NRG Energy, Inc. (NRG) Q2 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Second Quarter 2013 NRG Energy, Inc. Earnings Conference Call. My name is Katina, and I'll be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today, Mr. Chad Plotkin, Vice President, Investor Relations. Please proceed.

Thank you, Katina, and good morning, everyone. I'd like to welcome you to NRG's Second Quarter 2013 Earnings Call. This morning's call is being broadcast live over the phone and via webcast, which can be located on our website at www.nrgenergy.com. You can access the call, associated presentation material, as well as a replay of the call in the Investor Relations section of our website. [Operator Instructions] In addition, as this is the earnings call for NRG Energy, any statements made on this call that may pertain to NRG Yield will be provided from NRG's perspective. Before we begin, I urge everyone to review the Safe Harbor statement provided in today's presentation, which explains the risks and uncertainties associated with future events in the forward-looking statements made in today's press release and presentation material. We caution you to consider the important risk factors contained in our press release and other filings with the SEC that could cause actual results to differ materially from those in the forward-looking statements in the press release and this conference call. In addition, please note that the date of this conference call is Friday, August 9, 2013, and any forward-looking statements that we make today are based on assumptions that we believe to be reasonable as of this date. We undertake no obligation to update these statements as a result of future events, except as required by law. During this morning's call, we will refer to both GAAP and non-GAAP financial measures of the company's operating and financial results. For complete information regarding our non-GAAP financial information, the most directly comparable GAAP measures and a quantitative reconciliation of those figures, please refer to today's press release and this presentation. Lastly, please note that both David Crane and Kirk Andrews are on the road today, so please bear with us in case we experience any technical issues during this call. And with that, I'll turn the call over to David Crane, NRG's President and Chief Executive Officer.

Thank you, Chad, and good morning, everyone. Today, I'm joined on this call, as usual, by Mauricio Gutierrez, our Chief Operating Officer; and Kirk Andrews, our Chief Financial Officer, and both of them will be giving part of the presentation. We're also joined in Princeton by Chris Moser who runs our commercial operations; Elizabeth Killinger, who's responsible for our Texas Retail Business; and Jim Steffes, who runs our Northeast Retail Business. And Chris, Elizabeth and Jim will all be available to answer any specific questions that you have about their areas of our business. And so let me get right into this topic at hand and if you're following along with the presentation, this would be on Slide 3. Based on our financial performance through the first 6 months of 2013 and the mild weather and subdued wholesale prices that have gripped Texas in the critical weeks of mid-summer that have ensued since the end of the second quarter, we are compelled today to reduce our financial guidance for full year 2013 adjusted EBITDA by 3% at the bottom end of the range and 4% at the top end of the range. This is, of course, very disappointing to me because it raises a real possibility that for the first time since we started giving guidance as a range several years ago, we may end the year below the range of our original expectations. Before explaining the negative drivers which have gotten us to this point, let me emphasize on behalf of all NRG management that finishing the year within our original guidance range is a streak that none of us want to see broken. And I want to assure that we are doing everything we can prudently do between now and the end of the year to get our financial performance back within the original range. In fact, this is a uniquely unusual earnings call for me. In fact, it's my 39th quarterly earnings call before -- as CEO of NRG. Twice before, in the second quarter of 2005 and the third quarter of 2011, to be specific, we have announced financial results which disappointed me, and in both cases, the poor financial results were driven by mediocre-to-bad operational performance. For this, the second quarter of 2013, the situation is different. While our financial performance has not met expectations, either yours or mine, to be candid, I can't say that, overall, I am displeased with the company's operational performance. Certainly, there have been specific operational disappointments that have contributed to our year-to-date shortfall: the extended forced outage at STP2 this spring, the losses attributed to our commercial optimization activities discussed last quarter, the projected delay in the completion of one of our construction projects. But overall, I'm quite proud of our people's performance across the entirety of the company in the first 6 months of 2013. In terms of what we can control, we have had many more wins so far this year than we have had losses. The main culprit driving 2013 soft year-to-date financial results has been a factor beyond our control, which obviously is the Texas summer weather. The weather, which, until this week at least, had been unusually mild by Texas standards, has impacted our volumetric sales at both our Wholesale and Retail businesses, leading to disappointing overall results year-to-date. Plus the mild weather effectively has eliminated the short-term risk of scarcity pricing, which has in turn led to a decline in the forward curve, which obviously has had a negative impact on our assessment of the earnings power of our Texas fleet over the balance of the year. Just as we finally did get some heat in Texas, in fact, Wednesday was the third-highest load demand day on record in Texas and that's only by a few days in August of 2011. But one day does not a season make and the heat will have to occur on a more consistent basis if we are to see more goals [ph] in the market driving up the prices in the foreign market. I will say this, though: The conditions that we experienced this week, high load and low wholesale prices, explain why we are pleased to have a robust wholesale business in Texas -- I mean, I'm sorry, robust retail business in Texas. Anyway, this is enough from me, at least about the weather. It is what it is and we are doing our best to achieve the best financial performance possible in the current commodity price environment. If there is any silver lining in this situation, it is that in 2014, we will be in a much better position to reap the benefit of our long-term strategic plan to diversify our financial performance away from 100% dependence on cyclical commodity risk into a broader and more resilient set of revenue streams, cost savings and cost savings on operational improvements. The EBITDA and free cash flow synergy benefits arising out of the GenOn transaction will be realized on a full year basis in 2014. The timely completion during 2013 of virtually the entirety of our current construction program, including both the conventional and the large-scale solar projects, means that our new builds will contribute in 2014 on a full year basis as well. The additional marketing and customer acquisition spending in the Retail end of our business in 2013 is resulting in an expanded retail customer base that should benefit us financially in 2014 and beyond. These actions and more, I believe, enhance NRG's competitive positioning and our earnings power going forward. So turning to Slide 4, a slide you have come to be familiar with. I'd like to report on the current status of the GenOn integration, which currently is in full tilt. Of course, you are very focused on the financial impact of the integration, which I have a report on here, and I'm pleased to report in that regard that we have identified and secured another $50 million of annual cost synergies, raising that number from $200 million to $250 million per year. And as with all the cost synergies arising out of the GenOn transaction, it will be achieved and have a full year effect by January 1, 2014. The integration numbers are important. They are gratifying in that they have exceeded all of our expectations financially. But I want to make sure that our focus on them does not obscure the fact that achieving this result represents an enormous amount of hard work very capably done by professionals throughout our organization, including all aspects of our plant operations group, as well as by our IT group, HR, accounting, tax, treasury, supply chain management and other key functional and corporate support teams. It also obscures the fact that our second joint objective for our GenOn integration, beyond achieving cost savings, was to create an operation that was not only bigger but also better in every aspect of our processes, practices and technology. I want to let you know that we were well on our way to achieving this joint objective, and I want to thank Anne Cleary, our Chief Integration Officer, and the hundreds of employees that are focused and continue to do so diligently, executing the integration activities and synergy recognition that we have committed to you. We are on track to finish the integration strong in 2013, so as I've said before, we can recognize the fruits of our labor in 2014 and beyond. Another area of intense focus for our company in 2013 is the completion of our $5 billion construction program; it is reported on Slide 5. As you can readily see from the abundance of green checks and green circles on the slide, we are almost done and the record of an on-time, on-budget completion achieved by our EPC group, led by Ben Trammell, is exemplary. Almost all of our new units, whether fossil or conventional, are now in commercial operation and operating well in the early going. Even our 2 giant solar PV projects, CVSR and Agua Caliente, which are listed here as still in construction, are, for the most part, actually in commercial operation since those 2 plants are divided into blocks that are handed over into commercial operation when they are ready. Indeed, over 265 megawatts of the aggregate 398 megawatts of those 2 units are already fully operational. Our one project that has slid in respect of its completion date is Ivanpah where 2 of the 3 units have slid by roughly 1 quarter into the fourth quarter this year. At this point, all 3 units of Ivanpah are at or very near physically complete and the multistage commissioning process has begun. Together with our partners and our contractors, we are moving through the commissioning process deliberately and thoroughly to ensure that it is done right. We are increasingly confident that this groundbreaking solar thermal project is going to be a big success when it achieves commercial operation in the fourth quarter of 2013. Before I conclude, I want to touch upon the topic of NRG Yield as the importance of NRG Yield and its successful reception by the market is just too important to NRG financially and strategically to be overlooked. As depicted on Slide 6, NRG Yield significantly enhances our strategic competitiveness in 2 of our 3 critical business areas. And within those 2 areas, NRG Yield benefits both our intrinsic green and brownfield development efforts and our ability to grow extrinsically by improving our ability to acquire suitable assets at value. This is a very important development in terms of our growth aspirations for our renewable business because at long last, there are signs that the big strategic players in our industry are awakening from their long slumber and finally recognizing both the opportunity and the risk to them that solar represents. And some of them are trying to get active with their lower cost of capital in acquiring contracted solar assets. NRG Yield goes a long way to reducing or eliminating our cost of capital disadvantage to them, making it possible for us to continue to win projects and opportunities based on our greater nimbleness and understanding of the renewable space and particularly, the solar business. Actually, I'm sure everyone on the call recognizes the importance of NRG Yield to our renewable business, which has always been a business driven by renewable portfolio standards and long-term offtake agreements with load-serving entities. What is a little bit less obvious is the importance of NRG Yield to our growth aspirations for our conventional generation business. In the low gas price environment that exists, it's nearly impossible to justify the construction of new capacity on a merchant basis. As the governors of various states consider how they're going to replace the wave of generation capacity that will be retired over the next few years as a result of either economic stress or environmental obsolescence, they are increasingly reaching the conclusion that they need to offer some sort of state-sponsored long-term offtake agreement even for conventional new builds. NRG has the best brownfield sites and the best locations on the grid with the technical expertise and commercial savvy to get these projects filled. But what we lack before NRG Yield was a competitive cost of capital for assets that do not bear commodity price risk. And now we have that. So in summary. If you consider the message contained within my previous 3 slides: the successful integration of GenOn that has outstripped everyone's financials expectations in terms of synergy factor; a massive construction program that has been close to perfectly executed and is now almost completed; and an effective execution of NRG Yield vehicle IPO that has effectively addressed or at least mitigated both our cost of capital issue and our tax benefit optimization issue in respect of our renewable progress. On the progress that's been made by my colleagues at NRG on all of these 3 fronts in the second quarter of 2013, hopefully, you can understand how my disappointment in our financial performance year-to-date has been tempered by my gratitude to my colleagues for advancing the longer-term interest of our company on the 3 integration, construction and optimization initiatives described above. Let me conclude, actually, on a personal note. As I alluded to earlier, I'm now approaching the 10th anniversary of my tenure at NRG, which is not particularly significant to any of you other than it means that the initial sign-on grant of NRG stock options that I received in 2003 expire this year. As such, I want to alert you that over the next few months, in the rare instance when we are not in a closed period for trading purposes, I plan to take steps to convert a modest portion of my overall holdings in NRG stock to other investments, which only will be the second time I have taken such an action in my 10 years at NRG. Even after that partial divestment, I will hold NRG stock well in excess of 10x my paid salary, which exceeds the 6x requirement imposed by the NRG Board of Directors, and I will continue to hold an amount far in excess of the required amount for the full extent of my duration in NRG. I tell you this now for 2 reasons: first, to assure you that there are no surprises with respect to my personal investment decision-making that might raise questions in your mind about my commitment to the success of NRG; and two, to reassure you that in no way does my partial sell-down indicate a pessimistic point of view on my part about the prospects for NRG stock price appreciation. Notwithstanding the challenges of the present commodity environment, I remain very bullish on NRG's prospects to flourish over the short to medium term. Given the relative strength of NRG's financial performance, even now, 4 full years into the commodity price downcycle, I can only imagine how strong we will be when the cycle turns around as it inevitably will do. And when it does, I expect to be there to benefit from it as a major individual shareholder in NRG. So now, I'd like to turn it over to Mauricio.

Thank you, David, and good morning. During the second quarter, our primary focus was on several key areas: optimizing the overall spend of our fleet as part of the operational synergies effort, continuing to integrate the GenOn assets and getting the portfolio ready for summer operations. Importantly, we executed our spring outage plan to ensure reliable summer operations and our key operational performance metrics improved relative to last year for the combined organization. Our safety numbers are well within top quartile performance but they are not at the level we expect. We implemented a number of corrective actions during the quarter and are encouraged by the changes we have seen over the last 2 months. As David already mentioned, Texas has disappointed so far this summer, both in terms of weather and prices, affecting our integrated business in Texas. Given this market dynamic, we're in the midst of implementing changes across the Retail organization, such as reducing operating costs and expanding our product offerings. These actions are intended to improve financial performance without compromising the long-term value of our franchise. On the quality side, I would like to point out that our financial performance benefited this quarter by improved regional diversification that we have as a result of the GenOn combination. Finally, we continue to make significant progress with our projects under construction. We brought Marsh Landing and the Dover gas conversion projects online in May, the Parish Peaker in June and the El Segundo Energy Center on August 1. This is a great achievement, and I want to join David in recognizing the entire engineering, procurement and construction organization for delivering these 4 projects on time. We continue to focus on the breadth of our utility scale solar projects with a particular emphasis in Ivanpah where full commissioning is under way. There have been some delays in 2 of the 3 units. However, we expect to reach commercial operation by the fourth quarter. Now moving on to our operational metrics on Slide 9, and starting with safety. 99 out of 118 facilities finished the quarter without a single recordable injury. These numbers are solid, but given the increase in recordables we're seeing from last year, we have implemented a number of initiatives, particular in the retail and service groups, where some of our employees are not accustomed to the rigorous safety culture typical in industrial environments. As you can see, our total generation was higher by 2.5% for the quarter, driven primarily by a reversal in coal-to-gas switching and improved coal availability. Coal and nuclear generation were up 20% for the quarter with gas down 35%. Looking around the country. On a regional basis, Texas and South Central were slightly lower, driven by lower gas generation. Northeast and California were slightly higher, given higher load and power prices. Our availability and reliability metrics are up from last year for the combined portfolio. Parish led the quarter with over 90% availability and we successfully executed our spring outage plan with 127 planned outages and more than 2,800 outage days for the year. Identifying additional operational synergies continues to be a priority. With 80 plants and more than 350 units, this provides an opportunity to reduce and optimize maintenance dollars spent on our portfolio. This will continue to be a priority for the operations group as we identify additional synergies. Moving on to Slide 10. Our Retail business performed within our revised expectations for the second quarter where we delivered $140 million in adjusted EBITDA. As we discussed on the June 24 investor call, the combination of milder weather, higher supply costs and the discipline we're taking in our commercial and industrial business largely led to the year-over-year reduction in financial performance. However, as I mentioned earlier, we continue to invest and manage the business in order to optimize near-term earnings while protecting long-term value. To that end, we increased customer count for the 10th consecutive quarter, now up 44,000 customers for the year. This demonstrates the continued momentum we have built in attracting and retaining customers. And while we continue to invest in new markets, new products and new sales channels to drive growing customer count, we are applying the same discipline underpinning the operational synergies across the Wholesale business. As a result, we are recalibrating our Retail cost structure to respond to changing market dynamics. Year-to-date results indicate that our operations and maintenance cost per customer is down 4% year-over-year. Now on a regional basis, we continue to organically grow customer count in Texas as a result of effective execution and expansion of innovative products and services. We have seen retention rates improve by 10% to 20% for customers enrolled in these products. However, total volumes were down close to 7% for the quarter. They were driven by weather and discipline on pricing and margins in the commercial and industrial segments. In the Northeast, while margins have been under pressure, we were able to increase our total revenues, grow customer counts and nearly double retail volume sold across the region. Earnings for the quarter were disappointing relative to last year, but we are absolutely committed to executing for the long term and are pleased to remain the largest retailer in Texas and are excited about our growing Northeast presence. Turning to our market update on Slide 11. Summer weather has not materialized as we expected, particularly in Texas where cooling degree days are down 12% through July compared to last year. As you know, we have maintained a more open gas portfolio to benefit from scarcity pricing given the tighter fundamentals compared to last year. Mild weather and higher wind generation depressed heat rates during the quarter and these trends have extended to the summer months where we saw a complete collapse in prices at the end of June. On the upper left-hand chart, we have provided the peak price pricing history for the summer months. And as you can see, August is down more than 50%, erasing any embedded scarcity premium. This short-term dynamic has put some pressure on the forward markets beyond 2013 and has increased the gap between the market and the required margins to justify any generation. We are convinced of the strong fundamentals in Texas, but this short-term dynamic may create a lack of urgency for the additional market reforms necessary to ensure the adequate level of resources needed to meet our cost reliability target. Even though Texas has been disappointing to us, the regional diversification we have now after the GenOn transaction has proven to be very beneficial. Outside of ERCOT and particularly in the Northeast and California, prices were robust in the second quarter driven by higher gas prices, unit retirements and higher load. More recently, in July, we experienced a heat wave across the Northeast. New York actually set a new all-time record peak load in July 9 -- 19. We saw scarcity prices across all 3 Northeast pools reflecting some of the price formation changes implemented this summer. In particular, I want to call out the positive changes in New York, where emergency demand response was setting prices during intervals of resource shortages and sending the correct pricing off to the market. In PJM, we saw a similar situation in the active [ph] zone where demand response set prices close to $1,800 per megawatt for a couple of hours. We are encouraged by these changes and we will continue to work with all 3 pools to ensure the competitive pricing now continue to improve. I want to make sure to recognize the efforts of the entire integration team. Through their ongoing efforts, they have integrated over 14 gigawatts across all 3 Northeast pools to our commercial and risk management systems. I am very pleased to say that all systems, both the operations and commercial groups, worked flawlessly during this heat wave. Our hedge positions are presented on Slide 12. We continue to layer in additional hedges in 2014 and 2015 against our coal and nuclear assets. We are significantly hedged for the balance of the year and are now close to 75% hedged on power and slightly higher on coal for 2014. We're constantly evaluating the benefits of being opportunistic and hedging in the wholesale market or [indiscernible] megawatts with our retail companies. Different than other merchant generators that rely purely on wholesome markets, we believe these options will become more valuable over time as financial players leave the space given more stringent financial reforms. Finally, in California, our origination team successfully extended the contract with PG&E for all 3 units at Pittsburg facility for 1 more year. Consistent with our hedging philosophy over the past 2 years, we made a conscious decision to leave a significant part of our Texas gas portfolio open for the summer months. This was driven by our fundamental view given the regulatory changes, the new price cuts and the tighter reserve margins as I discussed in our first quarter call. In our view, summer prices in Texas have not reflected the potential upside embedded in the market. The key takeaway is that we will continue to position our portfolio to be consistent with our fundamental view while taking into consideration operational risk and the potential upside expected in our different markets. With that, I will turn it over to Kirk for the financial review.

Thanks, Mauricio. For the financial summary on Slide 14. NRG is reporting second quarter 2013 adjusted EBITDA of $594 million with $393 million from Wholesale, $140 million from Retail and $61 million from our new operating segment, NRG Yield. Through the first half of the year, adjusted EBITDA totaled $967 million with $629 million from Wholesale, $243 million from Retail and $95 million from NRG Yield. Turning to the quarter's highlights. With the successful closing of the IPO behind us and based on yesterday's closing price, NRG Yield now trades at an implied multiple of 12.8x 2014 adjusted EBITDA, providing a market-based measure of the value of our growing contracted renewable, conventional and thermal portfolios. In addition, as a result of the IPO, NRG received net proceeds of approximately $462 million, enhancing liquidity and increasing capital available for allocation. On the financing front, NRG took advantage of favorable market conditions with a well-timed pre-pricing and upsizing of our Term Loan B through which we not only reduced the spread on the loan from 2.5% to 2%, but raised new capital at this reduced rate by increasing the loan amount by $450 million. During the quarter, we also reduced the costs of our revolving credit facility by 50 basis points, extended its maturity by 2 years to 2018 and further enhanced NRG's liquidity by upsizing the facility by $200 million to $2.5 billion. These transactions helped drive balance sheet efficiencies to $142 million annually, which significantly exceeds our original target. Just this week, on August 7, we successfully closed the acquisition of the 390-megawatt Gregory cogeneration plant for $244 million and used approximately $120 million of the proceeds from the upsized term loan I just mentioned to partially fund the transaction. In addition, closed on 3 solar projects, totaling 66 megawatts, High Desert and Kansas South, both of which, which are currently operating, and an advanced development project on the island of Guam. Turning to 2013 capital allocation. In addition to expanding capital through the NRG Yield IPO, during the second quarter, NRG also exceeded its previously announced $1 billion deleveraging plan by retiring $575 million of GenOn senior notes using excess GenOn cash on hand. When we take into account the $330 million balance of the Term Loan B upsize, which served to increase cash at the NRG level, this transaction resulted in a $245 million reduction in overall debt, allowing us to significantly exceed our original $1 billion delevering target. And finally, the trading restrictions resulting from the ongoing NRG Yield IPO process significantly limited opportunities for share repurchases during the quarter. And we intend to complete the remaining $175 million of our share repurchase program by the end of 2013. Turning to the guidance overview on Slide 15. Based on year-to-date results and declines in forward prices over the balance of the year, we are both revising downward and narrowing the ranges of our adjusted EBITDA and free cash flow before growth investments guidance for 2013. This reduction primarily arises out of the volumetric sales shortfall caused by the unseasonably mild summer weather in Texas, as well as a contraction in forward prices over the balance of the year. Our revised guidance for 2013 adjusted EBITDA of $2.55 billion to $2.7 billion, reflects a $65 million reduction versus previous guidance and a $50 million narrowing of the range. We are also narrowing our guidance for 2013 free cash flow before growth by reducing the upper end of the previous range by $50 million and maintaining the lower end due to a reduction in maintenance CapEx and assuming collateral posted is either returned, replaced by LCs or covered by our $900 million liquidity reserve. 2014, which benefits from increased EBITDA contributions from our contracted assets, as well as an increase in expected cost synergies, we are reaffirming our guidance ranges for both adjusted EBITDA and free cash flow before growth. Specifically, our adjusted EBITDA guidance ranges remain at $2.85 billion to $3.05 billion and our free cash flow before growth ranges remain at $1.1 billion to $1.3 billion. Finally, with the successful completion of the NRG Yield IPO, we are modifying the components of our adjusted EBITDA guidance ranges, which will now include Wholesale, Retail and NRG Yield. NRG Yield adjusted EBITDA guidance includes the 7 utility scale solar facilities and 2 distributed solar portfolios previously part of solar guidance, as well as the expected adjusted EBITDA from our South Trent wind facility, thermal and our GenConn and Marsh Landing assets, all of which, which were previously part of Wholesale guidance. Expected adjusted EBITDA contribution from the remaining utility-scale solar projects, which were also part of our previous solar guidance and now comprised of 5 solar assets covered in the right-of-first offer agreement with NRG Yield, is now part of Wholesale EBITDA guidance. Turning to Slide 16. With the NRG Yield IPO now completed, we have put in place the critical final step in enabling a clearer understanding of the distinct components of NRG's value, our wholesale retail business and our contracted and growing generation platform now optimized through the creation of NRG Yield. While there are a number of valuation methodologies and metrics used by the financial community in assessing NRG's value, in order to summarize the impact of NRG Yield, we have demonstrated this in the context of an EBITDA multiple. On the left slide of Slide 16, starting with the current NRG market capitalization of approximately $8.7 billion based on yesterday's closing price and deducting the market value of NRG's 65.5% stake in NRG Yield, the implied residual NRG equity market value is $7.5 billion. Next, we add NRG's preferred stock and proportional debt balance and subtract NRG Yield debt. Finally, by subtracting our June 30 pro forma cash balance, we can derive the implied market residual enterprise value for NRG, net of NRG Yield. At the bottom of the page, we've expressed this residual enterprise value as a multiple of residual adjusted EBITDA based on the midpoint of our 2014 guidance range. The market 2014 residual adjusted EBITDA multiple is approximately 7.7x. On the right side of this slide, we provided the calculation of the 2014 residual adjusted EBITDA range by deducting the guidance for NRG Yield, as well as deducting the portion of consolidated EBITDA associated with other noncontrolling interests. Consistent with the enhanced disclosures for adjusted EBITDA and debt we initiated at the beginning of the year, we will continue to provide the details in deriving proportional EBITDA and debt in the appendix to our quarterly disclosures. Finally, as some of you may have already observed, as the residual adjusted EBITDA numbers still contain the contribution of the ROFO Assets, the implied multiple on the left-hand side is reflective of an interim step. So we've also provided, for your reference, the adjusted EBITDA contribution from these ROFO assets in 2014. Importantly, this not only underscores the adjusted EBITDA from these assets as nearly equivalent to the current NRG Yield adjusted EBITDA but it valued at the same multiple for NRG Yield. This further clarifies the implied trading multiple of our competitive businesses, which, based on this approach, currently trade at an implied 2014 adjusted EBITDA multiple of just over 7x. Turning briefly to corporate liquidity on Slide 17. NRG's liquidity adjusted for the recent NRG Yield IPO proceeds and the cash paid for the acquisition of the Gregory cogeneration plant since the quarter end remains strong with a balance of approximately $3 billion. The right side of the slide provides year-to-date sources and uses, which comprised this change in liquidity since year end and include the benefit of our now expanded revolver. Turning to Slide 18. I'd like to review NRG's common dividend in the context of the NRG Yield IPO. As you may recall, NRG's growing portfolio of contracted assets forms the foundation supporting our common stock dividend. As a result of the NRG Yield IPO, about half of our contracted assets are now held by NRG Yield and about half -- or excuse me, and about 35% of the cash distributions from those assets now support the NRG Yield dividend to the public shareholders, which, in the aggregate, totals approximately $27 million at the current rate. NRG retains a 65.5% stake in the contracted cash flows from the NRG Yield assets, which, when combined with the growing distributions from the remaining contracted ROFO Assets, continues to provide a solid basis of support for the NRG dividend. Finally, turning to Slide 19. I'd like to provide a brief update on our year-to-date capital allocation progress, which, during the second quarter, represents a balance between continuing value-enhancing investment and expanding our overall base of capital for allocation. During the second quarter, we acquired additional contracted solar assets that were included in the right-of-first offer agreement for NRG Yield, as well as exceeded our delevering goals by redeeming the GenOn 2014 notes. In addition, we closed on the acquisition of Gregory, which, as I mentioned, we included in our prior capital allocation update. However, by utilizing the $120 million of the proceeds from the low-cost expansion of our Term Loan B, we reduced the capital allocation requirement for this acquisition from $244 million to $124 million. The $462 million in net proceeds from NRG Yield IPO, combined with the increased free cash flow guidance we announced in late June as a part of the asset optimization update, served to expand the overall base of capital for allocation. As a result, excess cash for capital allocation now stands between $1.03 billion and $1.18 billion for 2013. As $130 million of this consolidated excess cash now resides at the NRG Yield level, we've broken it out separately on the chart, leading to approximately $1 billion in excess cash through year end at the NRG level. We continue to actively evaluate opportunities for accretive capital allocation across all categories as the remainder of the year unfolds, including the possibility of enhanced or different allocations should conditions evolve. We will provide an update on our progress, including progress on the deployment of the remaining $175 million in share repurchases on our next quarterly call. And I'll turn it back to David for his closing remarks.

Well, thank you, Kirk. And operator, Katrina, I think we should turn straight to questions. I think we have about 15 minutes for questions. So we're happy to answer any questions that anyone has.

[Operator Instructions] Your first question comes from the line of Jon Cohen representing ISI.

A couple of quick questions. I'm going to let somebody else ask about capital allocation. But on NRG Yield, how are you thinking about the pace of drop downs from NRG into NRG Yield and will that be done sort of with an eye toward managing toward that 10% to 15% distribution growth or some other metric? And the second question is, how will those be valued? Is it going to be on some premium to book value or some discount to where NRG Yield is trading?

Well, Jon, I think from NRG parent perspective, we want to do it in sort of a measured pace based on the assets that are part of the ROFO perspective, in the set of ROFO Assets. I think the main thing that could sort of change, I mean, we talked about maintaining a 10% to 15% growth rate over like a 5-year period, which was something that we thought we could do with the assets that are in the ROFO set. It's the amount of assets that we can see that we either develop intrinsically. We have high hopes for a lot of our brownfield development projects, as I talked about in my comments, or if we were to get appropriate assets through acquisition, then I think we would accelerate the pace or try and make the drop downs, when they occur, bigger. But it's very early days yet, so I would say that nothing has really changed from that relative to when we're on the road a few weeks ago on behalf of NRG Yield. In terms of the valuation, I mean, speaking from NRG's perspective, obviously, we would like to sell the assets to NRG Yield at a price that maximizes value to NRG. But NRG Yield and its independent directors, I think they will probably want to follow the normal approach of getting independent valuations and making sure that they are acquiring assets that are not only appropriate but assets that they can acquire in terms of returns that safely exceed their weighted average cost of capital. The NRG Yield Board of Directors has had one meeting and an organizational meeting. So I think there's a fair amount of work that needs to be done there to settle exactly. I'm not sure that even if this were an NRG Yield call, which it is not, I'm not sure I would be able to be much more specific than to say something like that at this point. Kirk, is there anything that you want to add on behalf of NRG?

No. I think you've covered it, David. Certainly, the point to underscore is that the ROFO Assets, in particular, now that we've provided you some additional detail, Jon, around those, give us a lot of confidence in terms of the tangible pipeline to drive that growth rate that you mentioned. And looking at the other opportunities David had mentioned, that more than anything will drive the pace in terms of delivering all that. And from a valuation standpoint, I think that's also a function, of course, of the independent directors, I think, as David may have mentioned. And I would expect on larger drop downs, that would also be informed the degree to which the independent directors of NRG Yield determine to access a third-party adviser on the value of those assets.

Okay, great. And one follow-up for you, Kirk. On your Page 16 analysis here, if you were to take the -- where you show NYLD proportional debt, if you were to take that number, including all of the current ROFO Assets -- I realize you're on the road, so you might not have it, but how much would that go up and the NRG debt go down?

Yes. And you're correct, I can't give you that number in detail off the top of my head and don't have it directly in front of me. But the order of magnitude of those particular assets from a leverage perspective should be directionally towards that leverage, if not a little higher than that, just given the preponderance of those particular assets or -- are more along the lines of the DOE loan guarantee, which tend to be a little bit larger in terms of the leverage capacity.

Okay, great. And that cash, just as of June 30, does not include cash flow for the rest of the year or for '14, correct?

No, that's correct. That's as of June 30. But importantly, if you'll notice included, because we're accounting for NRG Yield on a pro forma basis, which obviously didn't close as of June 30, but on this page, looking to depict that, that cash balance is both pro forma for the Gregory acquisition, as well as pro forma for the cash from NRG Yield.

Your next question comes from the line of Keith Stanley, representing Deutsche Bank.

Can you comment just a little more on ERCOT pricing this summer to date and what you see as driving that, looking, particularly, at this week, for example, when peak demand was actually very high but the price stayed fairly low? And then how does this make you think about hedging heat rates differently, if at all, for the outer years just given the experience of the past 2 years where we see a pretty big drop in the summer period?

Well, Keith, let me take a first cut at that, then I'm going to turn it to Mauricio or Chris particularly to answer the hedging question or to not answer the question, as they see fit. I mean, I think what we saw this week is really a combination of 3 things because the level of -- you're right, the level of demand we saw on Wednesday, when we reached that level of demand back in 2011, there was scarcity pricing. And when you -- and so why did it not happen this week? I would say 3 things: number one is that a lot of times when it's very, very hot, the wind situation is at a dead calm. But in this situation, there was ample wind generation this week in Texas. So whether that's a new weather phenomenon or not, I don't know. Maybe Mauricio has a point of view. But that's one of the reasons, that the wind was there. I think the second thing is that, typically, what happens, what happened to us and what happened to the market in August of 2011 is sustained periods of peak, not only does it build up demand on the demand side, but some of the power plants that are used to only operating a few days out of a year, they wear down and they break. And so you have more outages than you normally do. That clearly hurt us and hurt the market in the second half of August in 2011, but the supply side was fully there this year because it had not been tested so far this summer. And then the third thing is just the psychological element. And again, Mauricio and Chris know this better than I, but there's just no fear in the market of running out of supply because things have been so calm so far. So Mauricio or Chris, do you want to add anything to that in terms of this week's subdued prices and then also talk or say whatever you're willing to say about hedging philosophy?

Thanks, David. This is Chris. Keith, when we're looking back at the Wednesday number, which was around a 67.2 peak or so. There was almost 3,700 megawatts on average of wind, and that's pretty far in excess of the expected load-carrying capability of the wind even under the new construct that they're talking about moving to -- moving it from a 8.7 to the 14 and the 32. So there was clearly, as David pointed out, a lot more wind going on out there as well. To his point as well, the gen stack was very healthy across the fleet, ours and everyone else's looked like it, too. So extra wind, fairly -- very healthy generation. And then the load at 67.2 is a pretty good load, but it's not near what we saw in 2011 or even -- keep in mind, the forecast when the CERA came out for the summer was for 68.4, so you're 1,200 megawatts short of where they thought the load was going to be as well. And obviously, as guys very interested from both the wholesale and retail side on what the load is doing, we're digging into a lot of the moving pieces on the load side. I don't have a lot of answers yet on that piece. But I think wind, I think a very healthy gen stack and I think the fact that, frankly, it just wasn't as hot as 2011. I mean, the numbers I have, give or take, for the 7th was a Dallas high of 105 and a Houston high of 100. I mean, the numbers we were seeing in '11 were 109s and 110s and 104s and 103s in Houston, and so it's just a step-change difference in terms of the temperatures.

And Keith, I guess, just a word on the hedging strategy. I mean, I want to just make sure and point out that for the summer, we were significantly hedged, our coal portfolio. And we have told you over the past couple of quarters that we will have a long biased position around our gas portfolio, given the tight fundamentals that we see in the market. Then certainly, I laid out the value proposition for this summer, given the regulatory changes that we have seen and the tighter reserve margins that we were expecting, which hasn't played out yet. Going forward, we're going to continue to maintain the same discipline on hedging the gas portfolio. Keep in mind that we want to have a -- we will be consistent with our fundamental view, and we will continue to have a long biased position so long we believe that the Texas have strong fundamentals, which we believe they do.

That's very helpful. If I could just do one very quick follow-up. Just on the quarter, what was the driver of the $19 million in positive EBITDA, the corporate segment? I think that's usually a negative number. And the big working capital in collateral deposit drags year-to-date on cash flow, should we expect that to reverse over the balance of the year?

Keith, it's Kirk. To address that question, on the collateral side, some portion of the collateral that's posted, yes, is for positions that we expect to roll off over the balance of the year. But with the volatility and the movements that we see in the commodities markets, obviously, the additional collateral posting is obviously increasingly difficult to predict. But we expect a good portion of that to come back and another portion of that to be supportable through the posting of LCs, if deemed necessary. And that's also part of the reason why we have the $900 million liquidity reserve.

And as to the corporate side?

As to the change in the corporate side, I actually don't have that particular number in front of me at present, but I think we can follow up with you on that one offline.

Your next question comes from the line of Angie Storozynski, representing Macquarie.

Given what's happening with prices in Texas and we saw a memo today filed by one of the commissioner, Commissioner Nelson, do you feel like a capacity market in Texas is now more likely, given how disappointing prices have been even though we have had an increase in price caps? And Commissioner Nelson is clearly suggesting that a second look needs to be taken at a capacity market. What's your view?

Well, Angie, I mean, it's hard for us to obviously determine any sort of critical regulatory process and how influenced they are by -- in terms of market design by short-term movements. I would say, for the most part, I wouldn't say that sort of a weather-driven situation in Texas is going to change the fundamental attitudes for or against. I would say the most important thing is as the forward price in Texas moves away from replacement price, the chance that a bunch of people start to build power plants without a change in the market design becomes more remote. And so I think, for the people charged with maintaining the stability of the system and keeping the lights on, I think it may incrementally increase their desire to make a change. But it's a pretty indirect connection. Mauricio, I don't know if you have a different point of view about it than that.

No. I mean, I guess, just to complement or to add, the memo filed by Chairman Nelson, I think, they're looking at this the right way, which is, first, evaluate whether they need a mandated reserve margin; second, looking at what is the mechanism to achieve that target reserve margin. And what is the most effective mechanism of doing that? I think there's been multiple parties that have been pro a capacity market to be the more cost-effective way of doing that. I will tell you, Angie, that I think a lot of that and the probability whether or not capacity is more likely will be determined once the next commissioner gets appointed. And given that Texas legislative has ended their session, we expect somebody to be named within the next couple of weeks. So I think that will resume the talks around the resource adequacy for Texas on the long term.

Okay. And completely separately, you mentioned that a delay in operations of one of the assets has had an effect on your annual guidance. Are we talking Ivanpah or El Segundo?

No, we're talking Ivanpah.

Your next question comes from the line of Stephen Byrd, representing Morgan Stanley.

David, I wanted to go back to your opening comments on NRG Yield. And you mentioned, in a low gas price environment, that long-term contracted assets are the key to replacement capacity. Can you talk a little bit further about that in terms of -- in the competitive markets that you're in, do you see further trends towards long-term contracted assets? Or could you just sort of expand on that point a bit further?

Well, I mean, what I would say about that, Stephen, is if we look around our system, clearly, the trend started a few years ago. The GenConn assets that we have in Connecticut were driven by a process, El Segundo, Marsh Landing in California. But if you look around our system in California and New York State and Connecticut and Maryland, they're either served RFPs either by state entities or sponsored by the state for 10 years plus. And a lot of it is sort of specifically targeted at replacement capacity. And to be frank, from my point of view, our company's point of view is we don't really see conventional generation being a growth business in response to sort of tepid demand growth in a post-industrial society. It's all about replacement power. And so each situation is different. So California needs to replace San Onofre. New York, depending on what they decide about Indian Point, may need to replace that power. And in each of these cases, we have great sites basically in the load pockets where they're looking for new capacity. And so we hope to respond to those RFPs with our own brownfield developments. And I think the way we would price those would be that typically, we're going to price NRG's cost of capital sort of over the entire life of the asset but certainly through the construction period, which is relatively the higher-risk portion of it. But now that we have at least a sense from NRG's perspective what NRG Yield's cost of capital should be, it may cause us to sharpen a pencil a little bit on what we expect the cost of capital to be during the period of the PPA. Does that answer your question?

That does. That's very helpful. And then I just wanted to talk broadly about kind of a related point on capital allocation. You'll have quite a bit of excess cash, and we're seeing headwinds in a lot of these competitive markets. As you look at the growth prospects out there relative to your own stock, can you just comment on a broad level sort of the relative attractiveness of those 2 options?

I'm not sure I'm following what your 2 options are. Do you want to rephrase that? Or else you're going to get some sort of meandering answer from me about both the acquisition environment and capital allocation. And probably on Friday in August, you have better things to do than listen to me go on for 10 minutes. So [indiscernible] do you want me to comment on?

Yes, maybe just a little more point on it. Given that it looks pretty challenging in the competitive markets, it would seem to make M&A maybe a little less attractive relative to your own currency, which you laid out in terms of valuation metrics. As you look at buying assets in the market versus your own stock in this kind of sort of more challenging commodity environment that we're in, does that sort of point you more towards your own stock than it would have maybe 6 months or a year ago?

Well, okay, I think I got the question now. What I would say, starting on the capital allocation front and then segueing effortlessly and smoothly into an M&A discussion is, the approach we've taken in the past, certainly our firepower has been enhanced by the proceeds we got from NRG Yield. But the fundamental approach we have, prudent balance sheet management, sort of -- we've always been fortunate enough to have enough cash flow to apply to debt reduction. We've done share buybacks, but we've also had enough money to take advantage of opportunities in the M&A world. And I think that, that balanced approach is going to continue. In terms of returning capital to shareholders, our immediate goal, as Kirk laid out for everyone, was we've got to finish our 2013 program. To us, it's really pointless to sort of think about doing anything beyond that until we finish what we undertook to do earlier in the year. So that's really what our eyes are set on in terms of from now through the end of the year. Beyond that, we'll look at the circumstances, discuss it with our board and maybe have more to say on the November call. On the M&A front, what I would tell you is, you've mentioned the challenging M&A environment that's in our merchant space. But as we saw with the GenOn transaction, to me, there's more opportunity the more challenging it is. As I like to say, Stephen, I'm sure you've heard me say this in many occasions before, it's when there's no hope that there's the best opportunity to make acquisitions at a price that makes sense. So we hope to see opportunity even on the merchant space precisely because it is a challenging environment to make money. And we've shown that one way you can make money with those type of assets is through consolidation. But also, it used to be that if there was a contracted asset out there, we wouldn't even really bother to take a look at it because we knew we weren't going to be able to compete with the Canadians or someone else with those assets. And now, again, because NRG has the sense of what NRG Yield's cost of capital should be, I think we can be more competitive on that front as well. But my final point, Stephen, is we're not specifically setting aside money at the NRG level, because while now we're going to go out there and set the world afire with 20 acquisitions in the next 2 months because you never know. I mean, it takes a willing seller willing to accept a reasonable price. And often what we've found in my 20 years in this industry is that there are willing sellers, but they don't have a reasonable point of view about what the price should be.

Your final question will come from the line of Neil Mehta, representing Goldman Sachs.

I appreciate the sensitivity about this, but can you talk about retail margins? One of the trends we've seen year-to-date is those margins have come in a bit. Is this an ongoing trend in your view? Or have we reached a point of stability in terms of the margins?

Neil, you want that in both -- I mean, are you more focused on Texas, Northeast or you want sort of a -- well, Elizabeth, why don't you -- I mean, I'm sure you're asking about Texas, so why don't you start with an answer on Texas and then, Jim, if you want to add any comment on the Northeast, go ahead.

That would be great.

Sure, thanks. Neil, so margins in retail, as you can tell from the slide Mauricio walked through, they did drop about $3, and that's really largely due to the higher supply and hedging costs, some of the weather variability. It was expected to be much warmer, and then it came in cooler. And then some competition in C&I, as well as some customer mix between both customer segments and markets. In Texas, we saw a little over $1 reduction in unit margins. And we're actively managing the balance between margin and customer count. I would say we're in the stability range, but I'll turn it over to Jim to also speak to the Northeast.

Thanks, Elizabeth. I think the same story is true for the Northeast, as Elizabeth highlighted, a little bit emphasis, different emphasis across the different elements. But generally speaking, competition remains very intense in the C&I space. We do believe there's again pressure because costs have increased. But we're seeing sort of a stabilizing in those key numbers.

Got it. And last question for me. Another dynamic we've seen is basis in PJM is compressed here and even inverted relative to Henry Hub. What does that mean for your PJM fleet and how do you think about managing that risk?

Mauricio, do you want to answer that? And I think, Mauricio, when you're done, I think we'll just call it a day at that point.

Yes. Neil, so I guess, a couple of things. One, and I alluded to that on my script, there's been a reversal of coal-to-gas switching. And if you look at the gas pricing scenario last year versus this year, there is almost $1.52 to $2 higher. So that basically put our coal facilities in the money. Prices certainly have come down and basis have contracted across the PJM pool, but we still see premiums on the Eastern side where we have most of our baseload portfolio. With respect to the gas, the gas basis and the potential dynamics to that, we certainly don't expect gas prices to fall back to spring of 2012 levels, but we are seeing a significant bottle of -- I guess, bottled gas around the Marcellus shale. We presented the economics for new builds. We looked at the sensitivity of gas, which I think we tried to capture the potential dynamic. And even with that, we see a significant gap between the current market and the new-build economics needed, not now, but in 3, 4 years down the road, given our capacity options. So what I would say is, we don't expect kind of a go back to the coal-to-gas switching situation that we saw last year, even with the drop in gas prices around the Marcellus Shale.

Okay. We appreciate everyone looking -- joining us on this call, and we look forward to talking to you at or before our next quarterly call. Thank you, operator.

Thank you, sir. Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.