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Pepco Holdings (NYSE:POM)

Q2 2011 Earnings Call

August 05, 2011 11:00 am ET

Executives

David Velazquez - Executive Vice President of Power Delivery

Anthony Kamerick - Chief Financial Officer, Senior Vice President, Chief Financial Officer of Potomac Electric Power Company, Chief Financial Officer of Delmarva Power and Light Company, Chief Financial Officer of Atlantic City Electric Company, Senior Vice President of Potomac Electric Power Company and Senior Vice President of Delmarva Power and Light Company

John Huffman - Chief Executive Officer of Pepco Energy Services Inc and President of Pepco Energy Services Inc

Donna Kinzel - Vice President of Investor Relations

Joseph Rigby - Chairman, Chief Executive Officer, President and Member of Executive Committee

Analysts

James Krapfel - Morningstar Inc.

Dan Eggers - Crédit Suisse AG

Paul Ridzon - KeyBanc Capital Markets Inc.

Paul Patterson - Glenrock Associates

Justin McCann - S&P Equity Research

Ali Agha - SunTrust Robinson Humphrey, Inc.

James Dobson - Wunderlich Securities Inc.

Operator

Good day, ladies and gentlemen, and welcome to the Second Quarter 2011 Pepco Holdings Incorporated Earnings Call. My name is Modesta and I will be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Donna Kinzel, Vice President, Investor Relations. Please proceed, ma'am.

Donna Kinzel

Thank you, Modesta, and good morning, ladies and gentlemen. Welcome to the Pepco Holdings Second Quarter 2011 Earnings Conference Call. The primary speakers on today's call are Joe Rigby, Chairman, President and Chief Executive Officer; and Tony Kamerick, Senior Vice President and Chief Financial Officer. Also available to answer your questions are Dave Velazquez, Executive Vice President, Power Delivery; and John Huffman, President and Chief Executive Officer of Pepco Energy Services. On today's call, we will be referring to slides which are available on the Investor Relations section of our website.

Before Joe begins, let me remind you that some of the comments made during today's conference call may be considered forward-looking statements. As such, they should be taken in the context of the risks and uncertainties discussed in the Safe Harbor disclosures contained in our Securities and Exchange Commission filings and found on Slide 2 of our presentation.

Please note that the earnings release can be found on our website at www.pepcoholdings.com/investors. Joe?

Joseph Rigby

Thanks, Donna, and good morning, ladies and gentlemen and thank you for joining us today. Earnings from continuing operations for the quarter were $95 million compared to $76 million in the 2010 quarter. Our operating results were driven by the positive impact of our infrastructure investments and reasonable regulatory outcomes, lower interest expense and income tax adjustments. Our results for both 2011 and 2010 quarters reflect Conectiv Energy's results as discontinued operations. Tony will discuss the financial results and our operating segment performance in more detail but first I'll address some topics of interest, starting with an update on our initiatives to improve system reliability as shown on Slide 3. We continue to make good progress in advancing infrastructure improvements and performing system maintenance in the Pepco region that will reduce power outages and improve service for our customers. Since launching our Reliability Enhancement Plan last fall, we have trimmed trees along more than 2,200 miles of power lines in our service territories, replaced or upgraded more than 150 miles of underground cable and identified overhead lines for undergrounding, among other efforts. We also have made several enhancements to improve customer communications during major storms, such as increasing call center staff and phone system capability and enabling outage maps to be viewed on smartphones. Our Reliability Enhancement Plan is on track and we are beginning to see positive trends in the operating performance of our electric system. Improving system reliability will remain a top priority for our company. As we are making progress in advancing our Reliability Enhancement Plan, we are continuing to dialogue with our regulators regarding system reliability and standards. In Maryland, the proceeding initiated in August 2010 to investigate the reliability of Pepco's distribution system is progressing. Hearings were completed in June and initial briefs were filed on July 20 with reply briefs due on August 8. Certain parties to the case have recommended the imposition of a variety of sanctions in various reporting requirements. As I've stated, we are committed to improving the reliability of Pepco's electric service. However, while we cannot predict the outcome of this case, we will oppose the sanctions requested by the other parties which we believe are not supported by the record.

Also in Maryland, the commission has commenced a rule-making to establish reliability benchmarks applicable to all electric utilities in the states. The proceeding involves all of Maryland electric utilities, the commission staff, People's Counsel and other interested parties. We are participants in the process and support the development of objective-fair standards with reasonable penalties. In the District of Columbia, the commission has recently has adopted new reliability standards. The new rules require improvements in reliability performance on an annual basis beginning in 2013 and continuing through 2020. Again, we support objective-fair standards, but we believe the regulations in their current form are flawed because they propose an inconsistent method to calculate reliability. Furthermore, while we are in the process of evaluating the cost and operational changes necessary to comply with the new requirements, we currently believe the standards as adopted may not be realistically achievable at an acceptable cost over the longer term. As a result, we intend to file an application for reconsideration of the regulations with the commission shortly.

We continue to make progress on our Blueprint for the Future initiatives. Status by jurisdiction can be seen on Slide 4. The advanced meter installation for electric customers is largely complete in Delaware with 305,000 meters deployed, about 98% of the total. Of the installed meters, 273,000 have been activated and we plan to have the remainder activated by the end of the third quarter. The initial functionality includes remote meter reading, the availability of account-specific energy use information and outage detection. In the District of Columbia, 102,000 advanced meters have been installed, about 38% of the total, with the goal of having the installations completed by the end of 2011. In June, we began installing advanced meters for Pepco customers in Maryland and expect to have the installations completed by the end of 2012. The commissions in Delaware, the District of Columbia and Maryland have approved the establishment of a regulatory asset to defer AMI-related costs and the accrual of returns at the authorized rates of return on the deferred cost until such time as the cost and accrued returns can be incorporated in customer rates.

Proposals are pending in Delaware and the District of Columbia that request permission to implement a dynamic pricing plan for customers. Under the proposed critical peak rebate structure, the plans would reward Standard Offer Service customers for lowering their energy use during critical peak periods when energy demand and the cost of supply and electricity are higher. Decisions on the proposal are expected by year end. This Critical Peak Rebate structure has been approved in concept in Maryland, and the tariff details are currently being developed by a working group. Subject to approval, the phase-in implementation for residential customers in Delaware, the District of Columbia and Pepco Maryland's customers is targeted to begin in 2012 and continuing to 2013. Through the build out of the Smart Grid, we will gain added tools to improve system reliability while providing customers with access to detailed usage information that will enable them to better manage their energy use and lower their energy bills. Our energy efficiency and demand side management programs will also help our customers to reduce energy costs. The cost of these programs is being recovered through our demand side management-related rate adjustment mechanisms.

Turning to our regulatory filings in June, the Delaware Commission approved the settlement agreement in Delmarva Power's natural gas delivery base rate case. As seen on Slide 5, the commission granted an annual rate increase of $6 million based on a stated return on equity of 10%. The parties to the settlement agreed to defer the request to place revenue decoupling into effect until an implementation plan has been developed. While the new rates were effective July 1, keep in mind that as permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5 million on August 31, 2010, and $7.7 million on February 2, 2011. The amount collected in excess of the approved rates will be returned to customers. On July 8, the Maryland Commission approved the settlement agreement in Delmarva Power's electric base rate case. As seen on Slide 6, the commission granted an annual rate increase of $12 million. The new rates became effective on July 8. Although the return on equity was not specified in the proposed settlement, the commission authorized a return on equity of 10% for purposes of calculating the allowance for funds used during construction and regulatory asset carrying cost. The commission also authorized a Phase 2 proceeding during which a working group, including Delmarva Power, commission staff and the People's Counsel will explore methods to address the issue of regulatory lag. Our objective in this process is to gain a consensus of the working group regarding the adoption of one or more mechanisms that will reduce regulatory lag and file a proposal with the commission that is supported by all parties. If consensus cannot be reached, each party can file its own proposal with the commission. Phase 2 proceeding has a 100-day term, which commenced on July 8. Delmarva Power is preparing to file a rate case in Maryland this fall in order to continue its efforts to close the gap between its earned and authorized return. This case will request commission approval for any proposals to reduce regulatory lag that are developed in the Phase 2 proceeding. As I've noted previously, reducing regulatory lag is a significant focus. Our preference is to achieve this by adopting mechanisms that negate the need for frequent rate cases, which we view as costly and inefficient. However, we have a deep and experienced regulatory staff that can execute a regulatory strategy that includes frequent cases if need be in order to earn returns close to what the commission has authorized.

Turning to Slide 7. On July 8, Pepco filed a rate case in the District of Columbia requesting an annual revenue increase of $42 million based on a return on equity of 10.75%. Of the requested $42 million increase, approximately $10 million relates to AMI-related cost. Since we have generally been earning a return on these costs since they were incurred, recovery of the cost through rates has a positive cash flow impact but does not affect earnings. Like Delmarva Power's filing in Maryland, this filing includes a comprehensive discussion on the topic of regulatory lag and its negative effects. The filing requests approval of a reliability investment recovery mechanism, which provides full and timely recovery of future capital investments related to distribution system reliability. The filing also requests the commission adopt fully forecasted test periods. The prehearing conference has been scheduled for September 8, a decision is expected in April 2012. We remain on track with our preparations to file 4 additional rate cases later this year. As shown on Slide 8, Atlantic City Electric expects to file a case shortly likely by the end of today. The case will request an annual revenue increase of $59 million based on a return on equity of 10.75%. In September, we plan to make another filing in New Jersey requesting an extension of the current infrastructure investment surcharge to help mitigate the effects of regulatory lag. As I've noted, Delmarva Power plans to file a case in Maryland in the fourth quarter. Also in the fourth quarter, Pepco plans to file a rate case in Maryland and Delmarva Power plans to file an electric rate case in Delaware. Note that this filing schedule is tentative. In each of our jurisdictions, we plan to include in our rate cases or other filings a comprehensive discussion on the topic of regulatory lag and its negative effects as well as proposals to minimize lag. The status of the Mid-Atlantic Power Pathway or MAPP project can be seen on Slide 9. As we have previously reported, PJM is in the annual process of evaluating the region's overall transmission needs. PJM has stated that it expects to complete this evaluation sometime this month. While the PJM process is not yet complete, our expectation is that the MAPP projects' in-service date will be delayed several years beyond the current in-service date of June 2015. We will have further clarity on the revised in-service date when PJM completes its process.

Slide 10 shows the forecasted annual construction expenditures for our Power Delivery initiatives including the MAPP project. Due to the uncertainty of the MAPP projects in-service date, we currently anticipate that the 2011 construction expenditures associated with MAPP may be lower than our forecast due to the deferral of between $90 million to $110 million of MAPP expenditures to later years. However, we also anticipate that approximately $40 million of non-MAPP transmission capital expenditures planned for later years will be incurred in 2011. Once the revised in-service date for the MAPP project has been determined, we will update our 5-year Construction Expenditure Forecast accordingly.

At Pepco Energy Services, the profitable wind down of the Retail Energy Supply business continues to be on track. And we continue to make good progress in growing the Energy Services business. As shown on Slide 11, Pepco Energy Services signed $35 million of new energy efficiency contracts in the second quarter of 2011, including a $28 million energy performance contract with the Maryland Port Administration. This project consists of the installation of a number of energy conservation measures, including renewable energy components as well as building upgrades. Looking ahead, the business development efforts we have undertaken over the past 2 years are showing results, with a prospective project pipeline of nearly $600 million. We believe the benefits of energy efficiency provide long-term growth opportunities for this business and we can grow Pepco Energy Services in a manner that is consistent with our lower risk profile. At this point, let me turn it over to Tony Kamerick. Tony?

Anthony Kamerick

Good morning, and thank you for joining us today. I'll recap our earnings, address our performance by operating segment and discuss some topics of interest. We will then open the call to your questions. Earnings from continuing operations for the second quarter were $95 million or $0.42 per share compared to $76 million or $0.34 per for the second quarter of last year. For the 6 months ended June 30, 2011, earnings from continuing operations were $157 million or $0.69 per share compared to $104 million or $0.47 per share for the 2010 period. Our results show Conectiv Energy's results as continuing operations. For the 6 months ended June 30, 2011, income from discontinued operations, net of taxes, is $1 million. This includes income from adjustments to accrued expenses in connection with the sale of the generation assets, partially offset by losses from the disposition of Conectiv Energy's remaining assets and businesses. A summary of the drivers of our financial results can be found on Slides 12 and 13. In the fourth quarter of last year, we reached a settlement with the IRS for the tax years 2001 and 2002, which affected our tax returns as far back as 1996. In June, we reached an agreement with the IRS with respect to the interest due on the tax liabilities related to that settlement. In the second quarter of 2011, we recorded a tax benefit of $17 million or $0.08 per share primarily related to this agreement. About half of the tax benefit affects the Power Delivery segment with the balance affecting the other nonregulated segment. Our earnings guidance includes a range of tax benefits for the expected resolution of pending tax matters. Tax years 2003 and beyond are still open with the IRS, and the IRS is in the process of examining several large industry issues such as the treatment of mixed service costs and repair deductions. Until the IRS becomes more current with its audits and these industry issues are resolved, we can expect some level of tax adjustments in our results.

For the second quarter, Power Delivery earnings were $0.32 per share compared to $0.29 per share for the 2010 quarter. In addition to the tax benefit from the settlement with the IRS that I just discussed, higher distribution rates and default service margins positively affected earnings quarter-over-quarter. Higher distribution rates during the quarter increased earnings by $0.02 per share. The higher rates reflect the impact of electric rate decisions for Pepco in Maryland and Atlantic City Electric. The higher rates also reflect the interim rates put in place for Delmarva Power's gas business in Delaware. These rate increases were driven by higher costs and increased investment and distribution assets to enhance reliability. Higher default electricity supply margins during the quarter positively impacted earnings by $0.03 per share. About half of this increase is due to an increase in Pepco's cost recovery rate in the District of Columbia to recover higher cash working capital costs. The other half of the increase is due to an adjustment to Delmarva Power's operation and maintenance expense for providing default service in Delaware.

Partially offsetting these increases was higher operation and maintenance expense, which reduced earnings by $0.06 per share. The expense increase was driven by higher tree trimming and preventive maintenance costs, as well as emergency restoration expenditures. Lower weather-related sales versus the prior year decreased quarterly earnings by $0.01 per share. Cooling degree days decreased by 15% quarter-over-quarter. The weather for the quarter versus normal weather had no impact on the earnings. Keep in mind that our distribution revenue in Maryland and the District of Columbia, which represents approximately 2/3 of total distribution revenue is decoupled from consumption. Year-to-date, Power Delivery earnings were $0.53 per share in 2011 compared to $0.38 per share for the 6 months ended June 30, 2010. The increase in earnings was the result of higher distribution and transmission revenue due to higher rates, higher default electricity supply margins and favorable income tax adjustments. Partially offsetting the earnings increases was higher Power Delivery operation and maintenance expense. At our analyst conference in April, we provided a forecast of total O&M for Power Delivery of $818 million in 2011. We now expect O&M to be approximately $850 million with additional maintenance expense and tree trimming driving the increase. This level of O&M spending is contemplated in our earnings guidance range.

Pepco Energy Services' second quarter earnings were $0.03 per share compared to $0.05 per share for the 2010 quarter. Year-to-date, earnings were $0.08 per share compared to $0.11 per share for the six-month period ended June 2010. The decrease in earnings for both the quarter and year-to-date periods was due to lower retail electricity sales volumes resulting from the ongoing wind down of the Retail Energy Supply business partially offset by higher construction revenue. Note that the second quarter includes $2 million of net mark-to-market losses compared to $1 million of net mark-to-market gains for the 2010 quarter. For the 6 months ended June 2011, mark-to-market losses were $4 million as compared to losses of $1 million in the 2010 period.

In our other nonregulated segment, second quarter earnings were $0.08 per share compared to $0.03 per share in the 2010 quarter. Year-to-date earnings were $0.11 per share compared to $0.05 per share for the 6 months ended June 2010. The increase in earnings for both the quarter and year-to-date periods was primarily due to the tax benefit resulting from the settlement with the IRS for prior tax years, which I addressed earlier and the early termination of certain cross-border energy leases, which I will discuss in more detail shortly.

In our corporate and other segment which is primarily unallocated corporate costs, earnings improved for both the 2011 quarter and year-to-date periods compared to the same periods in the prior year. The earnings improvement resulted from lower interest expense due to lower parent company debt outstanding partially offset by the effect of favorable income tax adjustments in 2010.

Returning to the subject of the cross-border energy leases, as shown on Slide 14, in 2011, Pepco Holdings entered into early termination agreements for a number of leases in the portfolio at the request of the lessees. The lease terminations involved all of the leases comprising 1 of the 8 cross-border lease investments and a small portion of the leases comprising a second lease investment. Pepco Holdings received net proceeds of $161 million and recorded an after-tax gain of $3 million upon the termination. While the pretax gain was $39 million, in addition to the $14 million tax expense on the gain, $22 million of income tax benefits recognized previously were reversed in connection with the termination of the leases. The book value of the lease investment portfolio as of June 30, 2011, was $1.3 billion. As seen on Slide 15, the current annual tax benefits from the remaining cross-border energy lease investments are approximately $52 million and the annual net earnings are approximately $21 million. For the current status of our dispute with the IRS regarding the tax benefits of the leases, earlier this year, PHI paid $74 million of additional tax associated with the disallowance deductions from the lease investments in connection with the audits of the 2001 and 2002 tax years, plus penalties of $1 million and subsequent interest of $28 million.

Last month, we filed a claim for refund with the IRS, which we expect the IRS to deny. And if so, we intend to pursue litigation in the U.S. Court of Federal Claims against the IRS seeking to recover the tax payment, interest and penalties. Now I'll turn to our recent financing activity, which is summarized on Slide 16. In May, Delmarva Power repurchased approximately $35 million of 4.9% tax-exempt bonds due 2026, pursuant to a mandatory repurchase obligation triggered by the expiration of the original interest period. On June 1, the bonds were resold with the new interest rate of 0.75%. The bonds are subject to mandatory repurchase by Delmarva Power on June 1, 2012. PHI and utility subsidiaries maintain an unsecured syndicated credit facility to provide for short-term liquidity needs. On August 1, PHI and the utilities entered into an amendment and restated credit agreement to extend the expiration date of the facility from May 2012 to August 2016 and to include various enhancements to the terms and conditions of the facility. The aggregate borrowing limit under the credit facility remains $1.5 billion.

Turning to our earnings guidance as seen on Slide 17, we are reaffirming our 2011 guidance range of $1.10 to $1.25 per share. However, given year-to-date results and our expectations for the remainder of the year, we currently anticipate being above the midpoint of that range. We will address the guidance range on the third quarter earnings call when we have more clarity on the resolution of certain tax matters. Now let me turn it back to Joe Rigby for some closing remarks.

Joseph Rigby

Thanks, Tony. In closing, we remain focused on our strategy to invest in utility infrastructure and seek timely and reasonable regulatory outcomes. We remain committed to our dividend and we continue to make good progress on our strategic initiatives that position us to provide value to our customers and our investors. And with that, we'd like to open the call to your questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question today comes from the line of Paul Patterson with Glenrock Associates.

Paul Patterson - Glenrock Associates

Just to go over Slide 12 for a second, I see the $0.08 for income tax adjustments. And then I guess there's a negative $0.02 that's associated with other income tax adjustments. Are those similar in that they are sort of lumpy, is that the way to think of that or what's that about?

Joseph Rigby

I'm not sure what you mean by lumpy, exactly.

Paul Patterson - Glenrock Associates

Okay. Well, in other words, I mean, they are not proratable. In other words, these are periodic adjustments that are being made as opposed to some long-term income tax adjustments that's going to flow through the income statement on a more regular basis.

Anthony Kamerick

This is Tony. Yes. The answer to that is yes. As we've said, as we work our way through these numerous audits, it is going to be somewhat lumpy.

Paul Patterson - Glenrock Associates

Okay. And then there's an $0.08 per net interest expense. And what was causing that to be so much of a benefit this quarter over the last?

Anthony Kamerick

Well it mostly relates to the major buy down of debt that we did last year from the proceeds from the generation sale.

Paul Patterson - Glenrock Associates

Okay. And then, so in guidance, just to make sure I understand it. The $0.08 or $0.06, I don't know exactly how to look at it, that is included in your guidance, correct?

Anthony Kamerick

The answer, again, this is Tony, the answer is when we do our guidance, Paul, we would include obviously what we know of so far. And we would also include a range of resolution estimates on other issues.

Paul Patterson - Glenrock Associates

Okay. So what should we expect to happen with respect to the range? I guess are you expecting some of these income tax situations to reverse this year or how should we think about that?

Anthony Kamerick

I'm not sure what you mean by reverse.

Paul Patterson - Glenrock Associates

Well, I mean, I guess what I'm wondering is, how much of an income tax benefit, we're seeing $0.08 or maybe $0.06, I guess, for this year associated with income tax adjustment -- this quarter, excuse me -- associated with income tax adjustments. Is that going to -- do you think that might go down or go up going forward throughout the rest of the year?

Anthony Kamerick

Paul, I think the best way that I can respond to you is to refer you back to the statement we made in the script which is we expect to be in the upper part of the guidance range that we've provided. We are including in our range of result possible outcomes regarding certain tax issues that are still under discussion.

Paul Patterson - Glenrock Associates

Okay. And I guess I'm trying to figure out and perhaps feel comfortable. That's okay if you don't want to elaborate any further, but I guess what I'm wondering is, the further, the additional outcomes that might happen, would those be negative or positive to this income tax adjustment of about this income tax adjustment that we're seeing this quarter?

Anthony Kamerick

I guess I'd say yes. We don't really plan on litigating this with IRS over our earnings call. So what we're trying to do here is present a range for you all to give some kind of guidance on, even the way outliers of possibility. But as we see the year coming out, we believe we'll be in the upper end of the guidance range.

Paul Patterson - Glenrock Associates

Okay. I guess when we get into 2012 guidance, we might want to talk about what might happen year-over-year going forward, I guess. I don't want to pursue it any further, if you guys don't want to. But...

Anthony Kamerick

I guess I would add, Paul, that we're erring on the side of being conservative here by maintaining the range.

Paul Patterson - Glenrock Associates

Okay. Good. The mark-to-market reversal, that's going to be reversed. Is that going to happen -- the timing of the reversal on the mark-to-market, will that be this year or would it be into next year or do you any flavor for how that mark-to-market reversal might take place?

John Huffman

This is John Huffman. The mark-to-market reversal will occur as we deliver the energy associated with those contracts. So again, the majority of the contracts really are delivered by the end of 2012. So we can expect most of that to reverse by that time.

Paul Patterson - Glenrock Associates

Okay. And then the Maryland reliability requirements that you guys are asking for reconsideration on, what happens if they don't reconsider them. I mean, I think what you guys stated in your script was that, that they weren't realistic or that they had cost benefit problems. Could you just give us a little bit more flavor as to what the impact might be if there is no change in their policy?

Joseph Rigby

Paul, this is Joe. First off, the request for reconsideration will be with the District of Columbia.

Paul Patterson - Glenrock Associates

I'm sorry.

Joseph Rigby

That's okay. We're still in the process of discussing through the working group in Maryland. And I think that's coming along okay and it would be premature to try to speculate the outcome. The issue with the district requirements is over time and the further you get into the decade, working your way up the top quartile becomes pretty problematic, given just the nature of the service territory that we have. And we really haven't had a chance to dialogue with the regulators to really look at this, I'll say, from 2015 on to really understand what the true cost implications are. So I'm always kind of remain optimistic that once you get an opportunity to have a full sum discussion, that you'll be able to come to a pretty reasonable outcome. So that's pretty much where we stand at this point.

Paul Patterson - Glenrock Associates

Okay. So should we think about this as perhaps you guys being concerned about what the eventual impact might be from a cost perspective, the perspective to customers or is there something that shareholders are going to be -- could you guys give a flavor or both, how should we think of that?

Joseph Rigby

Let me -- a couple of comments. This is Joe again. I think in the near term and I'd say near term taking us out of the next 3 years or so. We believe that given where we are today from more of a liability that we can achieve those standards. Our view is that the investments that are made to provide reliable service are legitimate costs to be recovered. And so our posture there would not be changed going forward. And therein is where I think we need to have that conversation with the decision-makers so they understand the implications of directionally what their -- not directionally but what they've actually put in this order.

Operator

Your next question comes from the line of Daniel Eggers with Credit Suisse.

Dan Eggers - Crédit Suisse AG

I don't want to belabor this tax issue any more than necessary, but is it fair to assume after you get through the audit issues this year that you have the standard 40% tax rate you're seeing in the past is a good normalized number to be expecting in the future?

Anthony Kamerick

This is Tony. I would say only on incremental issues. We're dealing with right now the 2003 to 2005 tax years. I think I've said a couple of times in the past, until the IRS gets a lot more current than they are on our audits, we're going to see some tax adjustments on an ongoing basis more than likely.

Dan Eggers - Crédit Suisse AG

But those, they're not all bank errors in your favor, though. Correct? In the sense of that, they're not all benefits to you presumably?

Anthony Kamerick

We obviously can't predict that. We do as best we can to be conservative in our accounting on these issues.

Dan Eggers - Crédit Suisse AG

Okay. And then I guess, maybe a bigger picture. Joe, can we talk a little bit about MAPP and kind of the process. It seems like since the Analyst Day, the range of delay outcomes have gotten further into the future. What's kind of getting you to the point where you think that the delay is getting longer, and is this leading to a reevaluation of whether the project is needed at all?

Joseph Rigby

Well, we think the project is needed. We felt that way from day one and we've commented on that many times. We've commented in our ongoing dialogue with PJM. I think that what we tried to do this week and I know that it created, there was a number of questions that came in after we put the Q out is that one, we don't have a definitive answer but our sense is that -- we have a sense that this thing of where it's heading by saying that it's going to maybe move several years out from the current in-service date. So not unlike you, we're waiting to have a definitive answer, which our best view is that it's going to be sometime this month, maybe over the next couple of weeks. So like you, we're kind of in a wait mode but we felt that it was appropriate to indicate that this is going to move back several years as we've just disclosed. Beyond that, I'd be kind of speculating, but what I won't speculate about is our sense that this is a good and necessary project.

Dan Eggers - Crédit Suisse AG

And then I guess from a CapEx perspective, you guys have provided the range of capital spending expectations if it was at 15, 17 or 19 in-service date. Are you still comfortable with kind of that range of CapEx expectations or timing of spending if we were to move to several years in the future, just kind of, to grade what the outflows would look like?

David Velazquez

Dan, this is Dave. I think we're still comfortable with the expenditures we laid out for those various scenarios. Again, as Joe has said, we're not sure of what in-service date we're going to get from PJM. So you could slide that scale, I think, somewhat ratably if the date was in between them or past the end of that period.

Dan Eggers - Crédit Suisse AG

And then I guess, Dave, you guys talked when we first saw the first delay that you guys can find spending to help backfill for some of that lost capital investment. What kind of magnitude are you guys seeing to kind of -- other priority projects that would get in and I assume those are going to be state jurisdictional rather than FERC jurisdictional?

David Velazquez

No, the transmission projects that we would move in would be FERC jurisdictional. We just said earlier in 2011 with some of the delay in the MAPP project, we moved in or in the process of moving in about $45 million of additional transmission projects, which would be FERC jurisdictional, not eligible for the incentive rates, however. And then in the -- over the planning period, depending on how far out MAPP is pushed, at the Analyst Day, we had given estimate of over $200 million of other FERC transmission projects that we would move in. I still think that's a reasonable estimate.

Dan Eggers - Crédit Suisse AG

Okay. And I guess maybe just one last question, as you guys have gone through the rate, several rate cases have gotten down and a whole slug of them coming up. How is the conversation going as far as putting forward new mechanisms to try and get a more timely recovery? Are you guys -- how much feedback are you getting from the commissions and is there any thought of maybe narrowing the list of approaches to get more timely recovery so it's maybe a little more point to the conversation?

Anthony Kamerick

This is Tony. We're really just getting started with this major effort. And I'm not sure what you mean by narrowing the range. In each jurisdiction, we are providing specific proposals and attempting to tailor the approach jurisdiction by jurisdiction. And as far as if you're asking about body language, I -- it's a little too early to tell. We've had some meetings with folks in a couple of jurisdictions and they are listening to us. And we're doing our best to provide information that would help them understand the issue as best we can. So it's a little too early to handicap this process, but I think we're making progress on the educational front.

Operator

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

Paul Ridzon - KeyBanc Capital Markets Inc.

I don't want to beat the dead horse on the tax issue, but is it safe to say that the midpoint of guidance kind of assumed neutrality and then things have gone well, so now you're being more optimistic about where you're -- it ends up?

Anthony Kamerick

Paul,this is Tony. The midpoint of the range is, I wouldn't call that like a point estimate of any particular issue. When we put our guidance range together, we do our best to include a lot of different ranges on items that may vary during the course of the year. I think when I say we believe we'll be in the upper part of the range, that would include these tax items that we've booked so far this year and not a lot further. Did that answer your question?

Paul Ridzon - KeyBanc Capital Markets Inc.

Yes. I think that pretty much answered it.

Operator

[Operator Instructions] Your next question comes from the line of Jay Dobson with Wunderlich Securities.

James Dobson - Wunderlich Securities Inc.

Tony, real quickly. The tax item, and I'm speaking of the $0.08 is cash, it's listed as interest on -- as a cash item that came in, in the quarter?

Anthony Kamerick

No. It is not cash. It's reversal of provisions.

James Dobson - Wunderlich Securities Inc.

Okay. Okay. My humble opinion, you might consider excluding this going forward. I think it would help folks sort of get a better grasp of your ongoing earnings power. But maybe, Joe, if we could switch to Slide 3 in this Reliability Enhancement Plan, and you all at the analyst meeting spent a bunch of time talking and outlining this. I was hoping you could talk about both the capital costs and O&M costs sort of to date and how you see them going forward, sort of executing this plan, and I am making a distinction of this plan versus either in Maryland or DC what you might be forced to do.

Joseph Rigby

It's Joe. Let me take a shot at this, maybe with a broader statement. This plan that we put together is our plan, not necessarily driven from a stated set of reliability expectations or standards. We started this plan actually fully over a year ago and there was not any discussion around what the future standards would be. So what I see happening as we go forward in time is how we kind of think about this plan to make sure it's aligned to the evolving standards that are coming out. And my sense given the progress that we're making is that the level of, the pace of this work is certainly more than adequate, I think, and we really are seeing -- it's been interesting just even in the last calendar month to see the impact period-over-period particularly in the Pepco's service territory. The other comment I'd make, and I'll make a comment about O&M and maybe Dave wants to talk about the CapEx. We've clearly pushed very hard this year on our O&M with the tree trimming. A larger number of contractor contingency or higher level of spend at the call center such that you take the O&M expectation for delivery up from I think it was $810 million to almost $850 million. Now whether that's a, whether that's the spend rate going forward, we're still debating that looking ahead. But the one thing I know is that if I think about the spend that we're making relative to what we see as the right kind of regulatory outcomes, I know we're doing the right things. And we're going to keep doing those right things to drive that level of reliability improvement. But, Dave, I don't know if you want to comment on the CapEx piece of this.

David Velazquez

Yes. This is Dave. We have spent about almost $30 million in CapEx year-to-date on this and expect that we'll be spending in the second half of the year somewhere between $75 million and $100 million of additional capital. Some of the reason for the ramp-up is there's significant amount of work that was engineered and as you'd expect, that's front-running is the engineering, getting the permits for all of the construction. More significant construction would follow in the second half of the year. And as we've said before, if you look at the 5-year plan and the incremental additional capital in both the Pepco territory in both Maryland and the District of Columbia, that represents about in total about another $200 million of incremental capital over the 5-year plan.

Joseph Rigby

This is Joe. I guess one thing to think about is that when we talked about that incremental spend when we come through '11, it's not going to be ratably spent. We're trying to do this as aggressively as we can and to Dave's point, I think you're going to see even a higher level of CapEx, all of which we've contemplated, but I think the good news is that we're being able to move on this even faster.

James Dobson - Wunderlich Securities Inc.

That's great. I appreciate the clarity. But, Dave, do you see that the CapEx sort of going higher as you get -- and I'm only suggesting this thing as much as you're sort of in the throes of this right now. Do you see -- do you need more capital or is your plan sort of rolling forward, you're getting the reliability enhancements you expect in sort of what we're doing. And I'm specifically talking about the capital side, not the O&M. It seems sort of adequate the way you forecasted it.

Joseph Rigby

We are moving as aggressively as we can forward with this plan and then continue to do so. As Joe has said, we're beginning to see benefits of the plan even as we go through the summer storm season. So that's encouraging. I think, too, we fully understand where the CapEx is going to be over the next 5 years. We need to get a little further along in the Maryland reliability standard proceeding to understand exactly where we are, but we are committed and have been spending the money both in capital and O&M to dramatically improving the reliability for our customers.

James Dobson - Wunderlich Securities Inc.

Sure. No. I absolutely appreciate and understand Maryland and DC could potentially move these around. And then, Tony, just lastly, as you've sort of put Joe's and Dave's comments together and think about '12 and I know you haven't given guidance but since you talked about $850 million of O&M, should we think of that as sort of a baseline, I guess I sort of came into the first half of this year thinking 2011 O&M would be high, you guys would work hard and then it might roll a little lower in '12, but I guess I'm sort of feeling based on Joe's comments that maybe that's going to go higher in '12?

David Velazquez

This is Dave. We haven't finalized our budget for 2012 yet, as you would expect. But I would expect that in 2012 there continues to be a high level of O&M expenditures. I think we are, as you go forward, maybe further '13, '14, some of the expenditures in the O&M side may begin to drop a little bit but I think for 2012, we're going to continue to have an increased level spend.

Operator

Your next question comes from the line of Jim Krapfel with MorningStar.

James Krapfel - Morningstar Inc.

I'm just trying to get a sense of the competitive environment in your energy efficiency and services business. When you go into a contract such as the Maryland Port Administration contract that you announced, how many bidders are you encountering and as a related question, how do you see the margins in that business progressing?

John Huffman

This is John Huffman. The number of competitors on any given project, it varies. In Maryland, we typically see, I believe the state of Maryland actually qualifies as those who can do business with state entities and I believe there are 5 competitors that are qualified. So for this project in particular, we competed with 4 others and we were able to win that. Now other states and certainly the federal government, there are different rules. So I mean, I think all told, there are probably, I count 10 to 15 solid competitors on a nationwide basis that we see from time to time. In terms of the margins for our energy performance contracting business, we're seeing margins stay steady really over the last few years in the 20% to 25% range. So we really haven't seen any change up or down in that.

Operator

Your next question comes from the line of Justin McCann with Standard & Poor's.

Justin McCann - S&P Equity Research

Where are we to see the tax benefit to the second quarter earnings of the income statement? Because it shows $21 million extra dollars for this quarter versus a year ago, 36.2% effective rate versus a 30.3% rate. So where is it on the income statement?

Joseph Rigby

It's in the tax provision.

Justin McCann - S&P Equity Research

It's not an income tax expense related, the continuing operations?

Joseph Rigby

If you look at -- it might be best adjusting. If you look at Page 22 of our Q, I think you'll see some of the positives and the negatives. But part of the answer is or the answer is that the tax benefit is being offset by a tax on the leased investments, the termination of the leased investments. So it all comes down to about $36 million but that's got some big pluses and some big minuses.

Operator

Your next question comes from the line of Ali Agha with SunTrust.

Ali Agha - SunTrust Robinson Humphrey, Inc.

I apologize, I joined only a little late so you may have addressed this but with regards to, number one, the MAPP decision you're waiting for from PJM sometime later in August, are you waiting, is there a scenario that you're hearing that would imply PJM saying they just don't need the project, is that one potential scenario, is that not on the table?

David Velazquez

This is Dave. We continue to believe the project is needed and I'm not going to -- I can't predict what PJM is going to do but our feeling is that they will delay the project for several years past the 2015 in-service date.

Ali Agha - SunTrust Robinson Humphrey, Inc.

And so the revision part of '17 or '19, 2017 or '19, your sense now is probably even beyond that time frame?

David Velazquez

I think we're focused at the moment again, we'll know or once we talked to PJM but our estimate where we're focused is on scenarios that reflect the 2019 in-service date or later.

Joseph Rigby

Ali, this is Joe. We did chat about this earlier in the call. We're like everyone else. We're waiting for a definitive answer. But we felt that in terms of our disclosure, that we wanted to kind of give a sense of where this may be heading. Hence the commentary around several years beyond the current in-service date. So beyond that, I think we'd be speculating. What we don't speculate about is what we view as the need for this. But I think we're going to have that answer in the next couple of weeks.

Ali Agha - SunTrust Robinson Humphrey, Inc.

And that comes through a letter from the PJM, as I understand it, not a TEAC meeting but a separate letter straight to you?

David Velazquez

It may -- whether it comes straight to me, we'll find out but we would expect it to be communicated not through a TEAC meeting.

Ali Agha - SunTrust Robinson Humphrey, Inc.

And last question also, can you just remind us the 100-day period for the Phase 2 in Maryland, when would those 100 days, when is that over?

David Velazquez

It started on July 8. I don't have a calendar handy but sometime in mid-October. Yes.

Ali Agha - SunTrust Robinson Humphrey, Inc.

Care to give us an early read or rather not?

Anthony Kamerick

As I said earlier, Ali, this is Tony. We have made good progress we think on the educational element of what we're trying to accomplish.

Operator

Your next question is a follow up from the line of Paul Patterson with Glenrock Associates.

Paul Patterson - Glenrock Associates

I'm not going to ask about taxes, but I am going to follow up on the interest expense. And the reason why is because when I look at the first quarter or I look at year-to-date, it looks like a much larger amount of net interest expense was saved in the second quarter versus 2010 than what I would impute for the first quarter of 2010. And I'm wondering, is that because of the way that debt was paid down or is there something going on that I am missing, maybe I'm just slow, maybe I'm just missing something that's obvious.

Anthony Kamerick

Paul, it's Tony. I cannot think off the top of my head why it wouldn't be more ratable. So you'll have to give me a chance to go back and take a look at that, I guess.

Operator

Our final question today comes from the line of Paul Ridzon with KeyBanc.

Paul Ridzon - KeyBanc Capital Markets Inc.

On the O&M going from $810 million to $850 million, that's about $0.12 of earnings which is pretty much your entire guidance range. What are we seeing besides the tax items that we beat to death? Are there any other positive things going your way?

David Velazquez

Can you repeat the question again? I missed part of it because of the connection.

Paul Ridzon - KeyBanc Capital Markets Inc.

Taking your O&M guidance up to $850 million from $810 million, that's about $0.12 of earnings, which is pretty much your entire guidance range?

David Velazquez

Actually it went from $0.18, the $850 million.

Paul Ridzon - KeyBanc Capital Markets Inc.

Okay. So it's not quite that broad but are there other items besides tax that are moving positively?

David Velazquez

First of all, the taxes are a fairly significant amount as you know. Also this early termination helped to offset it.

Operator

Ladies and gentlemen, that does conclude today's Q&A portion of the call. I would now like to turn it back over to Mr. Joe Rigby for closing remarks.

Joseph Rigby

Thanks, operator, and again I just want to thank you all for joining us and for your interest in PHI and have a great day and have a great weekend. Take care.

Operator

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.

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