group Inc.
But are you likely to of see a fundamental difference in the number of plants across scaler side that gets scrubbed in the states where, honestly, those plants are under traditional rate-making processes versus those that are in competitive markets. And how would that impact kind of the NiHub market?
I think there are two view points out there. One is, and I've read one view that regulated states will use this as an opportunity to retire plants and build new plants and the plants that are retired are generally older plants that don't have a lot of rate base value. So they will use this essentially as a tool to reshape the regulatory compact in those states. And obviously, there is another school of thought that don't hold on a little bit longer in the regulated states. The reality is that the cost associated with all of these environmental regulations, and I'm not just talking about air, here but layering on coal combustion waste and potential water regulations. It's going to be difficult for folks to pay for the plants that they want to keep open, the ones aren't really marginally economic or the ones that they really like and would like to retrofit to make them comply with all the environmental regulations. When you add on -- really putting on controls and doing that sort of thing on plants that are economically marginal, I don't think you're going to see behaviors that are radically different in monopoly markets as opposed to competitive markets.
I would just like to add to this and I'll let Ken sure will correct me if they think I'm wrong. But I guess, I see the picture in Wisconsin, Iowa, Missouri, Southern Illinois, the adjacent areas, a little bit more like some of the suppositions in Hugh Wynne's earlier question, the big new units that are most compliant, most valuable, tend to be in turf like Southern Duke, AEP, Dominion and I think if you look at Wisconsin, Iowa, Missouri, Southern Illinois, you tend to see a pretty large percentage of the older and unscrubbed units that would have the largest compliance for scrubbing. I say that based on both things I've seen in anecdotes but, Ken, did I overstate that?
No, John. You just said it perfectly and one more comment I would add is, regulated states and regulated entities don't typically build or maintain generation to export to other regions, they do it for their customers. So Michael, I would think that, that impact would be minimal from that perspective.
Cynthia, I think we have time for one more question, please.
Your next question comes from the line of Steve Fleishman with Bank of America.
Steven Fleishman - BofA Merrill Lynch
I guess with a commentary you made about the positioning on the environmental rules, what does this mean, if anything for how you're looking at kind of M&A, and I guess, maybe, are you still the hyena or are you more of a gentle elephant right now?
Steve, you've known me for much of the last two decades, and you know I'm always careful. We've been calling Hilzinger here at El Toro because of his optimism. But I doubt if anybody is going to start calling me the elephant anytime soon. Well, we remain very value-driven. We always look, we stay oriented towards cleaner fleets, rather then less-clean fleets. But we believe that this is an industry where you need consolidation. But to make it make sense for investors, it has to be earnings accretive in relatively early time periods. And it has to be consistent with our need to maintain investment grade credit ratings. So no, you're not going to hear a lot more trumpeting, trunk-waving or roaring around here. We're constantly looking for how you add real value, and that just didn't get to change as long as I sit here.
Steven Fleishman - BofA Merrill Lynch
But it also sound like your more focus still is on -- if at all, on value in the generation side as opposed to the regulated side?
Well, I wouldn't say that because we've liked some of the additional diversity that having more regulated business would give us. The problem is that the regulated integrators are, in my view, on an up cycle in their market valuation. And the commodity-driven companies are at the low end of this cycle. So you have to be very careful about using your own paper, which has more upside potential in the future to buy somebody who's more regulated and may already be higher. We'd like to have a little more balance. But it's very difficult to find one that meets our value equation criteria.
Cynthia, I'd like to turn the call back to John Rowe for a couple of closing remarks.
Just to wrap up, Exelon, as you all know, is just different from other folks. We're 2/3 to 3/4 of commodity business, and 1/3 to 1/4 of regulated set of T&D companies. And when you think about that, we kept our earnings well over $4 last year in the worst recession in decades. We're beating our expectations this year and if you look at our earnings range, you can see that we think we have a shot at something in the $3.90s or perhaps even over $4 this year. We should do a little better next year. As we've said, '12 is a little tougher. But I think you'd see growth again in '13 and '14. And I just leave you with this, there are very, very few commodity-driven companies that can hold earnings that well and give you the kind of upside that we can give you. And we're committed to making it happen. Thanks, everybody.
Ladies and gentlemen, that concludes today's conference. You may now disconnect.
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