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Executives

William Johnson - Chairman, Chief Executive Officer, President and Chairman of Executive Committee

Mark Mulhern - Chief Financial Officer and Senior Vice President of Finance

Bryan Kimzey -

Analysts

Dan Eggers - Crédit Suisse AG

Jonathan Arnold - Deutsche Bank AG

Mark Sigal - Canaccord Genuity

Gordon Howald - East Shore Partners, Inc.

Greg Gordon - ISI Group Inc.

James von Riesemann - UBS Investment Bank

Raymond Leung - Goldman Sachs Group Inc.

Progress Energy (PGN) Q2 2011 Earnings Call August 4, 2011 10:00 AM ET

Operator

Good morning and welcome to Progress Energy's second quarter 2011 earnings conference call. [Operator Instructions] For opening remarks and introductions, I will now turn the call over to Bryan Kimzey of Progress Energy. Please go ahead.

Bryan Kimzey

Thank you, Kelly. Good morning and welcome, to everyone. Joining me this morning are Bill Johnson, Chairman, President and Chief Executive Officer; Mark Mulhern, Chief Financial Officer; and other members of our senior management team. We are currently being webcast from our Investor Relations page at progress-energy.com/webcast where we have also included a set of slides which accompany our speakers' prepared remarks this morning.

Today, we will be making forward-looking statements, as well as reviewing historical information. There are numerous factors that may cause future actual results to differ materially from these statements, and we outline these in our earnings release, Form 10-K, 10-Q and other SEC filings, as well as the risk factor discussion also found in our forms 10-K and 10-Q. For your information, we plan to file our Form 10-Q early next week.

This morning, following opening comments from Bill and Mark, we will open the phone lines to address your questions. Now I'll turn the call over to Bill Johnson.

William Johnson

Thanks, Bryan. Good morning, everyone. Thanks for being on the call. I know it's a crowded earnings calendar for you today so we'll dive right in. Slide 3 indicates -- I'll provide highlights of the second quarter and year-to-date financial results along with an update on our proposed merger with Duke Energy. I'll also update you on our nuclear fleet and comment on the NRC's Near-term Task Force recommendations, as well as the EPA rules in our major capital projects. Then Mark Mulhern will provide more detail on our financial results.

So let's start with ongoing earnings on Slide 4. For the second quarter, we reported ongoing earnings of $211 million, compared to $181 million for the same quarter a year ago. On a per-share basis, we're up $0.08 from the second quarter 2010. Primary drivers of the gain were lower depreciation and amortization expense in Florida and increased clauses in other margins. And these were partially offset by unfavorable retail growth in usage in the Carolinas and lower wholesale revenues in Florida.

Based on our performance for the first half of the year and our expectations for the remainder of the year, we are reaffirming our previously announced 2011 ongoing earning guidance range of $3 to $3.20 per share. On the merger front, we continue making good progress towards closing the merger transaction with Duke Energy by the end of the year. Earlier this week, the Kentucky Public Service Commission conditionally approved the merger. As you can see on Slide 5, we have now filed with all of the required state and federal agencies and are moving through the approval steps with each agency. We filed our testimony in North Carolina on May 20, and are now responding to data requests from the intervening parties. The hearing in Raleigh starts on September 20.

In South Carolina, the discovery process has begun and we are responding to data request. The final date for parties to file for intervention is August 8, and we'll be filing our testimony in South Carolina in the near future. The commission there has not yet set a hearing date. Meanwhile, we'll hold a special merger vote meeting of our shareholders on August 23. Likewise, Duke Energy will hold a similar meeting with its shareholders on the same day.

Now if you'll turn to Slide 6, which provides information about our nuclear units in the Carolinas. Through July, these reactors had a 95.2% capacity factor and that includes 1 plant refueling outage. The Robinson plant continues to demonstrate solid performance following the atypical performance of last year. The plant has been online for more than 258 consecutive days since returning to service. This last quarter, the NRC completed 2 in-depth special inspections at Robinson. And the feedback was positive and reflected the marked improvement in the plant's performance. The plant is still executing on its improvement plan and we will continue our management focus to ensure it reaches and sustains the desired operating performance I know they are capable of achieving.

On this slide, we have provided a listing of several major construction projects at the plants. I highlight these projects to show efforts completed or under way to improve the plants. Now as you know, the NRC's Near-term Task Force recently reported on its assessment of U.S. nuclear operations following the Fukushima accident. The headline is that the nuclear plants in this country are safe, but we should incorporate the lessons learned from the March event at Fukushima. The NRC has not yet determined its specific response and what the timing will be for any new requirements. At Progress Energy, we've conducted detailed inspections and reviews at each of our nuclear facilities to ensure we can effectively respond to extreme challenges of all sorts. And in some cases we've already strengthened our processes to incorporate these lessons learned. We recognize that to maintain the highest levels of safety and security, we must continually adapt and improve our practices. Along with the other nuclear operators, we will continue to support industry initiatives that evolve as we learn more about Fukushima. We believe a systematic analysis of root causes needs to be completed and thoroughly reviewed before the enactment of new rules and regulations.

Now, let's turn to the repair outage at our Crystal River nuclear unit in Florida. As we discussed on last quarter's call, we suspended repair work on the containment building in mid-March after identifying additional concrete delamination. We conducted a thorough engineering analysis and review of the structure, and evaluated a wide range of repair options. On June 27, we presented our findings to the Florida Public Service Commission, including our recommendation to repair the structure and return the plant to service. This specific repair option selected would entail systematically removing and replacing concrete in the containment structure walls. The preliminary cost estimates for this repair is between $900 million and $1.3 billion and it would enable us to return the unit to service in 2014. Based on what we know today, we continue to believe this approach is better for our Florida customers than retiring and replacing the plant. But as I said in June, we're approaching this situation in a very disciplined way, and continue to assess cost and feasibility at every step. We and several intervening parties met with the Florida Commission's pre-hearing officer on July 14. We discussed the procedural timeline for reviewing the prudence of actions associated with the initial steam generator replacement in the fall of 2009 and with the containment building repair work. Since then, we have met with the intervenors in an attempt to reach agreement on a procedural timeline. Another status meeting with the prehearing officer is scheduled for August 8, and we intend to submit a scheduled proposal before that hearing.

Slide 7 presents the cost data for this outage through June 30. We're still conducting engineering analysis and developing bid documents for the engineering and repair work. Also, a major effort is under way to prepare the plant's infrastructure for the repair work, as well as to ensure the major equipment systems are properly maintained throughout the outage period. You can see some details on insurance coverage on the bottom half of Slide 7. We maintain insurance coverage against incremental cost of replacement power resulting from prolonged accidental outages through NEIL. Following a 12-week deductible period, the NEIL program provided reimbursement for replacement power cost for 52 weeks at $4.5 million per week through April 9 of this year. An additional 71 weeks of coverage is provided at $3.6 million per week. So the NEIL program provides replacement power coverage up to $490 million per event. We also maintain insurance coverage through NEIL's accidental property damage program, which provides coverage of up to $2.25 billion, with a $10 million deductible per claim. We are continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs.

Now if you turn to Slide 8, and the EPA's Cross-State Air Pollution Rule known as CSAPR. This final rule replaces the Clean Air Interstate Rule and it affects 27 states. The first compliance period under this rule begins in 2012. Now, CSAPR has a lot of complexity to it, and we're still evaluating it. What is clear is that this final version has some significant differences from the proposed rule and overall, it is decidedly more stringent. For example, state-budgeted allowance allocations were modified, and in most cases are lower than in the proposed rule. Florida's NOx ozone season allocation is about 50% less than in the proposed rule, and in North Carolina SO2 allocations in 2014 are about 30% lower. The reason for this in part, is that the EPA changed the unit level allocation to a fuel neutral methodology based on heat input. And so coal-fired units were allocated significantly fewer allowances, and gas-fired units more allowances. In addition, the state assurance limits or the caps begin 2 years earlier. And some states having additional reduction of NOx allocations in 2014.

So what does all these mean for Progress Energy? As I've said, we're still assessing the impact, but it will likely affect our resource plans and how we operate this system. Fortunately the impact will be mitigated somewhat, because we began our fleet modernization several years ago. In North Carolina, we've spent $1.2 billion on approximately 3,500 megawatts of coal-fired capacity to reduce NOx and SO2 emissions with a significant Mercury Co-benefit. In addition, we've announced the retirement of our 11 uncontrolled North Carolina coal units for about 1,500 megawatts and we'll be replacing this coal capacity with new clean and efficient natural gas-fired capacity. But even with these steps, and with the fleet modernization, the more stringent standards might require us to alter the dispatch of Carolina's fleet or to purchase emission allowances were feasible in order to comply with CSAPR.

Meanwhile, in Florida we spent $1.2 billion on approximately 1,400 megawatts at Crystal River 4 and 5 to reduce NOx and SO2 emissions, again, with the significant Mercury Co-Benefit. Despite this successful project, we have approximately 2,000 megawatts of uncontrolled coal and oil-fired capacity in Florida. It remains at risk of compliance under the NOx ozone season program. So at this point, we know that the Cross-State Air Pollution Rule will mean incremental costs for compliance through emission allowances, higher O&M at our natural gas-fired plants, and potential environmental controls or replacement capacity, especially in Florida.

Slide 9, which we've shown you before, illustrates how the EPA's proposed utility MACT rule and water intake rule will affect our fleet. The MACT rule is expected to be finalized in November, and actually, the comment period on that rule ends today. Again, our fleet modernization efforts have put us in a comparatively better position to comply with these requirements, but these rules will increase cost to our customers. I think it's fair to say that the combined effects of EPA's recent and pending rules will be significant for our company and industry, and there are more requirements in the pipeline.

Turning now to our major capital projects on Slide 10. We're making excellent progress in modernizing our power system. On May 20, we broke ground on our new combined-cycle natural gas plant at the Sutton site. This unit is scheduled to be online in December 2013. Our newest plant, the Richmond County combined-cycle began service in early June. We continue to manage our system modernization projects in a disciplined way to meet constant scheduled targets. So now I'd like to ask Mark Mulhern to provide a little more detail on the numbers for the quarter. Mark?

Mark Mulhern

Thank you, Bill, and good morning. I will cover the topics outlined on Slide 11. So if we start with Slide 12 which shows our second quarter ongoing earnings, for the second quarter 2011, we reported $0.71 versus $0.63 last year. Progress Energy Carolinas was down $0.02, Florida was up $0.07 and the Corporate and Other category was $0.03 favorable. The main drivers for the quarter were in clauses and other margins, amortization of the cost for removal obligation in Florida, and slight positives in O&M and interest expense.

On balance, this year's second quarter was above normal in terms of weather, but compared to 2010 weather, accounted for $0.02 of negativity.

Going to Slide 13 is our waterfall chart which outlines the positive and negative drivers for the second quarter. You see there, the largest positive on the page is the $0.09-benefit associated with the amortization of the cost for removal obligation at PEF. The $0.06 positive variance and clauses in other margin is comprised of $0.03 of PEC from expanding demand-side management programs and $0.03 in margins at PEF, partially related to lower joint-owner replacement power costs related to the CR3 outage. So for the quarter, we had a positive impact of $0.02 from lower O&M and $0.02 pick up from lower interest costs.

On the negative side, there were a number of $0.02-items that reduced earnings. The growth in usage item was comprised of $0.01 positive in Florida, but a negative $0.03 in the Carolinas, and I will address this in just a few moments. During our update call on the Crystal River 3 on June 28, we indicated that we would be reserving $45 million pretax for the indemnification costs for future years' joint-owner replacement power costs. Because this charge relates to 2012 and 2013, we have excluded it from ongoing earnings as a one-time charge, and it amounts to a $0.09-charge to GAAP earnings in the quarter.

Now, I'll turn to the first half of the year variances that are summarized on Slide 14, which is our year-to-date waterfall chart. Just a couple of brief points here. Year-to-date we have utilized a total of $134 million in cost for removal amortization in Florida. That leaves a balance of $338 million that we can utilize over the next 18 months. Then as you see the reversal of very strong weather we had it 2010, which accounts for a negative $0.19 item, and then the clauses and other margin, AFUDC equity and O&M were the other positives for the first half of the year, and were offset by slight negative variances in wholesale and growth and usage, and dilution from shares issued in 2010.

Slide 15, shows our weather-adjusted retail sales. And this slide is different from the way we have traditionally shown it and different from the presentation on Page S4 of the earnings release. And we elected to show it this way with the unbilled adjustment allocated to the customer classes, because our unbilled variance at Progress Energy Carolinas is larger than normal. Extreme weather and the way the billing cycles fall on the calendar impacted the unbilled amounts at the quarter end, so there are 3 key points on this slide. The first point relates to the very significant impacts of weather on retail sales in both utilities for the periods being compared. You will recall that 2010 was a very strong weather year at both utilities. And as you can see, weather is 3% of the total 4% variance at PEC and 5.6% of the total 6.1% variance in total retail sales at PEF.

The second point is a recognition that our growth in usage numbers are trailing our forecast at the halfway point of the year, so we are behind our plan by 1.8% at PEC and 1.2% at PEF. Lower-than-expected customer growth has been the larger variance, with usage being closer to our expectations. The third and final point is, it is still early in the year, with our largest revenue and earnings quarter in front of us. Therefore, I would not jump to conclusions based on this data. We expect these numbers to improve in the second half of 2011 and we have seen some early signs of that improvement in July with an increase of approximately 2,000 new customer accounts at PEC, but still expect the full year to be weaker than our forecast with the return to normal sales growth still further down the road.

Our industrial customers showed a strong recovery in 2010 and in early 2011. So strong gains were seen in the metal and paper industries, and coupled with the strong rebound in the textile industries. Starting in the second quarter of this year, our customers began reporting increasing inventories and excess capacity, and some have instituted shorter operating hours. Our experience is consistent with some of the recent economic data reflecting a slowing economy, and not the steady recovery we had all hoped for.

So now let's turn to Slide 16, which is our standard slide on the customer growth and low-usage accounts. Florida continues to show a positive trend in customer growth. Florida had a net addition of 8,000 customers year-over-year and the Carolinas added 6,000 customers year-over-year. Over the last 3 quarters though, Florida appears to have leveled off its growth trajectory and the Carolinas are still lagging historical trends in customer growth. We are still not seeing any strength in the region in terms of new customer growth.

So on Slide 17, just to highlight of number of points that you should consider regarding our results for the full year of the 2011. On a trailing 12-month basis, our ongoing earnings are $3.09, well within our 2011 guidance range. Second half weather in 2010 was $0.26 favorable, so weather will make for a tough comparison for the second half of 2011. We have, however, gotten off to a good start with about a $0.05 positive pick up in weather for the month of July, and August is predicted to be very warm as well. The positive weather variances will help us preserve costs for removal flexibility for 2012, the final year of our settlement agreement in Florida.

On O&M last year, we had 109 nuclear outage days with lengthy downtime at Robinson and the plant refueling and maintenance outage at Harris. We do not have any plant outages in the second half of this year, and this should result in lower O&M costs when compared to last year. And finally, we will continue to utilize the cost for removal amortization that we have in Florida. So all in all, we expect to deliver ongoing results in our guidance range of $3.20, though before I turn it back over to Bill for questions, let me just note that the substantial integration, planning and regulatory work related to the merger with Duke has not impacted our focus on execution and delivering results. Our nuclear performance has shown significant improvement, the regulatory flexibility in Florida continues to help offset significant weather variances, and we are carefully and deliberately addressing our challenges at Crystal River 3. Consistency in performance is what you have come to expect, but it is especially noteworthy in light of the significant merger activities. So now I'll turn it back over to Bill for questions and answers.

William Johnson

Thanks, Mark. Before we take your questions, please turn to Slide 18. We remain focused on the fundamentals to excel our core mission of serving customers and to achieve our 2011 earnings targets. And we're following through on our major projects and initiatives. I'm very pleased with the commitment of our management team and workforce, and I want to say a particular thank you to our employees who are doing a superb job of maintaining a reliable system during this summer's extraordinary heatwave. And now we'll be glad to take your questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll go ahead and take our first question from Daniel Eggers of Credit Suisse.

Dan Eggers - Crédit Suisse AG

I guess, first question, Bill, kind of just thinking about the generation dispatch behavior. As you guys think about the CSAPR rules forcing less run time. Is that potentially going to affect the fuel savings you guys anticipate out of the merger if the coal plants can't run as well as, or as much as you might have anticipated going into the merger?

William Johnson

No, Dan, I don't think it will. It will make it more complicated. And I have to say that the CSAPR is -- the ink is still wet on that final rule, so I don't think we understand it entirely. But I think given the size of the fleet, your ability to arbitrize the different coal costs, and just a general efficiency that come with the merger, I don't think we'll have a significant impact on that joint-dispatch in fuel savings.

Dan Eggers - Crédit Suisse AG

So that part holds up then. Okay. And then, the -- I guess the nature of you kind of getting comfortable with CSAPR and that sort of thing, when do you expect to have an updated plan and maybe thoughts on additional CapEx or replacement generation relative in environmental spend?

William Johnson

Very good question. You know one of the things that -- you have to think about these rules, sort of in conjunction. And so, we'd like to see the final MACT rule before we have great clarity about it. We expect by the end of the year, we'll have more clarity on what the capital requirements will be and what the plan looks like.

Dan Eggers - Crédit Suisse AG

And I know that you -- as you said the ink is still wet, but a lot of folks seem to all be expecting to buy credits out in the market to run their coal plants in the next couple of years. Have you guys on the analytics to figure out the credits are going to be in enough surplus to be able to buy them to keep the liability in the appropriate level?

William Johnson

You've asked a great question, in which I don't think anybody has the answer to yet, which is the way the trading regime is broken out between various groups, it's still a little hard to tell what the liquidity will be, what the price will be in those allowance markets. So I think there's still quite a bit of work there to understand that, and again, we should have more clarity, I think, on that, probably by the next quarterly call.

Dan Eggers - Crédit Suisse AG

Okay. I guess just one last question just on -- and, Mark, you got into a bit, so maybe a little more color on customer usage patterns. Is this -- as you guys kind of survey users, is this an economy issue? Is this an efficiency issue? You guys have a better handle on what's really affecting the underlying amount of power being consumed at the house or the business?

William Johnson

Yes, Dan. What I would say is, it's hard to really get a handle on -- exactly what's driving some of this, but there is no question, there's probably some small impact from energy efficiency in some of the programs we have. I think there's no doubt about that, but I would say that the growth -- when you click at our forecast compared to what's actually happening, we haven't seen customer growth return in any meaningful way, especially in the Carolinas, where it's kind of leveling out here. So I would say that the general economy is troublesome. And as I said in my comments about the industrial customers, I think, demand has slowed so inventories are building, and I think it's just -- it's going to be a long slug here, I think.

Operator

And we'll take our next question from Gordon Howald with East Shore Partners.

Gordon Howald - East Shore Partners, Inc.

There's been a lot of focus on coal-fired generation now that the EPA, obviously, has coal in its crosshairs, but there hasn't been a lot of discussion about oil-fired generation. I mean you mentioned it briefly here earlier, and then Dan has a question that kind of got on there. I recognize the ink's not dry yet on the new rules and the impacts, but a lot of your oil fleets, specifically Progress, doesn't run often, but some plants like Henkel, for example in Florida is an important plant. I have 2 questions if I could on this. What approach do you believe you'll be taking towards your remaining oil fleet. And second question, how do you believe EPA regulations overall will impact oil-fired generation? How much of an impact do you believe that it's going to have on the power markets overall?

William Johnson

Good question. There's not that much oil-fired generation in the country. It's a very small percentage, I think. So I wouldn't expect it would have a big impact on power prices, unless you're uniquely situated in a certain market where it's crucial that you run. But in general, I don't think it's a big impact in the wholesale markets. For us, you're exactly right, we do have some oil in Florida. We reduced that substantially when we converted Bartow toward natural gas. You have several options here. The oil plants really haven't been heavily implicated by the EPA regulations until you got to the CSAPR rule. I think that's drawing a beat on the oil plants. So you can try to control them. We do have dual-fuel capability at Anclote, so we can convert to natural gas and get off oil there. Or you can build replacement capacity. So the dual-fuel capability at Anclote will be a big help to us, I think, and help us solve some of the CSAPR problems. It's a little too early exactly to know what the option we will take is, but those are the general options.

Gordon Howald - East Shore Partners, Inc.

And how much does that -- would that plan derate if you were to convert it over to natural gas? Any rough estimates?

William Johnson

You've exceeded the level of my operational knowledge with that, but if you call our IR folks later, they can probably give you a guess on that.

Operator

And we'll go to our next question from Jonathan Arnold with Deutsche Bank.

Jonathan Arnold - Deutsche Bank AG

I apologize if I missed this, but did you give any update on this, on the kind of NEIL situation as to whether the Crystal River 3 event will count as 1 or 2 events. So is that -- I think, when you had your call in June you said you thought you might have some more color on that by the time of this call.

William Johnson

The update we gave was that we continue to work with NEIL to get appropriate replacement and repair coverage. And I would say about the process, I think that everybody involved is working diligently, doing what they're supposed to be doing, mindful of their responsibilities here. This would be a big claim. NEIL has to approach this carefully, because they have an obligation to us and all their other members. So I would say, the process is working about the way you would expect. We don't have any more substantive update other than to say that everybody is working on this.

Jonathan Arnold - Deutsche Bank AG

And timing when you might -- when there might be an overcome there?

William Johnson

I don't think I can hazard a specific guess on that.

Jonathan Arnold - Deutsche Bank AG

Okay. And then the other thing, back in June you'd said you might have a clearer line of sight on -- what you would do about the uprate while this repair is going on. Any new color on that?

William Johnson

No. We're still considering that in conjunction with the procedural schedule that we have in Florida. There are a lot of dockets that touch the uprate and other parts of nuclear, and then you overlay essentially a prudent schedule on top of that. So, really, those things are all combined until we have clarity on one, we're probably not going to have clarity on the other.

Operator

And we'll go to our next question from Greg Gordon with the ISI Group.

Greg Gordon - ISI Group Inc.

So 2 quick question. One is, I mean, if I look at your -- the slide where you give earnings drivers for the second half, is it fair to presume that assuming you don't fully catch up on whether, that you got these positive comps on cost of removal being $134 million versus $50 million, having no outage days versus over $100 million, and so those are kind of the balancing mechanisms that get to your guidance range.

William Johnson

That's exactly right.

Mark Mulhern

And I'll also add to that, just a good old-fashioned managing your business and watching your O&M and doing everything you can to make those earnings numbers.

Greg Gordon - ISI Group Inc.

Fair enough. Second question, can you explain the $0.09-charge in a little more detail as it explains -- as it pertains to your replacement power costs? Because you do have $500 million of expected replacement power costs that will be incurred outside the balance of your current insurance coverage, and this is clearly just a very small fraction of that. So why are you compelled under the accounting rules to take a reserve for this amount, which is I think is less than $50 million relative to the entire sort of exposure outside the insurance coverage.

William Johnson

Greg, we have a little history here. We had a settlement agreement with the joint owners at Crystal River related to an item a few years ago that included a certain capacity factor and therefore, an obligation by us to kind of, to meet that, to indemnify them if we fell below those things. That agreement runs through 2013, and so when we go forward and project that liability today, knowing that the plant will not be in service before the end of 2013, we're required under the accounting rules to book that liability when we know that liability. Which is what happened to us in the second quarter when we went through the estimation of what the repair plan would be and the return to service in 2014. We had to book the liability for the joint owners of the facility, the indemnification obligation under that agreement. That's really the requirement.

Greg Gordon - ISI Group Inc.

Okay. So that's separate and independent exercise from the conversations you'll have at the PSC regarding replacement power costs outside of those coverage?

William Johnson

Correct.

Operator

And we'll take our next question from Jim van Riesemann with UBS.

James von Riesemann - UBS Investment Bank

I wanted to touch base with you on your merger partner, and their interest in Santee Cooper. How do you feel about that? And how do you feel about taking an interest yourself, or a separate interest?

William Johnson

Yes. I'll only speak to our interest in that and not theirs, if I could ask a favor. We've said publicly that regional nuclear is the way to go. We continue to believe that new nuclear is important to future energy supplies and future environmental standards. We continue to talk to the folks in South Carolina about this possibility and it's a potential, but we haven't reached any conclusions yet, so I think we're about where we were last time we talked.

James von Riesemann - UBS Investment Bank

Okay. Can you just provide any color on what you think the North Carolina legislature might do in the spring? Not to pull a pin out of a hand grenade.

William Johnson

Just given -- no, I don't think I can. This is obviously -- you're referring to the Quip legislation and the importance of that, and we will be making the pitch there, the importance of this. So, we'll be working on that topic. What they will do I think is hard to predict. And that's an understatement.

Operator

And we'll go to our next question from Mark Sigal with Canaccord.

Mark Sigal - Canaccord Genuity

I was just wondering if you could expand a little bit on the commentary on Slide 10, regarding Smart Grid activity to date, and perhaps talk a bit about your plans for the future.

William Johnson

Sure. We started in Smart Grid, actually, in Smart Appliances many years ago and the Escape and those sort of things, but recently, we have been the recipient of a DOE grant, that supplemented a program that we were already implementing. So our focus today, in general, is on the voltage regulation. We made the choice that when we talk about Smart Grid, we were going to start making our part of the grid smarter and work toward the customer. So, we are essentially doing demand-side voltage management, is a way to think about, which allows you to run your system more efficiently, and avoid building capacity on peak. That's going to be the focus probably for the next couple of years. We're doing some meter replacement with large industrials and those kind of things. But for the couple of years, it's really demand-side voltage management, and then we will reevaluate and look at where the meter technology is, where the appetite from the customer for meters is, and those kinds of things. But at the moment, the focus is on using those grant funds wisely, complying with the conditions and actually making Smart Grid investments that have a value proposition to all the stakeholders.

Mark Sigal - Canaccord Genuity

Okay. And the metering phase comes 12 to 24 for months out?

William Johnson

I think it's probably out a little further than that. So I would say after 24 months. We're actively looking at that. We keep up with it. But we think what we're doing now has a higher value proposition than the meters.

Operator

[Operator Instructions] And we'll go to our next question from Raymond Leung with Goldman Sachs.

Raymond Leung - Goldman Sachs Group Inc.

Can you talk a little bit about -- it looks like you have some maturities coming up and how you in finance -- Can you talk about how you may potentially deal with that given current interest rates and sort of, maybe any financing plans for the balance of the year?

Mark Mulhern

Sure Ray. This is Mark. We have -- we just had a maturity at PES come due that we actually funded in the short term. TP markets will ultimately replace that and term it out here. Second half of the year, we've just lined it up with some of our regulatory filings and making sure we had a clean slate here, so we will do that. We also -- will likely have an issuance at PEC sometime in the second half of the year to -- and it is consistent with our plans around the construction of the new combined-cycle gas facilities in Carolinas. So those would be the 2 that I will between now and the end of the year specifically.

Operator

At this time there are no other questions. Thank you. I'll go ahead and turn the call back over to Mr. Johnson for any additional request or remarks.

William Johnson

Thanks, Kelly. And thanks to all of you for being on the call. Thanks for your questions and for your interest in Progress Energy.

Operator

And that does conclude today's conference. We thank you for your participation.

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