PPL Corporation (PPL) Q4 2010 Earnings Report, Transcript and Summary

Good morning. My name is Christie, and I will be your conference Operator today. At this time, I would like to welcome everyone to the PPL Corporation Fourth Quarter Conference Call. [Operator instructions] I will now turn the conference over to Joe Bergstein, Director of Investor Relations.

Good morning. Thank you for joining the PPL conference call on fourth quarter results and our general business outlook. We are providing slides of this presentation on our website at www.pplweb.com. Any statements made in this presentation about future operating results or other future events are forward-looking statements under the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from such forward-looking statements. A discussion of the factors that could cause actual results or events to vary is contained in the appendix to this presentation and in the company’s SEC filings. At this time, I'd like to turn the call over to Jim Miller, PPL Chairman, President and CEO.

Thanks, Joe, and good morning, everyone on the call. We've got a lot to cover today, so we'll jump right into it. Today, we plan to discuss our 2010 results and our 2011 earnings forecast as well as provide you a more in-depth discussion of the strength of our platform that we feel is well-positioned, I should say, to grow shareowner value over the next few years. Obviously, the past few years have been very challenging for our sector, especially those with significant competitive generation. At PPL, we've used this period as an opportunity to strengthen our business mix and focus capital on the rate-regulated sector of our industry. As a result, we've reduced our earnings risk profile and retained the upside inherent to our Supply business when wholesale electricity markets recover from our current down cycle. We already see proof that the steps we've taken over the past few years have significantly strengthened our company while improving our flexibility to thrive in a variety of market scenarios. This morning, we'll provide you with our normal year-end update and also discuss our 2011 earnings forecast. Bill Spence, our Chief Operating Officer, will provide you with a detailed operational overview; and Paul Farr, our Chief Financial Officer, will review the financial details with you. And of course, we'll leave time for your questions at the end. Before launching into the discussion, however, I'd like to talk briefly about some recent M&A trade press rumors mentioning PPL. You're all aware it's our long-standing and appropriate policy not to discuss market rumors or speculation, and we won't deviate from that today. As we've said many times before, the company continuously explores opportunities to enhance value whether it be acquisitions, divestitures, improved operations of our existing businesses. There's something to discuss in regards to one of those potential opportunities, we do it when the time is appropriate. So until that time comes, we'll not respond to questions on that matter today. Now let's move on to the earnings announcement we've made this morning. Driven by a strong fourth quarter, we ended the year with reported earnings of $2.17 per share and ongoing earnings of $3.13 per share. These results are higher than our most recent forecast range, even excluding the $0.12 share contribution from the Kentucky operations, which were not included in our prior forecast. Considering the continued headwinds of very low wholesale electricity prices driven by low natural gas prices, we're very pleased with our 2010 results. Fully factoring in dilution from the E.ON U.S. acquisition, our 2010 earnings from ongoing operations are 60% higher than our 2009 results. While the combination of our very beneficial hedging profile and depressed energy and capacity prices results in a lower earnings-per-share forecast for 2011 than we achieved in 2010, we expect strong growth in our utility segments in the future. This earnings growth is based on immediate infrastructure improvements in these companies, which will result in significant rate base growth over the next several years. We expect compound annual growth rate or rate base growth of our combined regulated businesses to be approximately 9.5% from 2011 to 2015. We're confident in our ability to earn reasonable returns on this rate base because these utilities are best-in-class performers, and they operate in jurisdictions with highly constructive regulatory frameworks. Also, it's important not to overlook the superb competitive generation assets that we have in the mid-Atlantic region and in Montana. While margins have fallen because of lower natural gas and capacity pricing, our units continue to be among the most competitive in the PJM Interconnection. This position has been enhanced by the significant environmental investments that have already been made in our coal units and the investments to expand capacity in our nuclear and hydro units. Our diverse mix of coal, natural-gas-fired hydro and nuclear generation in this region means that we are well-positioned to benefit from proposed EPA regulations. In Montana, our balanced portfolio of coal-fired and hydroelectric generation puts us in a very good competitive position. As I alluded to earlier, we're confident that prices will eventually rebound, and we do begin to see some industrial growth throughout our territories. When they do, our shareowners will benefit significantly. Our strategic actions for the past year have strengthened our financial position, increasing the proportionate size of our regulated business and lowering our exposure to commodity market volatility. Today, we're announcing that our earnings forecast for 2011 is $2.40 to $2.60 per share, and Paul will walk you through the major year-on-year drivers in his prepared remarks. Within the forecast, I'd like to highlight that we're projecting 50% of our 2011 earnings will come from our regulated businesses, a substantial increase over 2010. We've also tightened our range compared with previous earnings forecasts, reflecting a higher mix of rate-regulated businesses and my confidence in PPL's ability to execute on our business plan. Beyond the excellent assets that we have in place to grow shareowner value, we also have some significant strengths that differentiate us from our peers in the sector. In each of the jurisdictions in which we operate, we have strong regulatory relationships built on foundations of transparency and meeting the commitments we make. We respect and value the role the regulators play in ensuring highly reliable electricity and gas services at reasonable prices while providing a fair return to shareowners. Our communicative, cooperative approach has led us to a mutual respect among PPL reps and regulators, a respect that makes us a credible voice in the policy-making process. Our regulated companies are among the best in terms of cost competitiveness, reliability and customer service, earning very high customer satisfaction and regulatory recognition. We intend to retain that distinction by making necessary and prudent investments that will maintain our strong reliability in customer service. In the U.K., for example, we're recognized as an efficiency and customer service leader, benchmarks by which others are judged. This commitment to operational excellence also incorporates disciplined cost management practices to ensure that we're getting the most out of the money we spend. At the heart of our success are 14,000 highly trained, dedicated employees in our business. We rely on these experts to deliver on the promises that we make to our customers and shareowners. Finally, we're clearly remain committed to a strong dividend, which we view as a key element of total shareowner return. Our acquisition this past year fortified our dividend and the rate base growth potential that Bill will discuss in a minute. I think this clearly puts us in a much stronger position to grow the dividend in the future. With that, I'd like to turn the call over to Bill for a business and operational review.

Thanks, Jim, and good morning, everyone. Today, I'm going to review four of our key business segments, with a focus on the value drivers for each one. I believe you'll see that PPL has a compelling growth story in each of our regulated businesses, and we have a highly competitive generation fleet that is very well-positioned. Jim mentioned that our regulated growth and rate base is now estimated at a compound annual growth rate of 9.5% over the next five years. That's a full 2% higher than we had previously forecast. Now let's turn to Slide 9 and start with an overview of LG&E and KU, which forms our largest regulated business segment. Going forward, we will refer to this segment as the Kentucky-regulated segment. The segment consists of two vertically integrated utilities. LG&E is a gas and electric utility, while KU is electric-only. Our regulated generation fleet has a capacity of about 8,100 megawatts with the recent addition of the Trimble County 2 coal plant. LG&E and KU commissioned this 800-megawatt plant in January at a cost of just over $1,500 per kW. This is an exceptionally low cost for a state-of-the-art facility like this. Like our other regulated operations, LG&E and KU have a history of outstanding customer satisfaction and efficient, reliable and safe operations. Vic Staffieri and his team have earned the trust and respect of regulators where they have constructive and supportive working relationships. The combination of efficient and effective operations and this constructive regulatory environment have resulted in these utilities having some of the lowest rates in the nation. These rates are a significant economic development tool for our service territories as well. The growth prospects driven by this economic development coupled with pending changes in EPA environmental regulations will lead to further growth in rate base and returns on that investment. As noted on Slide 10, the Kentucky environmental cost recovery mechanism, or ECR, is provided by a statute enacted in Kentucky in 1992. It allows for near real-time recovery of costs associated with environmental compliance for coal-fired generation. Currently, about 85% of the applicable environmental costs, including investment and operating costs, are being recovered through the ECR. Since inception, over $2.9 billion of environmental capital spending, including CWIP, has been recovered through the ECR mechanism. The remaining 15% of environmental costs represent the cost associated or allocated to all system sales, sales to Virginia retail customers and sales to Kentucky municipal utility, served by KU under FERC-approved, full requirements contracts. These remaining costs are recoverable through general rate cases. As you know, increased regulations being issued and proposed by the EPA are expected to impact coal-fired generation. We expect the majority of our compliance costs in Kentucky will be recovered through the ECR mechanism. Dependent upon final EPA regulations and our evaluation of the lease cost options, we believe the various compliance costs for air and coal combustion residuals, CCRs, could be more than $2 billion over the next five years. This estimate does not assume a hazardous definition for CCR, nor does it include any incremental costs associated with CO2 compliance or new water-quality standards. Our estimate will continue to be refined as regulation and lease cost compliance analyses are finalized. Slide 11 summarizes the environmental control equipment already installed on our coal plants in Kentucky. As you can see, significant environmental controls are already installed at these plants. But we do expect additional investment will be needed to comply with the evolving environmental regulations. LG&E and KU's rate base has grown by more than 50% over the past five years with the construction of Trimble Country 2 and the installation of scrubbers at KU's Brown and Ghent plants. As you can see from this slide, we expect a similar increase over the next five years. We show environmental CapEx in two categories. We expect the spending designated by the orange bar to be needed regardless of the outcome of the new EPA regulations. The green bar represents the $2 billion estimated to comply with new and proposed EPA regulations, as I mentioned earlier. Since the majority of the environmental CapEx should be recovered through the ECR mechanism, the remainder of the environmental and non-environmental CapEx and O&M growth will drive the need for future rate cases. As agreed in the Kentucky change of control proceeding, new base rates cannot be effective prior to January 1, 2013. We are able to offset regulatory lag to a degree using mechanisms that supplement traditional rate cases, and we believe our rates will remain competitive in light of similar activity at surrounding utilities and our favorable starting position. PPL continues to be very pleased with the addition of the newly acquired Kentucky operations. The rate base growth potential, transparent regulatory construct and economic prospects in the Kentucky region will provide earnings growth for this business well into the future. Before turning to WPD, I'd like to comment briefly on the integration process. A significant amount of upfront work went into ensuring a smooth transition upon closing. Our day-one integration work went extremely well, and we will continue to pursue ways to operate the combined business in an efficient manner and within our regulatory commitments. Now let's turn to Slide 14 for a review of WPD. Our WPD business is regulated by the U.K. Office of Gas and Electricity Markets, or Ofgem. The U.K. enjoys a fully developed mature electricity market. The regulatory framework is well established and provides a favorable, efficient system where WPD has thrived for many years. Ofgem has approved a $2 billion expenditure program and the current five-year distribution price control review period, DPCR5, to fund maintenance, capital improvements and upgrades to WPD's network. This approved network investment is 31% higher than that provided in the last price control period. A key element of the regulation is the multiyear formula-rate nature of revenue determination. There is no regulatory lag in expenditures over the entire price control period. They are fully factored into the determination of WPD's revenues during this regulatory cycle. Another key feature of the regulatory construct is the incentive nature of the scheme, whereby companies that are frontier performers can outperform peers on a revenue and ROE basis. Beyond the base revenues, each distribution network operator has the opportunity to earn incentive revenues related to performance and customer service, reliability and cost efficiencies, areas in which WPD has excelled. We expect that our regulated asset value will increase from $2.8 billion at the end of 2010 to almost $3.5 billion by 2015, driven by the network investments I just mentioned. A key component of last year's price control review was recognition of WPD's readership in the area of operational performance. As shown here, we led the industry with the lowest number of customer complaints, best contact center performance, best capital unit cost and customer reliability. In fact, the degree to which WPD excelled in these areas led the U.K. regulator to increase WPD's revenues by over $240 million in this and future rate periods. This type of best-in-class service is nothing new to WPD. During the last price control review, WPD was awarded over $100 million in incentive revenues. And finally for international, at the November EEI Conference, we committed to provide modeling parameters for WPD when we announced 2011 guidance. As a basis for helping model the U.K. operations, we thought that using the segment P&L format, already available to you in our published financial statements, would be the best option. So let's begin with revenues, which are projected to increase by an average of 6.9% per year plus inflation for the balance of the price control review period. Most of our operating costs increased with inflation, although depreciation expense increases at a higher rate due to the increased levels of CapEx. Pension expense is expected to increase from GBP 20 million in 2011 to GBP 55 million in 2012 and beyond, primarily due to projected amortization of prior actuarial losses. For calculating interest expense, most of our debt is fixed, except for about 20% that is inflation-linked. And over the longer term, our consolidated effective tax rate is expected to be about 25%. With these factors and applying the foreign currency rate, you should be able to more accurately model the inherent growth in WPD's future earnings contribution. In summary, the goal for the international segment is to continue to add value for shareholders to frontier performance and customer service and business efficiency, achieving significant growth in rate base and being a source of growing earnings and cash flow for PPL. Now let's move on to our Pennsylvania-regulated segments, starting on Slide 19. Like our Kentucky and WPD operations, PPL Electric Utilities is also known for its superior customer service and well-established, constructive regulatory relationships in Pennsylvania. We have very visible investment opportunities, with rate base growth projected to rise from $3 billion to $4.8 billion, a 60% increase over the next five years. In fact, we expect to make sustained investments over the next 10 years to replace aging infrastructure largely built in the 1960s and 1970s, a good portion of which is now starting to reach the end of its useful life. On the Transmission side of our business, our projected CapEx investment of $1.9 billion through 2015 is nearly 5x higher than the prior five years. As you know, our Transmission business operates under an attractive formula rate structure with annual true-ups effective June 1 of each year, capturing rate base additions and O&M escalations on a very timely basis. The majority of EU's increased transmission spending is recoverable under the FERC formula rate structure, and there are added incentives for our Susquehanna-Roseland line. On the distribution side of our business, we're forecasting $1.5 billion of new investment, resulting from a combination of aging infrastructure, smart grid technology and more traditional CapEx. Distribution costs are currently recovered through a base-rate filing. As we have noted in the past, we are interested in pursuing alternative rate mechanisms that would provide for more timely recovery of and on the capital deploy. Absent this, we anticipate filing rate cases in 2012 and 2014 to recover the increasing expenditures needed to maintain customer reliability and improve network efficiency. EU's CapEx profile on Slide 20 provides further information on those upcoming investments. We plan to increase our capital spending over the next two years before we hit an expected sustained level of capital investment, excluding the Susquehanna-Roseland transmission line. As illustrated here and shown in light green, transmission is a predominant driver of our CapEx growth. The $1.9 billion in investment from 2011 to 2015 consists of $800 million in aging infrastructure replacements, $700 million for capacity and other projects, and the remaining $440 million is associated with the Susquehanna-Roseland line. Regarding Susquehanna-Roseland, the environmental review of the project by the National Park Service is ongoing, after which, we expect construction to resume in 2013 and 2014, with the project in service early 2015. The need for this project has been reaffirmed several times by PJM, and we expect the need for the project will continue to be reaffirmed. We do not expect the recent legislation in New Jersey and associated generation projects to eliminate the need for this line. In summary, our capital investment opportunities and distribution translate into an annualized rate base growth of 10%. Over the same period, transmission rate base growth is just over 20%, from 28% to 40% of total rate base, increasing the proportion of our earnings driven by the transmission formula rate structure. Let's move on to Slide 22 and take a closer look at our competitive Supply segment. We've discussed this segment and its investment highlights with you in great detail in the past, and today I'll provide a brief update. Importantly, we want to highlight our ability to control spending and optimize our operations during low commodity cycles and our ability to meet and benefit from evolving EPA regulations. Slide 23 details the environmental control equipment we've already installed on our fleet and the control equipment under consideration. Approximately 40% of annual output from the fleet is carbon-free, nuclear and hydro. While approximately 50% of our output is coal-fired, the majority of our coal plants are large supercritical plants that are well controlled from an environmental perspective and highly efficient. Our proactive approach to environmental compliance positions the PPL fleet favorably for future EPA regulation. 96% of the competitive coal generation is scrub, 88% has NOx controls already installed. Since 2005, PPL has invested $1.6 billion in environmental control equipment, positioning us very well to meet many of the proposed EPA regulations. The additional control equipment that is under consideration can be installed at an expected cost of just $350 million to $400 million. At this low point in the commodity cycle, we are clearly focused on controlling our cost. We did reduce our 2010 capital spending by nearly $100 million compared to our original plan, and we've reduced our five-year plan by nearly $500 million. We're also focused on managing operating costs. We cut $30 million out of our operating budgets in both '10 and '11 despite the addition of new environmental control equipment and compliance with new security and work-hour regulations at our nuclear station. We have been operating our coal units at minimum output levels during certain off-peak hours and are working to achieve even lower minimum levels. In order to reduce fuel costs, we continue to analyze the types of fuel we're burning at each of our units. For example, we're continuing to prepare several units to burn Powder River Basin coal as well as Illinois Basin. And we look to burn off-spec coal during off-peak periods as another means to reduce costs. We've maintained our disciplined three-year hedging program, which has captured significant value for shareholders. The hedging program added $700 million to our margins in 2010, and our hedges for '11 and '12 are in the money by $1.4 billion. While we're unable to completely eliminate volatility in this business, our hedging strategy has significantly reduced a substantial portion of that volatility. On this slide, we're preparing our asset hedge positions for 2011 and 2012. There are a few notable changes to this slide I'd like to point out from previous quarters. We've eliminated the base load fully loaded hedge price and instead provided the annual capacity revenue separately at the bottom of the slide. This provides more visibility on our expected PJM capacity revenues. As we discussed previously, given current market conditions and transmission work in the region, our forecast for 2011 does not include a basis premium over PJM West Hub for our units. We are also giving you a range for delivered coal prices in the East and now provide you with a range of our expected coal price in the West as well. As for 2013, we continue to be very lightly hedged, with less than 10% of our PJM generation under contract. We do, however, have about 80% of our coal under contract for 2013. When we enter into a more meaningful level of energy hedges for 2013, we'll provide you an update. In 2010, we began to see signs of economic recovery and annual net energy requirements within PJM increase nearly 3% from 2009. This is roughly equivalent to the output of a 2,200-megawatt nuclear plant. PJM forecasts a similar level of increased demand over the next few years. At the same time, low current forward prices and the uncertainty that New Jersey and Maryland are adding to future capacity prices, there is little incentive to add new generation. We anticipate that the return of demand will drive forward market prices higher, as will the impact of the EPA's proposed regulations affecting the supply side of the equation. Our internal modeling estimates that approximately 12 gigawatts of generation could be retired within PJM by 2019. This assumes all uncontrolled units less than 200 megawatts are retired along with some inefficient uncontrolled units greater than 200 megawatts. Analyses by the Brattle Group, Credit Suisse and others have made similar assumptions and project retirements somewhat higher than our own analysis. The impact of those retirements should improve energy and capacity prices over the longer term. Now before turning the call over to Paul, I'd like to conclude with the following. The new PPL, with the addition of the Kentucky-regulated segment, has a very strong group of regulated businesses. These utilities will provide a significant platform of growth for our regulated earnings well into the future. The leaders of these businesses clearly understand the importance of continuing our tradition of working with regulators to ensure reliable service while providing shareowners with solid returns. As I mentioned in my opening comments, we're forecasting a compound annual growth rate of 9.5% in rate base. Over the next five years, PPL will be investing more than $11 billion in our delivery businesses in the U.S. and the U.K. Importantly, of this $11 billion, we expect 55%, or $6.4 billion, will be recoverable using the near-real-time mechanisms in the U.K., Kentucky and under our FERC formula rates. We believe this clearly differentiates PPL from others in our sector. With that, I'll turn the call over to Paul.

Thanks, Bill. Good morning, everyone. Let's turn to Slide 28 to review our financial results for 2010. Our earnings from ongoing operations for the quarter and year reflect the earnings contribution of our Kentucky-regulated segment due to the successful close of the transaction on November 1. For the full year 2010, we earned $3.13 per share, exceeding the $2.87 per share midpoint of our 2010 forecast of earnings per share from ongoing operations. The two largest contributors of our outperformance versus forecast for the quarter were the operating earnings from Kentucky of $0.12 per share and several tax items that net benefited the quarter by just about $0.12 per share. On a segment basis, we fully allocated dilution from the equity units, which was incorporated into our forecast, resulting in a $0.07-per-share net contribution from Kentucky for the quarter. The tax items that net benefited the quarter included a positive impact from evaluation adjustment for Pennsylvania net operating loss carryforwards and the negative impact of bonus depreciation that decreased our Section 199 deduction, both of which impacted supply, as well as the negative tax impact of the tax restructuring that took place in international. I'll review the segment earnings drivers for 2010 and then discuss our earnings forecast for 2011. Turning to Slide 29. Our international regulated segment earned $0.53 per share in 2010, a $0.19-per-share decrease from 2009. This performance was the net result of higher delivery revenue, primarily driven by higher prices, which were effective April 1, 2010 under DPCR5; higher pension expense; higher interest expense, primarily due to the GBP-400-million debt issuance in March of 2010; and higher interest expense on WPD's inflation index bonds on the back of higher inflation later in the year; the favorable impact of currency exchange rates; higher income taxes; and dilution of $0.07 per share. Moving to Slide 30. Our Pennsylvania-regulated segment earned $0.27 per share in 2010, an $0.08 decline compared to 2009. This decrease was the net result of higher O&M expenses primarily due to expanded vegetation management activities and higher staffing costs, lower interest expense due to lower average debt balances, higher depreciation and dilution of $0.03 per share. Turning to Supply. The Supply segment earned $2.27 per share in 2010, an increase of $1.39 per share compared to last year, driven by significantly higher realized sales prices for our Eastern baseload generation, lower margins on load-following agreements due to customer migration and the economic downturn and higher average fuel costs and higher energy margins in the West, primarily due to higher net sales prices partially offset by lower sales volumes. 2010 was also impacted by higher O&M, primarily at our Susquehanna nuclear station as a result of the Unit 1 forced outage in the third quarter; higher refueling outage costs and higher payroll costs; higher depreciation driven by the Brunner Island scrubbers that were placed in service in 2009; lower income taxes, primarily due to the release of deferred tax valuation allowances related to the PA net operating loss carryforwards I just mentioned; and the impact of investment tax credits for the Holtwood and Rainbow hydro expansion projects; discontinued operations, which includes operating results of the Long Island generation and the Maine hydros; and the pending sale of UPark, Wallingford and PPL's equity interest in Safe Harbor; as well as dilution of $0.33 per share. Turning to Slide 32. As Jim already mentioned, we are announcing our 2011 earnings forecast of $2.40 to $2.60 per share, with a midpoint of $2.50 per share. This slide provides an overview of the key factors expected to impact 2011 earnings. A significant earnings driver between 2010 and 2011 is dilution of $0.34 per share, reflecting a full year's impact of the 103 million shares of common equity issued in June 2010 to finance the Kentucky acquisition. The full year addition of our Kentucky-regulated business is the largest positive driver of 2011 earnings, followed by increased delivery margins in our Pennsylvania-regulated segment, resulting from PPL Electrics' already approved distribution rate increase that became effective January 1 of this year. Offsetting these positive earnings drivers are lower supply margins, which are the net results of lower electricity prices, including lower basis and capacity prices in the East and higher fuel costs in the East and West. Partially offsetting these unfavorable factors are higher expected generation and higher margins on load-following agreements. We expect higher O&M at our Supply segment, primarily due to increased outage costs at our fossil plants in the East and West, higher income taxes primarily in the Supply segment due to the 2010 release of the deferred tax valuation allowances and a lower Section 199 benefit, lower earnings as a result of the 2010 sale of non-core generating assets, higher depreciation in our supply in Pennsylvania-regulated segments and higher financing costs due to higher commitment fees and higher debt levels, including a full year of interest on the equity units that we issued in June. In addition, when excluding the impact of dilution, which we've captured as a single driver on this slide, we expect flat earnings in our international-regulated segment driven by higher delivery revenue and a more favorable currency exchange rate offset by higher income taxes, higher depreciation and higher financing costs. On Slide 33, we've detailed our 2010 free cash flow from operations before dividends. The 2010 free cash flow before dividends includes the operating results of the Kentucky-regulated segment but not the cash used in the acquisition of these assets. Since last quarter, the most significant change in the 2010 free cash flow before dividends is the expected timing of the proceeds from the pending sale of Wallingford, UPark and our interest in Safe Harbor. We now expect to close that transaction and receive the proceeds in 2011. The change in cash from operations for 2010 is the net result of the return of third-party collateral, an increase in unbilled revenue and the impact of bonus tax depreciation. In addition to adding asset sale proceeds to 2011, the 2011 free cash flow before dividend is driven by higher expected cash from operations, primarily due to a full year impact of the Kentucky operating results; the cash benefit of bonus tax depreciation and an expected income tax refund in 2011, which are expected to be partially offset by large pension contributions, both domestically and international; and the further return of collateral to third parties. This positive cash from operations is expected to be partially offset by large capital expenditure programs in all segments. Turning to Slide 34. As Jim mentioned earlier, we continue to focus on our dividend as a key element of total shareowner return. Our significantly more rate-regulated business mix provides strong support for the current dividend and for future dividend growth. As depicted on this chart, our regulated earnings alone nearly cover the current dividend. As our regulated earnings grow, we would expect to be able to enhance this dividend growth profile. Now moving to Slide 35. We're looking forward to 2012 and 2013. We expect higher domestic rate-regulated earnings due to higher rate basis directly tied to large capital expenditure programs and assumptions related to planned base rate filings during this period; increasing distribution revenue at WPD except during the 2009 DPCR5 process; lower supply margins as a result of depressed energy prices and our hedge profile; higher O&M in all business segments; positive fundamentals affecting the Supply segment that Bill previously discussed, including heat rate expansion; and increased load as the economy begins to recover. And with that, this concludes the prepared remarks for this morning. So I'll turn the call back to Jim for Q&A.

Okay. Thanks, Paul. Operator, we're ready for calls.

[Operator Instructions] Your first question comes from the line of Greg Gordon of Morgan Stanley.

A couple of questions for you, Paul, and then a question for Jim. First on the -- it looks like overall, capital expenditures at regulated utilities across all the different businesses as it pertains to rate base growth is up, but it was down in Pennsylvania and up in Kentucky. So overall, given that you have automatic rate riders for a lot of those that's pending in Kentucky, whereas you have more regulatory lag in Pennsylvania, I mean, should it be fair to assume that the overall return on equity at your regulated utilities should be rising over the forecast period?

That's a fair statement. When you factor in that pattern that you mentioned as well as the timing of expected rate cases in both Kentucky and Pennsylvania and the expected earned returns in the intervening years, yes.

And I'm looking at your guidance for earnings per share for Kentucky in '11, I'm presuming that assumes that all the leverage associated with the transaction is allocated there. But even sort of sussing that out, it looks like year-one ROE there implied by your guidance is high single-digits, so it's a fair ways off from the current authorized ROE in Kentucky. Is that accurate or inaccurate?

That's accurate. Again, driven by the capital expenditures that we will wait for recovery on, the fact that the last test year that was used was a backward-looking test year that goes back to September of the prior year. We did see very meaningful increases in weather-adjusted load in Kentucky in 2010. So that level of earned return is also significantly driven by continuation of that pattern. So we've been, I think, appropriate in our estimates of what the load is going to look like, but to the extent we see any meaningful improvement that will help offset that. And then again, as you said, when you mentioned all leverage, that does include a full year allocation of the equity units as well. So not just the hold co leverage and what we put at the op cos that replaced the intercompany stuff back to E.ON, but the equity unit financing as well has fully been allocated against that segment.

Right. So if we continue to see industrial load recovery in Kentucky -- I mean, I guess -- well, let me rephrase the question. You've been -- the presumption you just stated is that you're assuming a deceleration in the industrial load recovery in Kentucky in that segment. Is that fair?

That's fair, because they're basically back at above pre-recessionary levels at this point. So to the extent that we can see continued demand for the sectors that, that segment serves in terms of industrial, that will be the single biggest driver. But the recovery was so strong in late '09 and '10 that it'd be tough to see that continuing at that pace. Industrial loads were up almost 19% last year.

So that will be a factor in whether you exceed or miss that number, a big piece of it will be watching the economy in Kentucky?

Yes. In my mind, it will be that and whatever success that we can achieve as it relates to trying to find ways to operate the combined businesses more effectively and efficiently.

Then one last question to Jim. I'm not going to ask you anything directly with regard to M&A, since you clearly don't -- have already indicated you won't answer it. But what are the criteria that you're looking at if you were to pursue another acquisition? I think as investors look at what you've done here, you've been very aggressive in trying to achieve your strategic goals of sort of moving the needle on your business mix. You've, from my perspective, bought a great asset. But you did a very large financing to finance that. So I think as investors look at your profile, I think the feeling is they'd like to see execution on integrating what you've done and -- or is there so much chagrin that you might come back to them and ask for more money for another acquisition so soon. So as you think about those things and you think about the opportunities that exist out there, what are the criteria that would have to be met for you to want to do something without commenting specifically on any transaction?

Well, I think, Greg, the scenario you've laid out I think is -- I agree with, it's very accurate. And I think there are, I'd say, two words that remain in my mind for a consideration of a path to growing shareowner value. And the first word would be strategic. Meaning I would approach that in a vein that matches the strategy that we've laid out to our shareowners. And the second, I think, more important word as to where we stand today in executing that strategy is accretive. So I think that those are two key words that I think any shareowner of any company that would find itself assessing where PPL has been over the past few years would find logical.

Your next question comes from the line of Ashar Khan of Visium Asset Management.

I was just doing a rough calculation of the dilution impact. Am I correct that if the transaction had not happened, the earnings could be like $2.85 in 2011? So there's like a 10% dilution for the impact of this acquisition?

Ashar, there was a partial-year impact of dilution that affected 2010 because the shares were issued in June. The 30-plus cents that's on the slide on the walk from '10 to '11 represents the balance of the year impact to get the full weighted average amount of shares up from basically 390-ish million to 490 million. And then '10 was -- the $0.43 that we initially announced, which was $0.38 from the shares, $0.05 from the equity converts was offset by -- well, it was actually slightly larger because we outperformed plan, but it was offset by the $0.12 that we earned from the segment itself in November and December.

And then if I can just go back to -- could you just reiterate what your financing plans are? This bonus tax depreciation, did it help? Not help? Or any change in financing plans?

One thing, Ashar, and I'm not sure I fully, just based on your hesitation, that I fully answered your last question. I would say that we do not see much dilution in 2011 at all from the Kentucky acquisition. If I phrase it that way, maybe that will -- we do not see meaningful dilution in 2010 from having done the deal. Given where commodity prices have moved, given where we see the earnings opportunities in the other segments, it's not a significant number.

Paul, I don't know, I'll do it, but I guess off the line. But I was getting, if you were doing a stand-alone and there was no Kentucky acquisition, your earnings per share could have been like $2.84 the midpoint 2011 versus the $2.50 that you announced. I could be wrong in my math.

Yes, your math is definitely off.

And then can I just go back? Can you just give us an update on financing plans? This bonus depreciation, does it help? Not help? Or what is the financing going forward in the next couple of years?

Yes, when the bonus -- and again, there are still, and I know other companies have already talked about this, the IRS is still developing either regulation or rev fracs [ph] around interpreting committee reports on what was intended and what the results will be. But we see somewhere around $700 million between the September 9, 2010 implementation and the end of 2012 when in sunsets around $700 million in total cash benefit during that period versus what things would have looked like without the bonus depreciation. Now in a full year like 2011, yes, it's nice that it's FFO. It helps credit metrics. It's cash. We likely will push out the need for equity at least to the very back end of the year. The net impact, though, on earnings is still a negative since we were in a position where we should have gotten around $0.05 to $0.06 of Section 199 benefit. The manufacturers' deduction that affects both the Kentucky and Pennsylvania-based competitive generation, Montana generation. So all in all, it's a net negative from an earnings perspective, slightly, including the impact of pushing back equity financing needs. However, it does provide significant cash surplus or cash benefit.

Overall, you're saying, what, negative by like a $0.05 or so?

No, I'd say negative by about $0.02, $0.02 to $0.03 maybe.

$0.02 to $0.03.

Right.

And then if I can just end up with your views on capacity pricing in the next upcoming auction based on the recent data that has come out?

Sure. Ashar, it's Bill Spence. We would not expect anything significantly different from the last auction. Perhaps a slightly higher number because of the tweaks to the CONE that have been made. Now of course that's absent any impact to the New Jersey legislation or from that. We do expect that the companies, including PPL, that have filed a pleading at FERC and with PJM's expected response, we think we will be successful at requiring any new generation in New Jersey to be bid in at, hopefully, CONE. And that would certainly mitigate some of the potential impact that could otherwise come out of that. So I would say absent New Jersey, maybe a slight improvement compared to the last auction.

Your next question comes from the line of Paul Ridzon of KeyBanc.

Where does customer migration stand in Pennsylvania? And what have you assumed kind of at the midpoint of your guidance as to where that could go in '11?

Yes. Customer migration continues. About 50% of the customer load has switched to a third-party supplier. However, there is no net impact on PPL for two reasons. One is it's obviously a pass-through at the Electric Utility business unit. And as it relates to our competitive supply, we do not have any significant load-following positions in Pennsylvania under any load-following contracts, including PPL Electric Utilities.

And Paul, you talked about delayed equity. When do you anticipate when you would need equity?

Back into the fourth quarter, at least back that far. Remember that we do have a reasonable amount of normal drip. Between drip and management comp, it's around $100 million. So what I'm talking about is that incremental kind of $250 million-ish that I mentioned at EEI. So the other stuff will turn out as we pay dividends.

And then just any -- I guess, maybe, Jim, what's your expectation? Does EPA go full speed ahead? Does Congress have any success in trying to rein in the pace? Or how do you see things unfolding here as we start to come up to March?

Well, I think we're all following, obviously, the politics of the entire EPA situation. The way I think about it is that there will be some hesitance or a little slower going forward than back we expected a year ago. But I think it's important to realize that there are certain things that EPA is mandated to do and will have to complete their regulations on and their rulings. And so I tend to think that much of the intent of the regulations will become evident through this calendar year, either by laying them out in great clarity or enough information on the table to know that they will happen. So I think our view has been looking at our fleets and our level of economic spend that we've already accomplished on our generating fleets. We stand to be in a very good position going forward in that we've already spent the money and spent it at the right time. We, in fact, will benefit from additional small coal-unit shutdowns, as I think Bill mentioned, our supercritical fleet here and then out West and Kentucky. Obviously, that will be recovered under the ECR. But in our merchant markets in Pennsylvania, Kentucky, we're positioned very well for the EPA regs as we see them unfolding. But I do think -- to try to answer your question, I see a bit of a delay, but I don't see them going away by a long shot.

And then lastly, DOE authorization to name transmission corridors was struck down. Did that have any impact on the RS line?

No, not at all.

Your next question comes from the line of Paul Patterson of Glenrock Associates.

The deferred tax release that you mentioned, could you just elaborate a little bit more on that in your waterfall chart that you were talking about 2011?

Yes, sure. We have a substantial amount of Pennsylvania net operating loss carryforwards at energy supply and energy funding that, based upon a historical record of not showing profitability at that entity, we had to reserve again. So it simply weren't muted being realizable. Last year, we released a couple of cents to earnings from that. This year, with having the -- what changed more dramatically this year was, one, a business plan that showed significant taxable income at that entity and being able to get out from under rate caps and all the clamoring that went on in the legislature through the end of last year, only a small amount of valuation allowance resulted from last year. But when we got into the end of 2010 and completed the business plan, we just simply saw much more robust taxable income levels that would justify using the credit. So it amounted to $0.15 to $0.17 of total, the 199 impact was a negative $0.03, and then the international tax restructuring was a negative $0.07. There's more very small ones beyond that, that got to the '12.

Okay. So should we see any substantial tax changes past 2011 that we should be thinking about like this, or...

No, there's a very -- there is an amount of deferred tax valuation allowance that remains. It's not anywhere near what was released between the combination of this year and last year. We would have to see a relatively significant improvement in power market fundamentals on a competitive business to see the ability to release that and positively affect the effective tax rate. So I don't see that in any significant way until we see something more positive on that front.

Okay. Has there been any change in the trading marketing outlook that you guys gave before?

No, pretty much right on track, no change.

And then just to clarify, the $250 million of equity that might happen as early as the fourth quarter, did I understand that correctly?

That's correct. I think we originally might have planned that second or third quarter. But obviously, the need is pushed out. The cash is here, and we're trying to mitigate, obviously, as well the negative effect of the loss of Section 199 due to all this bonus depreciation that decreased the taxable income so much.

And then the PJM filing, whether you said to the New Jersey legislation the 205 filing, what's your expectation on timing of it? I mean, it's almost like we're a week since the governor signed it, and you would think that there would have been a lot of preparation before he signed it. Any thoughts as to when we're going to actually see that filing?

I think it will be very shortly. I don't have the exact time frame. But obviously, P3, which is the group that we're involved with, a lot of the larger PJM generators, made its pleading. I do expect a very timely response from PJM. And I would expect the market monitor to testify in support of making the necessary changes to impose a minimum offer price. And then at the same time, P3 members either collectively or individually will be making federal court challenges as it relates to federal preemption and trade interference. So that will be coming probably after, I would think, the PJM filing at FERC. But that's something that's obviously important to us as generators and a big challenge to competitive markets in PJM. So we are very serious about using everything in our power to overturn this kind of threat.

In the P3 filing, it mentions the subsidization that's been happening on the renewable area as being something that would be deferred for the purpose of their expedited filing, but something that had be looked at. Would be that something that you would be looking at in the federal courts in terms of going after the sort of -- there is a large amount of subsidization, as we all know, in the power markets with respect to certain types of generation. Is there any thought about that?

I'm just really not sure about that. I would say that the reason we mentioned it, but at least at the FERC level, we want to keep that out for now, so we want to have a laser focus on just getting this issue with the 2,000 megawatts dealt with right out of the blocks in time for the next PJM auction. So we want to be very focused in what we're asking FERC to look at.

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

When you look back at what you've said at the time of the Kentucky acquisition in terms of business mix, and you were talking about 55% to 60%, I think was the target you have for regulated, and it looks it's going to be 50-50 or so in 2011 earnings-wise. Can you just help us think about that? Could you get there naturally from further decline in the above market hedges? So how do you think about that target cyclically with where the Supply business is and the range of earnings that it could have?

Well, I think going back to that first part of the comment, John, I think the 55% to 60% was kind of on an EBITDA basis. That's what we had disclosed. From a balance sheet perspective and through the commodity cycles, clearly better than 50%. But with all of the growth that we see, the shape of the commodity cycle and our hedge profile, at a mid-cycle number, something in the 70% to 75% feels like the right range for us to be in. If it got to 80%, if it went as low as 70%, that wouldn't cause us to alter mix, per se. But just in terms of being able to handle the volatility to meaningfully address the dividend over time, provide the transparency in growth, that feels like the right kind of mid-cycle mix to us.

The 75%, is the right number mid-cycle?

In that range, yes.

75% regulated?

Correct.

And can you just give us an idea of, as you look the hedges you have on your book, I mean what year looks to you most like mid-cycle?

I'd say probably you're going to get out to that '14, '15 time frame would be my guess. I mean, if you just think about where PJM capacity reserve margins are and you look at some of the projections, I think if you get out in that '14, '15 range, you get closer to the kind of targeted PJM reserve capacity mix. So I think that's probably in that time frame.

You'll probably get close to the bottom end of that range by '13. But Bill is right, it's probably closer to '14, '15, so you're at the mid.

But I guess you have nearly $6 gas at that time frame, is that...

That's still what hangs out in that period, roughly correct.

You wouldn't describe that as mid-cycle, I'm guessing?

I think it's a reasonable number. I don't know, plus or minus $0.50, but...

And as you run -- I mean you think you would naturally get to the 75%-type number in that time frame, or...

Again, just based on open march [ph] with what we have now, it wouldn't be far off from that number.

Your next question comes from the line of Daniele Seitz of Dudack Research.

I was just wondering what do you see for the longer term in terms of payout ratio? And also what are your sort of cap structure goes, given the larger portion of regulated business that you will have?

Sorry, Daniele. Can you repeat? What do we see over the longer term related to...

I mean payout ratio, dividend payout ratio and the capital structure.

Yes, I think we'll wait before -- as we let the businesses evolve, the spending and, naturally, get through a couple of rate cycles here before we come out with something on a targeted payout ratio basis. What we were trying to indicate on the dividend slide is showing that, and combining this response with how I responded to Jonathan's question, we'll very clearly be able to more than sufficiently to cover the dividend with the regulated earnings. I think it depends upon where we see mid-cycle gas prices driving power, which drives margins, and maintaining our three-year hedge profile. I think it's difficult until we get up into that 75%-ish range that I'd I feel comfortable talking about payout ratios, and as well, getting through the last part of our generation build around the Susquehanna operates, the Holtwood and Rainbow construction projects and get into more of a normalized level of maintenance CapEx spend as well.

And in terms of capital structure, you're planning on this equity issue at year end. Do you think that you will have -- because of the expansion that you're planning on, do you think that every two years you will be issuing equity?

Again, at this part of the commodity, I'd clearly say that that's a safe bet. Again, if the regulated utilities are kind of fully paying for the dividend, and the generation business is using its surplus cash flow to fund some small capital expansion projects, we've got to be able to fund that CapEx growth at the utilities in some way, and it would be through a balance of debt and equity. I think that it would be reasonable amounts of equity, not unlike other companies that have to fund programs in this way. And again, what I'd say is the biggest driver there is maintaining the investment-grade credit rating in those businesses but as well as Supply. So that's really what drives the timing and amounts. It's a combination of the commodity cycle and the cap structure to achieve targeted credit metrics while trying to limit dilution.

And last question, have you mentioned your plans to the Pennsylvania Commission in terms of the upgrade of the infrastructure?

Yes, absolutely. We've had a long series of conversations with them, going back well more than a year about what we're seeing in terms of equipment, performance, reliability, degradation rates and the need to be able to achieve the service reliability level that they've outlined for the entire section that need to be achieved. And again, as Bill mentioned in his prepared remarks, a lot of this equipment goes back into the '50s, '60s, '70s, and it's just simply reaching the end of its life. And from both a company perspective and a customer perspective, the right decision is to not chase O&M expense but to replace this old equipment. It's better for the company and it's cheaper for the customer in the long run to make that investment that it is to be chasing reliability problems.

Your next question comes from the line of Carl Seligson of Utility Financial Expert.

Paul, in your last slide, you mentioned the planned distribution rate filings. I wonder if you could be a little bit more specific as to which jurisdictions, when you intend to file or what the size would be, what your targets are as far as ROE is concerned. That kind of thing.

Okay. Obviously, we get the more, I'll call it, perfect recovery in the U.K. in the FERC transmission. So what we're really talking about, what's left, if you will, is Pennsylvania distribution and then the Kentucky assets that that's not recovered in the ECR in Kentucky. In Pennsylvania, what I would say is that, and I think Bill mentioned this in his remarks, that we have filings in our business plan in 2012 and 2014, which would result in new rates effective 1/1/13 and 1/1/15 on the distribution side. In Kentucky, I think when we get down into the 9% kind of ROE levels, that would historically have, in how we think about it, triggered the need for filings there. Now we do have a committed stay-out from the change of control filing that we cannot file until '12 for new rates to be effective earlier than 1/1/13. So a potential scenario is filings in both Kentucky in full and then in Pennsylvania for the D side, with new rates in both effective 1/1/13. That's a potential, again, based upon what happens with load and what happens with costs and our success around efficiencies in that area, being timetable as well. But that's kind of what our plan would indicate would be needed.

And in the context of where ROEs are around the country these days, your filing would be contemplating that kind of thing and the fact that the Commissions are basically in the, I don't know, 10-ish range, if you're lucky, 10.5...

Yes, the 10 to 10.5 is -- we did a black box in the last settlement in Pennsylvania, but that's in the right zip code. Clearly, Kentucky was at kind of an announced ROE number, and it was at the upper end of that range that you just mentioned. The ECR just got reaffirmed at 10.6 or 10.63. So I mean, I think that that's in the right zip code.

Okay. Finally, with regard to Kentucky. Is there a prospect that Chairman Armstrong will not continue after his term expires next year?

Not sure. I don't think we know.

Your next question comes from the line of Leslie Rich of JPMorgan Asset Management.

When the acquisition of the Kentucky utilities was initially announced, I think there were some NOLs there that you were hoping to use. And I just wondered what the status of those are?

The status, Leslie, is exactly as we had forecast in due diligence. There is the potential for a larger asset driven by some capital loss carryforwards that got created as a result of unwinding some of the international things that Kentucky owned prior to our acquisition. So the total deferred tax asset that's there is slightly higher than what we had forecast. In terms of the timing, and, again, this is all balance sheet, this is not P&L. But in terms of the timing of utilization, the utilization will get pushed out a bit, simply because of all these bonus depreciation that the government has permitted. When you're able to fully depreciate in year one, everything that's kind of 20 years or less in terms of useful life, that will get pushed off a year or two. But the value of what we purchased is slightly greater than what was originally assumed.

So it was originally around $450 million?

That's correct.

And then you said you're going to be making a large pension contribution in 2011. Do you have any idea what the size of that would be?

Yes. We actually had total contributions in 2010, globally, of $435-ish [million]. That included about $230 million in the U.K., so they were the biggest driver. And then we had about $200 million, domestically. When I say we, that includes what Kentucky contributed, even though it was prior to our ownership level. In 2011, the figure is $480 million. We increased it very slightly at year end, but most of that was planned. It's not anything that's been enhanced because of the bonus depreciation. But unlike last year, it's a very small contribution to WPD, and most of it is actually coming from -- about $300 million of that $480, $320, from the PPL legacy and then $150 million in Kentucky.

And then finally, you discussed the potential for a $2 billion of environmental CapEx in Kentucky and actually put that in your rate base slide. But as I look at Slide 11, it looks like those coal plants in Kentucky are already largely retrofit. So just not clear what that $2 billion would potentially be allocated towards?

Yes, many of those units either have old technology that would have to be refreshed or they lack some of the best available control technology that may be required under the various air emissions regulations in particular. So those are our best guess at this point of the incremental expense associated with bringing existing units up to the new standards.

Your next question comes from the line of Brian Russo of Ladenburg Thalmann. Brian Russo - Ladenburg Thalmann & Co. Inc.: Would you mind just commenting on what your coal delivery costs are on a per-ton basis in the 2012 and beyond period?

We do provide on the hedge slide the estimate that we have for delivered coal in the East and West. And for 2012, the range is $76 to $80 a ton for the East, and the West is $23 to $29 a ton. Brian Russo - Ladenburg Thalmann & Co. Inc.: Great. That's full delivered coal. Is there any way to break that down? I think in the last quarter, you may have insinuated about $24 a ton for delivery cost?

Correct, that's correct. And that's still right in the ballpark, yes. Brian Russo - Ladenburg Thalmann & Co. Inc.: And then lastly, it looks like your intermediate and peaking swifter generation increased quite a bit from the last quarter. I'm just wondering, is that a function of tightening power markets? Or are you just seeing increased gas-powered generation displacing coal generations? Just wondering what your thoughts are there.

Yes, good question. It is related to an improving heat rate as well as some displacement of other units, coal cos, many of them are coal.

Your next question comes from the line of Michael Lapides of Goldman Sachs.

So when you talk about the U.K. business, and specifically near-term, can you kind of walk us through your, if you've done this before, your expected kind of a long-run earnings growth and whether that differs dramatically from the long-run revenue growth? And, B, and maybe even more importantly, can you talk about the REO process there, what this potentially means for changes in U.K. regulation and how that could potentially impact your views of your U.K. business overall?

Okay. Let me try to -- but maybe, Bill, chime in too. Let me try to tackle that one. I think from what we've said, as we focus on the move from 2010 to 2011, if we factor off the incremental impact of dilution from the full year of the common stock issuance from last year, that international is kind of flat year-on-year. When I think what the major contributors are and detractors to growth going forward, we did mention that we have a relatively significant increase in FAS 87 pension expense that's impacting '10 to '11. We don't see a further increase in that as we move from '11 to '12 or '13 or '14. So what will happen, what should happen, is we should see the leverage that's coming from the 6.9% plus inflation revenue increase year-on-year with O&M costs exclusive of, again, depreciation because of this big CapEx program that's rising slightly larger than inflation. We should see a decent amount of compound growth off of the 2011 number as we go forward through the rest of the price control periods through 2015. And again, sorry, what was the second...

REO.

Oh, sorry, REO.

Yes, REO, please.

REO is expected to do a couple of things. I think probably the most significant thing is, and the reason why you don't see with a very large CapEx program a bigger increase in rev over the five-year horizon is that the current regulatory depreciation rate, which ends up in revenue in the U.K., is 20 years, and that's likely to be extended to 40 years. In addition, the regulatory review period, and we'll get our first opportunity to see this upcoming in the gas cycle here, is expected to be extended from five years to eight years. So this kind of formula rate treatment and the predictability and forecastability should go out over a longer period of time, to be determined what happens in the intervening years, though, because eight years is a long period to commit to a capital structure as to what they will permit or what they will do with the cap structure, meaning interest rates, assumed interest rates in your model cap structure over that eight-year period of time. I think there's more to come on that. They've issued kind of, if you will, position papers early, thought papers around that in early last year and late last year, but I think we'll get our first real opportunity once the gas distribution folks go through the process, and then they'll be expanded to us.

And that interest rate as well as just other impacts a longer cycle could help offset the longer depreciation period from that 20 to 40 years, as Paul said.

Right. So I think...

And that we'll have to wait and see how things shake out, but I don't know that it would fundamentally change our view of the benefits of the U.K. regulatory scheme.

Right. And in that new period, if they do alter depreciation-wise, they would simply -- that would slowly blend in as you bleed off the time of return of the legacy assets versus the new things that you add. So it would be a slow progression over time.

And if I look at Slide 17, and you were talking about pension expense, and your comments were very helpful, the GBP 20 million in 2011, what's the baseline in 2010? I'm just trying to -- increases from GBP 20 million to GBP 55 million, I'm just trying to think about what the bridge is from '10 to '11?

Let me try to get that number for you.

Or is it a -- I'm trying to think about, is that GBP 20 million the incremental from '10 to '11? Or is it something smaller because you're not including the '10 base?

Just one second.

We can follow up offline.

Let me try -- let's follow up offline, if you don't mind.

Your next question comes from the line of Reza Hatefi of Decade Capital.

Paul, you mentioned $250 million equity in '11 or, I guess, the tail end of 2011. Is that still DRIP or not?

It would either be an ATM and at-the-market or something. Within the DRIP program, we do have the discount waiver opportunity or capability that we added last year to the program. But it would be one of those three mechanisms.

And then I guess, you guys raise CapEx a lot and had previously sort of talked about maybe $300 million a year of DRIP dribble every year, essentially. Is that still the plan, given the new CapEx forecast?

I think if we add the significantly higher and its all very timely recovery environmental CapEx for Kentucky, that number could grow. I think we need to wait to see what the final regulations look like and what the compliance schedules are to be able to give you a better definition around what the amounts would be and over what time frames. That was more at a planning rate that was with a lower level of environmental and other CapEx in Kentucky, so it would be enhanced off that a bit.

Given the increased CapEx in your new slides, I guess?

That's correct.

And then you guys said you're mostly hedged on coal in 2013. Is that going to -- from a price perspective, is that going to be similar to 2012 or a little bit higher? Or how should we think about that?

Yes, it'll probably be a little bit higher, because it builds in some price increases that are in the longer-term contracts.

And lastly, could you give your current thoughts on basis?

Sure. Yes, I think last year, we ended with a negative basis to the weighted average of our plants of about $1.40. But as I mentioned on the last call, we had hedges in place that were helping to offset that. So we wound up at a positive $0.84 with our hedges incorporated. If you look at last year, as I mentioned, there were numerous transmission outages, in fact, more than we've ever seen in the recent past. There are somewhat less outages this year, and you have the trail line coming into service in June, which should help basis relative to last year. So I think while we've assumed zero, I think we're still very comfortable that that's an achievable number, and perhaps there may be a little bit of upside, depending on how things shake out with the trail line and congestion.

And then your average energy-hedged prices, I guess you've taken away the fully loaded disclosure that you used to give. Besides capacity, should we just add your basis commentary to the energy, and then we're sort of there where we were relative to your prior disclosures?

That's correct. In the past, we also had a small amount for ancillary services, but of late, they've been very small as well. So yes, if you just added the capacity back in, in the basis assumption, then you're back to the fully loaded price.

Your next question comes from the line of Tom O'Neil of Green Arrow.

I just had two separate questions, so first was on the REO model. Is there any clarity just in terms of how they would be dealing with double leverage in the intermediate holding company? And then second question is on rail rates, just what the duration of the current contracts are and just the price reset periods.

Sure. On the first question, no, there is no, not that I'm aware, there's no impact to double leverage on the REO. On the coal, our major contract with NS expires at the end of 2012.

There are no further questions at this time.

Okay. Thank you, Operator. And thank you for all tuning in on the call. I'd just make a couple of comments here as we close. One, I think we're very pleased with the results of our Kentucky acquisition thus far. And I think pretty clear we have accomplished what we intended when you see our reg earnings jumping from 27% up to 50%. So we're certainly moving along with our strategic direction that we've laid out to you. I think we're very pleased as we look at our potential compound annual growth rate, just shy of 10% on a regulated rate base, and also the high percentage of spend in that growth rate base that will come from regulatory jurisdictions where we eliminate a good part of the regulatory lag. So we're very encouraged by that. We've also pointed out, I think, that we do stand to benefit, basically, from the EPA regs as we see them unfolding, based, to some extent, on our early work in our Pennsylvania fleet and our Montana -- condition of our Montana assets and also the regulatory posture we have or structure we have in place in Kentucky. So I think with that, we feel pretty good about going forward. We've seen some encouraging industrial growth in some of our regulatory regions. And I think that's what we all want to see. And as this economy continues to try to recover, I think our position will strengthen there as well. And we'll see, I hope, improved prices in PJM, and we'll be able to take advantage of a really good fleet and good pricing position we have in the PJM Interconnection. So with that, I thank you all for sitting in on the call and look forward to talking to you again. Thank you, Operator.

Thank you again for participating in today's conference call. You may now disconnect.