艾索倫電力 (EXC) 2014 Q4 法說會逐字稿

Good morning, everyone. Thank you for joining for our fourth-quarter 2014 earnings conference call.

Leading the call today are Chris Crane, Exelon's President and Chief Executive Officer; Jack Thayer, Exelon's Chief Financial Officer; Joe Nigro, CEO of Constellation; and Bill Von Hoene, Exelon's Chief Strategy Officer. 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 earnings release this morning along with the presentation, each of which can be found in the Investor Relations section of Exelon's website. The earnings 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. Actual results could differ from our forward-looking statements based on factors and assumptions discussed in today's material, comments made during this call, and in the Risk Factors section of the earnings release and the 10-K which we expect to file later today. Please refer to today's 8-K and the 10-K and Exelon's other filings for a discussion of factors that can cause the results to differ from management's projections, forecasts, and expectations.

Today's presentation also includes references to adjusted operating earnings and other non-GAAP measures. Please refer to the information contained in the appendix of our presentation and our earnings release for a reconciliation between the non-GAAP measures to the nearest equivalent GAAP measures.

We have scheduled 60 minutes for today's call. I will now turn the call over to Chris Crane, Exelon's CEO.

Good morning and thanks for everybody joining. We had another strong year of operations in 2014, which we're very pleased with, given the challenging weather conditions at the start of the year.

At the utilities, each OpCo achieved top-decile performance for safety and top-quartile performance for outage frequency and duration. The nuclear fleet ended the year at 94.2% capacity factor, which this marks our 15th year in a row being over 92%. Gas and hydropower dispatch match was at 97%, and our renewable energy capture was at 95%.

On the financial side, we delivered $2.39 a share, in line with our recent full-year guidance. Exelon Generation delivered a strong year for performance in what was a volatile year, and our generation-to-load matching strategy drove strong results during an unexpected mild summer. The utilities performed well in light of severe storms and continuing challenging interest rate environment.

2014 was an active year for us. In addition to selling several assets, we continue the process of recycling capital and strengthening our balance sheet. I'll highlight some of our major investments for the year.

We grew across the enterprise. From the utility growth perspective, we announced the PHI merger and continued on with our infrastructure upgrade plan, spending $3.1 billion of utility investment.

On the merchant side we announced a state-of-the-art CCGT newbuild in ERCOT, and we added 215 megawatts in nuclear, wind, and solar capacity during the year. At Constellation, on the retail side, we completed the acquisition of Integrys retail and ProLiance.

We also made investments in adjacent markets and emerging technology to continue to prepare for an evolving marketplace. Bloom Energy and our micro-grid investments are good examples of that.

We also had a number of major regulatory developments in 2014 that affect both the utilities and the generating business. On the generating side we've see progress in Illinois nuclear discussions, with four reports released last month which highlight the reliability, the economic and the environmental benefits of the nuclear plants to the state.

PJM capacity performance proposal has been submitted to FERC. We strongly support the steps being taken to ensure reliability in the region. We expect a continuing discussion on the EPA's Clean Power Plan over the next several months.

On the utility front, we had two positive outcomes for ComEd and BGE rate cases. ComEd received 95% or more from our ask on the last three consecutive rate cases; and BGE achieved its first settlement since 1999. These outcomes highlight our continued commitment to the customers we serve. Bill is going to go into greater detail on the advocacy issues towards the end of the call.

These policy initiatives on the horizon present a potential material upside to earnings, as value of our fleet is more appropriately recognized by the market. However, I do want to underscore that the management team is focused on EPS growth and our capital deployment efforts.

We invest in prudent growth at the utilities where we can add value for our customers; and within our merchant business we look for opportunities to earn robust financial returns. Our recent announcement announced a peaker in New England as a great example of that. Our continued investments in both the utilities and the Generation business demonstrates our commitment to long-term growth initiatives across the enterprise that will bring value to our customers and drive future earnings.

Now let me turn it over to Jack to discuss our financial expectations for 2015.

Thank you, Chris, and good morning, everyone. We've provided information on our fourth-quarter financial results in the appendix of today's materials on slides 17 and 18. I'll spend my time this morning on 2015 earnings guidance and our O&M forecast.

Turning to slide 3, we expect to deliver adjusted operating earnings in the $2.25 to $2.55 range, which is the same as our 2014 guidance; and earnings of $0.60 to $0.70 per share for the first quarter. Our guidance does not include the earnings from the Pepco Holdings acquisition, but does reflect all asset divestitures to date.

As you know we sold several assets last year, the proceeds of which are being used to partially finance the PHI acquisition and to recycle capital on the merchant side of our business. The lost contributions from these divestitures result in an earnings impact of $0.12 per share relative to last year.

In future years, there is minimal earnings impact, in particular as the capacity revenue from Keystone and Conemaugh runs off. The modest lost earnings from the divestiture plans will be meaningfully offset by the accretion from our Pepco merger and earnings from other growth projects.

For 2015, the earnings impact from these divestitures of $0.12, combined with an additional refueling outage at nuclear of $0.02, and increased pension and OPEB costs at ExGen of $0.02 are modestly offset by higher capacity prices of $0.07, the full-year benefit of the elimination of the DOE fee at Exelon Nuclear of $0.04, and by higher earnings at ComEd of $0.03.

As you know, at EEI we gave earnings projections for Exelon's three utilities through 2017. Since that time we have adjusted the midpoints of that guidance down by a total of $0.05 per share due to the impacts of Treasury yields at ComEd and bonus depreciation's impact on EPS. We still expect a healthy 5% to 6% CAGR on utility earnings from 2014 to 2017; and the cash benefits from bonus depreciation will help accelerate and fund utility investments.

For reference and deeper analysis, more detail on the year-over-year drivers by operating company can be found in the appendix on slides 19 through 22.

As Chris mentioned, our capital investment plan is significant and positions us to grow earnings over time. Over the next five years we are investing $16 billion in capital at our existing utilities and plan for more than $6 billion of investments at the Pepco utilities. We believe these investments are prudent and will improve reliability and our customers' experience.

As you know, the Pepco transaction is expected to add $0.15 to $0.20 per share of earnings on a steady-state basis in 2017 and beyond. In addition to growing earnings, the Pepco acquisition shifts our earnings mix to a substantially more regulated weighting, with 61% to 67% of earnings coming from the regulated side in the 2016 through 2017 period.

On the ExGen front, our focus is deploying capital for growth that achieves attractive financial returns and generates both earnings and cash flow. These investments span the energy value chain and include conventional Generation, like our Texas CCGTs and a newbuild peaker in New England that cleared the most recent capacity auction, and investments in our distributed energy platform.

Above and beyond our existing plan we see additional opportunities and have the free cash flow to deploy capital to earn attractive incremental returns on both the regulated and merchant sides of our business. Starting in 2016, we expect to have up to $1 billion in incremental annual capacity we can deploy to invest in our utilities, merchant growth, and other opportunities.

At the utilities, we are evaluating the potential to increase our investments in utility infrastructure, including grid resiliency and security, storm hardening, and new smart-grid-enabled technologies. Of course, our capital investment in the utilities has to be prudent and help meet the evolving expectations of our customers.

These investments will benefit customers by improving reliability and system performance and allow them to better understand and manage their energy usage and costs. At ExGen, capital deployment across the business will be driven by the ability to earn robust financial returns.

Slide 4 shows our 2015 O&M forecast relative to 2014. We project O&M for 2015 to be $7.225 billion, an increase of $275 million over 2014.

The increase at ComEd and BGE is due to inflation and increased budgeting for storm costs, which results in incremental year-over-year O&M growth. ExGen's increase is related to a combination of factors: the inclusion of three months of CENG O&M relative to 2014; an additional planned nuclear outage compared to 2014; increased pension costs; and projects at Constellation and Generation, including Integrys and growth in our distributed energy business.

Overall, we expect a basically flat O&M CAGR over the 2015 to 2017 period. We remain disciplined on cost even as we seek to grow our business.

Since our presentation at EEI we have increased our CapEx projections for 2015 across the Company by approximately $325 million. The increase is primarily at ExGen and reflects investments to build contracted generation, including an 80-megawatt wind facility in Texas and an up to 50-megawatt biomass plant in Georgia which we announced yesterday.

Additionally, we have increased the 2015 budgeted CapEx for our Texas CCGTs, advancing the timing of the capital spend. The total cost of the project has not changed.

Now I'll turn the call over to Joe Nigro for a discussion of markets and our hedge disclosures.

Thanks, Jack, and good morning. The Constellation business continues to perform at high levels. We finished 2014 strong and are seeing solid results so far in 2015 as a result of our generation-to-load matching strategy and our ability (technical difficulty) channels to market.

My comments today will address market events during the fourth quarter and what they mean for our commercial business going forward, including our hedging strategy, the New England ISO capacity market results, and our updated hedge disclosures.

During the fourth quarter we experienced a decline in prices across the energy complex, as oil and natural gas both realized steep losses in the spot market. Power prices followed gas lower in the second half of the quarter, as expectations of extreme weather subsided.

The primary driver weighing on prices was the contraction of winter premiums as the market's focus moved away from last year's Polar Vortex and on to higher natural gas production and storage estimates. NIHub and West hub around-the-clock prices were down $1.50 to $3.00 for calendar years 2016 and 2017 from the end of the third quarter to the end of the fourth quarter.

In response, we have positioned the portfolio to better align with our fundamental view that we expect to see seasonal power price upside primarily at NIHub and began to build a long position into the forward years. This is similar to how we positioned the portfolio the last few years when our fundamental view showed power market upside.

When the market is volatile, our generation-to-load strategy allows us to optimize the portfolio to lock in additional value. During the year, we aggressively pursued load-following sales when we observed appropriate risk premiums and increasing margins.

We are very highly hedged in 2015 and not impacted from the large downturn in near-term power prices. In fact, we were very aggressive in hedging our PJM East and New England portfolios early in the fourth quarter when higher-risk premiums were priced into the market.

The remaining length in 2015 is mostly in our Midwest position and focused in the months and time buckets where we believe the forward market is still undervalued. As I mentioned, we began to build the long position in the forward years because we see upside in our view versus market.

During the fourth quarter, we dropped further behind our ratable plan and added approximately 5% to our hedge percentages for 2016 and 2017, versus a normal quarter of an 8% sales. The majority of our behind-ratable position remains in the Midwest, where we continue to see upside in power prices driven by coal retirements.

Not only did we adjust our deviation to ratable during the quarter, but we also adjusted our seasonal hedging strategies, holding length in undervalued months. We will continue to hold a long position based on our market views.

Last year at this time we talked about hedging with natural gas to take advantage of our bullish view on heat rates. Those views have materialized over the past 12 months, and we have shifted our hedging strategy out of these cross-commodity hedges in order to lock in the higher market implied heat rates.

In January of last year, natural gas sales represented over 10% of our hedges. Currently, they are less than 2% in any given year. Going forward, our hedging strategies and positions will continue to reflect where we see upside versus current market prices, both from our view of heat rate expansion and natural gas price increases.

We've gotten a lot of questions recently on oil markets, and I'd like to spend a minute on what the sharp decline in pricing means for our business. We are not materially impacted by oil pricing, mostly due to the fact that our gross margin is primarily driven by our large baseload position.

However, we do experience some minor impacts, including: the potential for lower peak power pricing during heavy load conditions; the potential for lower load growth in ERCOT; and lower pricing in our upstream business. The current pressure on oil prices is more pronounced in the near-term delivery periods, as longer-term prices in the $65 to $70 per barrel range still reflect global demand growth.

Before I turn to our gross margin update, I want to provide an update on the recent capacity auction in New England. On February 4, ISO New England released the results of its ninth forward capacity auction for the planning year 2018/2019. The clearing price indicates that the new pay-for-performance capacity construct works and will attractive development of new resources needed in the region. This includes our recently announced 195 megawatts of dual-fuel peaking facility at our existing West Medway site, which we expect to have online by the summer of 2018.

Turning to slide 6, I will review our updated hedge disclosure and the changes since the end of the third quarter. In 2015, total gross margin is unchanged. The impact of the divestiture of Keystone and Conemaugh was offset by the acquisition of Integrys and the expectation of favorable portfolio performance.

We executed on $100 million of power new business and $50 million of nonpower new business during the quarter. Based on 2015 performance to date and expectations for the full year, we have increased our power new business target by an additional $50 million.

For 2016/2017, total gross margin decreased by $200 million and $250 million, respectively, largely driven by the impact of lower market prices on our open position. The divestiture of Keystone and Conemaugh was offset by the addition of Integrys in these years.

We also executed on $50 million of both power and nonpower new business in 2016. Overall, the commercial businesses are performing extremely well across all of our business lines. We will continue to implement hedging strategies that reflect our fundamental view of increases in both power and natural gas markets and optimize our portfolio.

Now I'll turn it over to Bill.

Thanks very much, Joe, and good morning, everyone. As Chris referenced in his opening statements, there are a number of developments playing out on the policy front that affect our customers and our businesses. These issues are not necessarily earnings impactful in 2015, but they may have a material impact on the Company beyond this year, and so we are going to spend a few minutes this morning sharing with you our perspectives on the issues.

I'll start with three issues affecting the Generation business in policy space, first on the capacity market reform front that Chris referenced. We have been involved in PJM's stakeholder process to develop a proposal that will harden the power supply system to help it withstand extreme weather events and ensure reliability for customers. We believe the proposal that now sits before FERC is constructive and, if approved, will address the gaps in system reliability.

The proposal has many similarities to the pay-for-performance market design which FERC approved in New England a couple of years ago. It's a no-excuses approach that provides fair compensation to reliable assets that do perform and penalizes suppliers that do not.

We think this is a win-win for our customers and for our Generation business. We have invested billions of dollars in our fleet over the years to make it the most reliable set of generating assets in the country, and we think that the fleet will fare well in a pay-for-performance system. All told, we view developments on the capacity reform front as decidedly positive, and we are expanding a ruling from FERC by April 1.

Second, let me talk briefly about the discussions that are ongoing in Illinois. As Chris referenced and as you all have seen by now, the state of Illinois report on potential nuclear power plant closings was issued earlier this year in response to House Resolution 1146. As stated in that report: The right energy policy for Illinois should guarantee reliability and improve the environment while creating and retaining jobs, growing the local economy, and minimizing cost. It is difficult to envision such a policy without nuclear as a critical part of the energy mix.

The report offers an independent assessment of the substantial economic, environmental, and reliability benefits that Illinois's six nuclear plants bring to the state and lays out five options to address the current situation: establishment of a cap-and-trade program; imposition of a carbon tax; adoption of a low-carbon portfolio standard; adoption of a sustainable power planning standard; or reliance on market and external initiatives to make the corrections. We are supportive of any of the options that reward all carbon-free resources equally. But doing nothing simply is not a viable economic option if we are to maintain the operations of those plants that are at risk.

As we've stated repeatedly, we do not seek a bailout. This is about addressing market flaws to properly value resources that are of great importance to the state of Illinois. The state has an opportunity to implement needed change, and we will work with policymakers and stakeholders during the coming months to come to an appropriate conclusion soon.

Third, on the Generation front, a brief discussion of the environmental policy. As you know, the EPA's Clean Power draft was issued last year. While it is well intentioned it fell short, in our view, of addressing the importance of nuclear to achieving our national environmental goals.

We continue to work on improving the plan. Notwithstanding the shortcomings of the initial proposal, however, we view the environmental discussion as progressing in the right direction.

Furthermore, the EPA debate and the states' roadmaps to implementing the plan are inextricably linked to the discussion around nuclear energy in Illinois that I just referenced, as any solution must contemplate the state's ability to comply and to do so cost-effectively. Without the clean attributes of nuclear, that will be impossible.

The final ruling on the EPA's plan has been pushed back to later this summer. Like many, we want clarity on the issue; however we would rather the time be taken for the agency to get this right and design a rational emissions reduction policy for the country, than to rush it through. We are confident that the EPA will issue a final rule that appropriately values our assets.

The question that arises from all of these pieces is: How do they fit together? And will the resolution of these three policy issues translate to market-based compensation sufficient to maintain the economic viability of our challenged assets? That is what will play out over the next few months or longer.

In the aggregate and individually, we view these potential policy changes as a positive driver for the Exelon fleet. If the PJM reforms are adopted, this should benefit all of our PJM nuclear assets.

However, we have been clear that there is no silver bullet. Each plant has to stand on its own economic merits; and it is unlikely that the PJM reforms in isolation will ensure the survival of each plant.

One clear example of this is Clinton, which is not in PJM and therefore will not be properly valued as a result of the PJM capacity market reforms. These plants need to be fairly recognized for both their unparalleled reliability and for their zero-carbon attributes. Anything short of that recognition is insufficient, and that is why we have been working diligently and simultaneously on all the fronts I have referenced.

The fact is, there is no other technology that produces reliable, zero-carbon electricity. All of the alternatives are intermittent and far more expensive than keeping these plants in operation.

Our customers will pay more if these assets are retired prematurely and need to be replaced. We think policymakers get this and also understand what it means to lose these plants in terms of jobs and costs. We are optimistic that they will take the steps needed to ensure fair treatment of the units, because it is clearly in the customers' and the states' interest to keep these plants open.

Finally, on the regulatory front, let me turn to a non-generation matter, which is of course the Pepco transaction which we announced last year. Getting the merger with Pepco across the finish line is, of course, a very high priority for the Company, and things are progressing according to plan. We continue to anticipate a closing some time in the second or third quarter of this year.

We are pleased to have received approval from New Jersey earlier this week. And as you know we have already received approvals from FERC and the state of Virginia.

In Delaware, as noted in a letter to the commission that you have seen, we are close to a settlement; and if a settlement is reached there may be an adjustment in the schedule. We are continuing the process of review in the remaining jurisdictions of Maryland and Washington, DC.

We believe the merger is in the public interest, and we expect that the combined Company will bring significant value to customers, given our top-tier operational performance and the merger commitments we have made. We look forward to completing the regulatory process and closing the transaction on schedule.

Thank you, and now we will open up the floor for questions.

(Operator Instructions) Greg Gordon, Evercore ISI.

Thanks. Good morning, guys. Jack, can you comment again on the -- can we revisit the comments you made on the earnings guidance for the utilities? Because as I look at the $0.20 to $0.30 from BGE, $0.35 to $0.45 from PECO, and $0.45 to $0.55 from ComEd, if I just take the exact midpoint there, that's $1.15 versus $1.25 at the midpoint of the EI.

So that's a $0.10 delta, not a $0.05 delta. Is there a reason why I am miscalculating that?

No, Greg. The $0.05 delta was with respect to 2017. The 2015 guidance, to your point, is down $0.10.

Some of that is just a mere factor of rounding. We speak in terms of $0.05 increments, and I would say 2015 guidance is down on a relative basis $0.05 year-over-year, although the rounding would indicate that it's down $0.10. It's just a matter of how we round it up or round it down in our expectations. (multiple speakers)

Okay, so the earnings power out in 2017 of your three utility businesses is $0.05 lower than your prior expectation, not $0.10?

That's correct. And I think importantly there, you see the sensitivity we have to interest rates, primarily ComEd. You see the impact of the bonus depreciation, which has the obvious EPS impact of lowering rate base and lowering expected earnings.

But also the cash flow and savings related to that is a contributor to the $1 billion of incremental capital we see in 2016 and beyond that we can deploy to grow both our utilities business as well as our merchant business.

Okay. Another question, because I think there is a bit of an apples-and-oranges going on in terms of the discussion. Now that you've given us an earnings guidance for this year that includes the $0.12 dilution from the Generation -- from the asset sales that you are using to fund the Potomac transaction, as we roll into -- if we assume that that deal closed precisely on 12/31, is it accretive by $0.15 to $0.20? Or is it accretive by $0.15 to $0.20 all things equal off this base? Or is it more accretive because you are also offsetting the dilution from the asset sales you used to fund the deal?

The $0.15 to $0.20 number, Greg, that we reference incorporates the net dilution associated with the asset sales. That said, as I mentioned in the script, the earnings contribution from those assets, while admittedly $0.12 this year, because of the failure of Keystone and Conemaugh to clear capacity markets, the contribution from those assets diminish meaningfully out the curve.

The $0.15 to $0.20 that I referenced we would anticipate in 2017. So that's while we're -- while you mentioned a close in 12/31, obviously per Bill's comments we are anticipating a Q2 and Q3 close.

We wouldn't expect to see all of that $0.15 to $0.20 until 2017. We will be certainly achieving part of that during the 2016 period.

Got you. I get it. So the math on the earnings contribution from the assets sold, they would've been significantly less than a $0.12 contributor out in time.

Correct.

Okay. One more question, just in a little bit of the weeds on the forecast for O&M. You did call out increased O&M, predominantly at BGE, ComEd, and ExGen. Then you say that through 2017 you expect 0.2% growth.

Specifically at ExGen, as we get out into 2017 is that growth rate pro-rata across all the businesses? Is ExGen's O&M roughly static?

Because I know you are adding assets to the mix in 2017, and I'm wondering whether there is a significant increase in O&M associated with that, or whether the totality of the O&M is still only growing nominally inclusive of those new asset additions.

It's pretty static, Greg. Certainly we are adding those assets, the operating cost of which will increase. We added Integrys; we added ProLiance. We have announced in recent months both a waste-digesting plant out in LA, a pulp and biomass facility down in Georgia partnered with P&G. We're looking for incremental opportunities in that space.

We're offsetting that in part with activities that we are pursuing broadly across the Company to drive lower operating cost both within the embedded businesses -- so Constellation, the power generation business, the nuclear business -- as well as our business services corporation. So on a blended basis, we see relatively flat O&M further out the curve.

Obviously, wage inflation is a component of that. Interest rates have been a meaningful factor of that, in driving pension costs and the growth in the liability side of that higher. So as CPI oscillates, as interest rates move, that will continue to be, candidly, something a little bit outside our control, but obviously something we are trying to focus on other things to offset.

Great. Thank you, guys.

Dan Eggers, Credit Suisse.

Hey, good morning, guys. Just following up on Greg's question on the utility outlook. If you go back to a year ago when you guys gave guidance, I think that all these expectations are down about $0.15 today from where they were a year ago.

Can you just bridge for me what has changed, a year-to-year basis? And then if you thought about interest rates normalizing or pension normalizing, how much of the $0.15 erosion could you reasonably get back?

I don't know that, Dan, I can track you back to year-end 2013, but clearly you've seen a material degradation in the interest rate environment. As an example, in 2014 the average 30-year was 3.34%; the interest rate for 30 years today is 2.63%.

So just even within on an average basis a full year, the continued decline of interest rates and our sensitivity to that through the formula rate at ComEd has been significant. For sensitivity, say 25 basis points up or down in interest rates is a $9 million improvement or detriment to our expected revenues at ComEd.

Obviously, the same element is impacting us from a pension liabilities side. Marry that with a change in the mortality tables and longer expected lives of our pension and OPEB participants, and that is a headwind.

That's a headwind that we pass through, through the formula rate within ComEd. But we have to go through rate cases at PECO and we have to go through rate cases at BGE to recapture that.

Then I guess the final element that's changed, I think, is given our load sensitivity at PECO, and given some of our longer-term load sensitivity at BGE and ComEd, as we've continued to experience zero, in some instances negative load growth, that's been a headwind as well.

That said, we continue to see meaningful opportunities to deploy capital in that space. We see an opportunity to drive our customers' reliability and experience. And importantly, we see opportunities to earn a fair rate of return in those businesses -- and as we are delivering an evolving array of services to our customer, even perhaps improve upon what we are allowed to earn.

Okay, got it. I guess just on the deployment of capital conversation, what are you guys seeing in the ERCOT markets at this point in time underlying the newbuild decision? It seems like sparks have eroded since those plants were announced.

And obviously with maybe an economic slowdown because of oil and gas drilling, there's a little bit of concern in the market, I suppose, over demand growth.

Yes, Dan; it's Ken. We are very comfortable with our decision to invest in our combined-cycle plants in Texas, and there are several reasons for it. First, the technology we've chosen we think puts us in a significant competitive advantage.

Again, as you know, with the position in the stack we would have, as well as the ramping capability of the units, also a cost advantage. Given we own these sites, we have an advantaged cost position that we don't think could be matched in the market.

Importantly, we made this investment on our long-term fundamental views. And without talking about every assumption in our fundamental views, they're not drastically different than the environment we are seeing right now.

We didn't make a bet on massive load growth in Texas. We were very conservative in our assumptions.

And the last thing I'll say, Dan, is we have a significant load business in Texas as well. And having these plants and this capability, and matching that capability with our load business, is something -- I think you are seeing it right now. We've proven that that is a value proposition that Exelon brings to the table, and we expect that the investment in these plants will really enhance that value proposition in Texas.

Okay, thanks, Ken. I guess, Bill, can you just walk us through what kind of timeline we need to see in Illinois as far as draft legislation on carbon action, and progression to get something done before the recess in the summer?

Yes, Dan. As you know, the recess is scheduled, or at least currently scheduled, for the end of May. What we anticipate is that legislation consistent with the policy solutions outlined in the 1146 report will be introduced in the General Assembly sometime within the next month.

We are actively working with legislators, regulators, and stakeholders with that in mind. So I would expect to see something surface within the next month, and that will give ample time for the legislature to consider it.

There will be hearings related to 1146 or possibly to the legislation specifically that will accompany that. But if this gets introduced, as we anticipate, within the next 30 days or so, it will give an opportunity to go through the full discourse in the legislature before the recess in May.

Okay. Thank you, guys.

Jonathan Arnold, Deutsche Bank.

Yes, good morning, guys. Quick one, first, just on Illinois, following up on Dan's question. Is there a sponsor that has yet emerged, or sponsors? or are you still working that out?

Jonathan, there has been nothing publicly announced. There will be a significant number of sponsors, and it will be bipartisan. But that won't be revealed until the legislation itself is actually announced.

Well, as you've just said, you're expecting it to be broadly supported?

Correct. We anticipate Republican and Democratic sponsors in significant numbers.

In both houses? Or is it going to emerge in one house and then go to the other?

The mechanics, it has not yet been determined what the mechanics will be. But there will be adequate support and sponsorship in both houses to run it through the legislature.

Great. Then if I could also just revisit the question on the regulated guidance -- sorry to do this. But, Jack, when I look at the $1.11 starting point for 2014, which was pretty consistent with the EEI slide, and your statement that 2017 is only down by $0.05 in the midpoint, which would imply $1.35 versus $1.40, I think where I'm having confusion is that you'd said -- you'd called that an 8% CAGR at EEI. But now you are saying 5% to 6%.

But seems to me the $1.11 to the $1.35 would be more like 6% to 7%. And 5% to 6% implies a bigger reduction. Can you speak to that at all?

I think, Jonathan, we're talking about 100 basis points; and to be candid, the rounding issue comes into play. So I think I'd focus more on the $0.05 of degradation from EEI's 2017 expectation to where we sit today.

(multiple speakers) And some of that is an issue of the timing of capital deployment and other elements. And I think we feel good about 5% to 6% growth.

Ideally, we'll endeavor to deliver higher growth. That $1 billion of incremental spend in 2016 and beyond is potentially a driver of that incremental growth.

But the $0.05 is what we should really focus on?

Yes.

Got it. Thank you.

Steven Fleishman, Wolfe Research.

Yes, hi. Thank you. Not to beat a dead horse with that, does your viewpoint on the utility include any of the $1 billion being reinvested in it? Or that would now be in additive?

(multiple speakers) It's additive.

Great.

Incremental.

Thanks. Then just with respect to the Illinois legislation, I know there's other aspects of this, not just on nuclear plants. So maybe you could give us a little bit a better sense of what else might be addressed in this legislation.

I'm assuming it's also renewables. But is there other aspects that would likely be in this?

Steve, this is Bill. The legislation that we are referencing in the nuclear is standalone for the time being. There are going to be, undoubtedly, additional energy-related initiatives.

There was a group that convened last week called the Clean Jobs Coalition, which was an environmentally directed group of a number of agencies and entities, which indicated that they will introduce legislation that will relate to energy efficiency, to renewable standards, and also to a cap-and-invest system that would be implemented in connection with 111(d). So we anticipate that that will be legislatively active, and there undoubtedly will be a variety of other things that will be considered as well.

Okay. Just lastly, and maybe to Joe, on your point of view in your hedging, just to clarify, it sounds like you are particularly focused on future NIHub prices being too low. Is that fair?

Yes, Steve, I think there's two elements. I think you are correct when you think about the expansion opportunity in heat rates, I think that's primarily in NIHub. I think from our perspective as well we actually see upside to the natural gas market, especially -- it's maybe to a lesser extent in 2016 and more so as you move out into 2017 and 2018 on the back of demand pickup from where prices are today. That would be true, for example, both at West Hub and NIHub.

You can see in the quarter that we sold less than our ratable plan, approximately 5% of our total portfolio; whereas an average quarter we would sell about 8%. And we rotated out of a lot of the gas shorts that we had because of the big heat rate move we had.

So as we move forward, as we built a position that falls behind ratable, it's going to be done more on a, I will call it a flat price basis, where we are just going to take the power that we would have normally sold and just hold it in our portfolio; and we'll tailor that to locations and time buckets. NIHub will be a big piece of that, but we will be looking at other areas as well, depending on what we see in the gas market.

Okay, thank you.

Julien Dumoulin-Smith, UBS.

Hi, good morning. I wanted to ask a little bit of a bigger-picture question here around the direction of the Company, vis-a-vis utility versus merchant. As you think about that decision point, you've obviously made a couple decisions over the past years -- Pepco namely -- how are you thinking about positioning the Company towards the merchant side of the business?

Specifically as you think about A, potentially expanding nuclear; and then, B, specifically expanding into Texas, are either of those avenues palatable or desirable under a merchant expansion? And then, more broadly, is a merchant expansion desirable at this point in time?

We continue to look at both sides. The utility business, as we talked about, we can operate the utilities well. We can drive efficiencies in. We can improve the customer experience, and while we are getting returns.

We are in a unique situation with ComEd on the formula rate at some historically low interest rates. We are not running from the investment in the utility business; we think interest rates will normalize, and we'll be at the right place for the returns. So we'll continue to make prudent investments and operate the utilities well there.

On the merchant side, it's all about the value proposition in looking at the specific investments. If a nuclear plant came available, and we could fold into the portfolio and see our adequate returns, we would surely have the scale and the scope to put one in.

We don't see any out there right now. But newbuild is not an option, so that's the only way we would get it as an acquisition.

As we've said before, we do think Texas is one of the more interesting markets to invest in right now. That's why we're proceeding with organic growth down there.

We do look at assets that come up from time to time in the ERCOT market. Most have been overvalued from our perspective on the long-term fundamentals. That's why building these new technology units makes more sense to us.

So we'll continue to look for opportunities on both sides of the business and use the balance sheet prudently to make the investments. But one thing that we -- in the last couple of years as we do our asset valuations on an annual basis, recycling capital has become a focus; and we'll continue to watch that.

If we see assets that others have more value on, and we can deploy that capital into other arenas, we will not be shy of any divestiture. And that's what we did this year, with divesting assets and having the opportunity to use that capital into what we think is something that would be strategically valuable for us with Pepco. And also having -- creating the balance sheet space to make the investments in new units.

So we are still very confident in the model and confident in the investment theses. And if low interest rates are hard on pensions and they are hard on the formula rate, but in the long run we see those coming back, and we still think it's a good investment thesis.

All right, great. Than secondly, if you could comment more specifically around Ginna in New York, obviously there's been some development there. What's your latest expectations, if you can elaborate?

Chris, you want me to take that?

Joe is going to grab it.

Great.

Julien, it's Joe Dominguez. We continue negotiating the RSSA with our counterparties up there in New York. I think you'll see developments become public on that within the next few days to a week.

Got you. Fair enough. Thank you. Good luck.

Stephen Byrd, Morgan Stanley.

Morning. Wanted to -- I think I had heard on the call that Keystone and Conemaugh have not cleared in the PJM auction. If that's correct, I wondered if you could just elaborate on the rationale.

I thought of those as large, well-operating coal plants. I'm just curious. What was the driver behind that?

Stephen, this is Joe. Good morning. There is a couple of reasons for that.

First of all, as you know, under the mechanisms afforded in the PJM model, you can calculate an avoided cost rate on each of your units. And we take the opportunity with our fossil units in particular and all of our fossil units to do that.

That sets what I would call a cost base line. And recognizing what we need from a cost perspective on those units, we take that into account in our bidding strategy. And we have a host of other assets that we have to look at in particular to make sure that we are looking at this in a proper sense from a total portfolio basis.

The way the math worked for Keystone and Conemaugh in particular, it just didn't clear, given where the clearing prices were for that particular auction.

So, Stephen, just a little to add to that; it's Ken. There are substantial costs at the plant associated with environmental upgrades. That associated with the avoid, the energy benefits that were very low from that 2009 to 2013 period, drove the avoided cost rates up at those plants.

And as we said before, the market works when participants bid their costs. And that's what we do.

Okay, great; thank you. Just shifting over to the utility, in terms of achieving the growth rate that you've laid out, what kind of load growth assumptions -- your latest thinking that's driving that growth?

Denis, you got that?

Yes, Chris. The load growth is really flat to slightly positive for the next few years. What we've seen for the last couple was flat to slightly negative. We see the next five years or so flat to slightly positive.

Okay, great. And that's driving the change in terms of the outlook from flat to negative, to flat to positive, what's your -- just at a high level -- view of what would drive that improvement in load growth?

I think it's just the general economic health of each of the service territories that we serve.

Okay. Thank you very much.

Hugh Wynne, Sanford Bernstein.

Thanks. The $435 million asset impairment charge this quarter, how does that break down between Keystone, Conemaugh, and then upstream assets and other?

Hugh, in total of overall long-lived asset impairments that we had during the year, we had a wind impairment that was $0.06; we had a lease impairment that was $0.02; we had Quail Run assets held-for-sale impairment of $0.04. Keystone and Conemaugh was $0.29 of that. Upstream was $0.09, for a total of $0.50.

On the flip side of that, we had $0.28 of gains related to the sale of Safe Harbor, the sale of Fore River; a gain on the sale of West Valley. So overall on a net basis it's about $0.22 negative impact on the year.

Okay. Then my question for Bill. Bill, you're a lawyer, and you were talking about the potential implications of the Clean Power Plan, EPS Clean Power Plan. I just wanted to get your views as to the likelihood that the plan survives at all.

I understand there's been challenges as to whether EPA has authority to regulate CO2 under 111(d) in the first place. And then secondly if it does, whether that authority extends to energy efficiency and renewables.

Is this Clean Power Plan going to be with us in the long run? Or do you think it's going to be whittled down or overturned altogether?

Well, one thing that we can be abundantly certain of is that there will be litigation respecting whatever the final rule will be. But the basic tenets, Hugh, of the underpinnings of the rule are legally sound. The ability to regulate carbon emission has been already ruled upon by the United States Supreme Court.

And our expectation is that there will be litigation and there may be modifications that result from that. But the basic underpinning of the rule will survive and will have impact that will be significant in that scope.

All right. Thank you very much.

I would now like to turn the call back over to our presenters.

Thank you very much, everybody, for joining. As we've laid out, from an operations standpoint, very strong year. We continue to run well, continue to watch costs and contain where we can.

The Constellation, the Generation business has done a very good job in this marketplace. And we continue to see -- feel very strongly that that will continue to be supported.

The utility side, the utilities are operating well, as I said. We see the investment theses as right. We know the sensitivity to the interest rates, but don't think that's a long-term sustainable issue and we'll continue to keep investing. Thanks.

This is the end of today's call. You may now disconnect.