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Executives

Paul Evanson – President & CEO

Kirk Oliver – SVP & CFO

Max Kuniansky – Executive Director IR

Analysts

Greg Gordon – Morgan Stanley

Michael Lapides – Goldman Sachs

Reza Hatefi – Decade Capital

Brian Chin – Citigroup

Lasan Johong – RBC Capital Markets

Gregg Orrill – Barclays Capital

Neil Kalton – Wells Fargo Securities

Ivana Ergovic – Jeffries & Co.

Paul Patterson – Glenrock Associates

Chris Ellinghaus – Wellington Shields

Philson Yim – Luminus Management

Danielle Seitz – Dudack Research

Unspecified Analyst – SunTrust Robinson Humphrey

Greg Scheer – Unspecified Company

Ryan Moody – [Ducane Capital]

Unspecified Analyst – Beckett Capital

Allegheny Energy, Inc. (AYE) Q4 2009 Earnings Call February 5, 2010 1:00 PM ET

Operator

Welcome to the Allegheny Energy fourth quarter 2009 financial results conference call. (Operator Instructions) I would now like to turn the conference over to Max Kuniansky, Executive Director, Investor Relations and Corporate Communications. Mr. Kuniansky, please go ahead.

Max Kuniansky

Good afternoon everyone and thanks for joining us. If you have to leave the call before it's over, you can listen to the taped replay. It's available until midnight on February 12 and you can listen to it by telephone, on our website or by podcast.

Some of our statements will be forward-looking. These statements involve risks and uncertainties and are based on currently available information. Actual results may differ significantly from the results and the outlook we discuss today.

Please refer to our earnings news release and our SEC filings regarding factors that may cause actual results to differ from the forward-looking statements made on this call. Our presentation includes some non-GAAP financial measures. On our website, you'll find the reconciliations required under the SEC's Regulation G.

After our prepared remarks, we'll take your questions. We ask that you try to limit your questions to two each, so we have time to get to as many of you as possible. And now let me introduce Paul Evanson, Chairman, President and Chief Executive Officer of Allegheny Energy.

Paul Evanson

Good afternoon everyone and thanks for joining us. For the fourth quarter of 2009 adjusted results were $0.66 per share compared to $0.51 in the prior year. Adjusted net income increased by $26 million. Both segments, regulated operations and merchant generation contributed to the higher quarterly earnings.

This break out of our segments is a little different than in the past, our new segment regulated operations now includes the generation of [inaudible] which is our West Virginia regulated subsidiary as well as transmission and distribution operations in all four states and our transmission expansion projects.

Earnings from these regulated operation nearly doubled in the quarter increasing from $19 million a year ago to $35 million. The improvement was largely due to increased recovery of purchased power cost in Virginia thanks to the settlement approved by the Commission in November, 2008 and higher earnings from transmission expansion projects.

This improvement was achieved despite lower megawatt hour sales which were down 6% from the comparable period last year. Weather was milder than normal, and milder than last year as well contributing to reduced residential usage.

Sales to industrial customers were down 11% continuing the trend we’re seeing throughout 2009. At our merchant generation segment we were hurt by weak demand and low natural gas and power prices. Both natural gas and power prices were down about 30% compared to a year ago.

As a result output was down 22% from last year’s quarter and our supercritical capacity factor dropped to a record low 58% in the quarter. Despite all of this adjusted earnings in the merchant generation business went up by $10 million. Our hedges including the Pennsylvania Polar contract and financial hedges provided substantial protection from the decline in market prices as they have throughout 2009.

And earnings were further bolstered by higher capacity revenues, a gain on the purchase of two hydro facilities, and a tax law change in Pennsylvania. Turning to plant reliability, supercritical availability was 83% in the fourth quarter, down from 91% a year ago. Planned outages were up, we had four planned outage weeks in the quarter as compared to virtually none in the same period a year ago.

Unplanned outages due to equipment problems also hurt availability. For the full year 2009 adjusted earnings per share were $2.33, up slightly from a year ago. Improved cost recovery in Virginia increased revenues from our transmission expansion projects and our favorable power hedges offset the adverse impacts of lower power prices, weak demand and the recession.

While the economy hurt us, we stayed focused on running our business well and we accomplished a lot in many important areas. Let me review some of these achievements with you, first safety. Our performance last year was outstanding on both sides of the business. At Allegheny Power we posted the best safety performance in the history of the company placing us in the top quartile.

And in generation we saw a significant improvement and now rank in the top decile in the industry. Second, we completed our scrubber construction projects on time and under budget. This $1.3 billion investment program added scrubbers to five supercritical units at two sites, Fort Martin and [Hatfield’s]. This will reduce our sulfur dioxide emissions from these plants by more than 95%. Our entire supercritical fleet is now scrubbed.

Third, we focused intently on controlling costs and spending throughout the organization. We succeeded in holding operations and maintenance expenses flat. This is now the fourth year in a row we’ve held O&M flat and we’ve done this while improving most measures of performance and maintaining high marks for customer satisfaction.

Fourth, we maintained our investment grade credit rating and strengthened our financial condition and liquidity positions. We refinanced $843 million of indebtedness, increased our credit facilities and extended maturities and in December we securitized the remaining Fort Martin scrubber costs.

Fifth, we moved forward on our transmission expansion project, the Trans Allegheny Interstate Line or TrAIL,. We remained on schedule for a June, 2011 in service. We have more than 90% of the right away acquired and significant progress has been made on the two substations.

Construction of all segments of the line is underway and we have about half of the tower foundations and around 40% of the towers themselves completed. Our other major transmission project the Potomac Appalachian Transmission Highline project or PATH, however has been delayed. PJM informed us at the end of December that their latest work indicates the line may not be needed in 2014 as planned.

They’ll set a new date when the complete that comprehensive planning process in June. Sixth, we made meaningful progress on a number of regulatory fronts. We settled in both West Virginia and Virginia on our fuel and purchase power recovery costs. We filed a base rate case in West Virginia during 2009. The Commission staff subsequently filed a motion to delay the case to give them more time to understand the tax election that we are planning to make.

This election is the result of the change in federal tax rules that allow us to deduct repair costs previously capitalized. It will create a cash flow benefit of about $120 million this year and as a result we won’t be a cash taxpayer in 2010. We reached agreements with the parties in our case on a procedural schedule that sets evidentiary hearings in early April.

Seven, we launched several energy efficiency and conservation programs in Maryland and Pennsylvania. In Pennsylvania a large portion of our residential program focuses on the installation of smart meters. Our implementation plan was filed with the Public Utility Commission in August 2009 and is still pending approval. We’ll continue to work with the Commission to move this forward in order to meet the requirements of Pennsylvania Act 129.

And eighth and finally, our transmission to market based rates in Pennsylvania continues to go smoothly. Our Pennsylvania utility, West Pen Power has now held four auctions to procure power for the period after rate caps expire at the end of this year. In the most recent West Pen auction held last month, the average retail generation price was $62 per megawatt hour for residential customers.

This includes energy, capacity, gross receipts, taxes, and line losses. We now have two thirds of next year’s residential power under contract. Based on these results residential customers would see an increase of 8.5% in their electric bills in January, 2011.

For small and mid sized non-residential customers the typical increase would be even less, 0.6% and 2.0% respectively assuming similar results in future auctions. So, overall we made substantial progress in a number of fundamental areas in 2009. Before I discuss our 2010 priorities, let me give you an update on the status of our hedging program including the success of our merchant generation unit in the recent polar auction.

As I said on the last quarterly call, by the end of the given year we wanted to have 80% to 90% of the next year’s output hedged, 30% to 50% of the second year, and up to 30% of the third year. As of year-end 2009 we achieved those targets. But we stayed at the low end of these ranges to maintain our leverage to an economic recovery.

Now in the January last month West Pen auction there were seven contracts awarded. Allegheny Energy Supply won three of them to a total of about of 1.25 million megawatt hours. Our Maryland utility Potomac Edison also conducted an auction in January awarding six contracts. Allegheny Energy won one contract for one-half million megawatt hours.

As of today we now have hedged about 82% of our merchant output in 2010, 33% in 2011, and 6% in 2012. Turning now to our priorities for 2010, we are anticipating a slow economic recovery so, maintaining a strong financial position and solid liquidity remains a top priority for us.

And we’ll be vigilant in our efforts to control costs and spending. Our plan is to keep [inaudible] O&M flat marking the fifth consecutive year of no increase in costs, an accomplishment I think few can match. Other priorities include keeping our TrAIL project on schedule for in service in June of next year, resolving our West Virginia base case successfully, complete the sale of our Virginia territory, and keeping our transition to market base rates on track in Pennsylvania.

And of course we’ll continue to monitor closely potential environmental legislation and regulation. With respect to climate change I think the probability of a bill passing this year has been greatly diminished. We’ll also be reviewing any new federal regulations regarding coal combustion byproducts including [fly ash].

If we use predominantly dry landfills to store [fly ash], we have no wet storage facilities of the type that failed at TVA but we do own wet storage facilities of a different design at two our locations, [Pleasance] and [R Paul Smith], and both of these facilities are regularly inspected by state agencies as well independent third parties.

So in closing I’d say 2009 was a tough year. We faced a long and deep recession, that effected our businesses. We experienced low energy prices both current and forward, and we had a capacity auction in May that hit our region sharply. No one can feel good about these developments. But as I indicated earlier, we did make great progress on what we could control.

We focused on keeping in tact the fundamental drivers of long-term value. And we had an array of accomplishments during the year. We’ll continue that focus in 2010. And we remain very well positioned for strong growth when the economy recovers. For example on an unhedged basis a $10 change in realized energy prices in 2011 should increase pre-tax income by approximately $360 million.

And we fully expect that power prices will increase over time. I think you all for your interest and support and now let me turn the call over to Kirk.

Kirk Oliver

Thank you Paul and good afternoon everyone. Today we reported GAAP net income of $109 million for the fourth quarter of 2009 compared to $16 million a year ago. Earnings were $0.64 per share compared to $0.10 in the same period a year ago.

Adjusted earnings for the fourth quarter were $0.66 per share as compared to $0.51 per share for the same period last year. Adjusted earnings exclude net unrealized gains and losses associated with hedging activities and $13 million of expense associated with a [inaudible].

Last year’s adjustments were primarily driven by unrealized losses associated with FTRs. Adjusted pre-tax earnings increased $17 million for the quarter compared to the same period a year ago. I’d like to summarize some of the key factors that drove the increase.

In our merchant generation business for the quarter unhedged net revenues were worse by $76 million. This reflects lower volume, and a reduction in realized energy prices partially offset by a decrease in fuel costs. The decrease in unhedged net revenues was more than offset by a gain of $78 million in power hedge margin which is the difference between our hedges contract price and the estimated market value of the volumes hedged.

An $11 per megawatt hour improvement in the contribution from our power hedges more than offset an $11 decrease in realized energy prices. Merchant generation EBITDA above also includes a $17 million benefit from a gain on the purchase of a hydro facility and the cancellation of a related contract.

You’ll find details on the fourth quarter performance of merchant generation in the appendix. Our regulated operations benefited by [inaudible] due to our 2008 settlement for recovery of Virginia purchased power. In addition we continue to make progress on our transmission expansion projects which increased EBITDA by $14 million quarter over quarter.

Interest expense for the entire company was higher by $19 million, of this amount $9 million was primarily due to the fact that we stopped capitalizing interest costs when the [Hatfield] scrubbers went into service in 2009 and $9 million relates to an increase in average debt outstanding of which $3 million is related to TrAIL [inaudible] recovery.

Depreciation increased by $8 million primarily due to the Hatfield scrubbers being placed in service. In total adjusted pre-tax earnings were $17 million higher than the fourth quarter last year. Our effective tax rate this quarter was 30% which compares to 40% for the same period a year ago. We benefited by $18 million in the fourth quarter 2009 due to a change in the Pennsylvania tax law that will allow us to recover a larger portion of our net operating loss carry forward benefits in future years.

This brings our effective tax rate in at 38% for the full year 2009. Cash flow from operations was $329 million after adjusting for the tender offer premium payment in the quarter. Capital expenditures were $293 million for the quarter, free cash flow netting the securitization proceeds used to fund the Fort Martin scrubbers and project financing for TrAIL, was a positive $185 million for the quarter.

Adjusting for the same items for the full year we had positive free cash flow of $233 million. We’ll go into more detail on 2010 later but we expect an adjusted free cash flow before dividends for 2010 to be between $125 and $175 million.

We’ve completed several financing since our last call, [inaudible] has completed an $86 million securitization, entered into a $110 million revolving credit facility, and repaid $110 million medium term note. In January TrAIL Co. issued $450 million of 4% notes and also entered into a $350 million revolving credit facility.

As a result of these transactions the company’s liquidity profile continues to improve with more than $2 billion of liquidity at year-end. There are no other maturities in 2010 except for securitization amortization.

Now let’s turn to the outlook, as a reminder for the merchant generation business we are providing forward-looking information on hedging, generation output, and other data that will facilitate modeling of the business. For the regulated businesses we’re providing some projections of rate base.

Depreciation and interest expense are shown on a consolidated basis. Our estimates are based on forward power prices at December 31 which were $48 for 2010 at the western hub. Forward prices are subject to highly variable market factors outside of our control and our estimates may change due to fluctuations in those prices and other factors.

We’re presenting our 2009 results and estimated increase or decrease in pre-tax earnings in 2010 over 2009. We’ll now go through the drivers of each of these line items, since our last call we’ve significantly revised our estimates for transmission expansion EBITDA and interest expense which I’ll address shortly.

Moving to slide 41 for merchant generation we estimate 2010 EBITDA to be down slightly from last year. As the following slides will show this is driven by a contraction in the benefit of our power hedges offset by growth in our unhedged energy margin and increased capacity revenues.

Slide 42 summarizes among other things, what we include in unhedged energy margin, the contribution of capacity, other revenues including ancillaries, and operating expenses bringing us down to unhedged EBITDA.

Generation volumes are forecasted using an industry standard dispatch model. Estimates of generation volume are based upon various inputs such as forward commodity prices, estimated costs, and our expected plant outages. We are forecasting a significant increase in our generation volumes in 2010 relative to 2009.

Our 2009 generation volumes were impacted by lower plant dispatch, driven by depressed spot power prices that frequently fell below our cost to generate. For 2010 forward commodity markets imply a recovery of power and gas prices, to levels that return our coal generation dispatch to levels that are more in line with historical results.

For example generation volumes in 2007 and 2008 were both slightly above 34 million megawatt hours. To estimate unhedged energy revenues we start with around the clock pricing at the PJM western hub. We then adjust this price to derive an estimated [bus bar] price at our power plants. The realized energy price is primarily impacted by estimates of basis and shaping.

The basis differential results from transmission constraints between our plants and the western hub. The premium for shaping accounts for the fact that our plants produce more output when prices are higher. The $223 million forecasted increase in unhedged energy margins is primarily due to an increase of $5 per megawatt hour and forecasted realized energy prices and its effect on dispatch, partially offset by increased fuel costs.

Coal expense reflects the forecasted tons of coal burn at our delivered coal price. This includes coal at contracted prices and the estimated delivery cost of our small open coal position. We are estimating an increase in other fuels due to a full year of operations of the Hatfield scrubbers and increased pumping costs at our Bath County station, offset by a decrease in natural gas expense.

The $49 million increase in capacity is due to a $27 per megawatt day increase in capacity prices. Operating expenses primarily O&M and state and local taxes, will increase by about $5 million and are subtracted from unhedged net revenues to get to unhedged EBITDA. So in summary our unhedged EBITDA is better by $269 million primarily due to an increase in generation prices and volume as well as an increase in capacity revenues.

Adjusted EBITDA is calculated on slide 43 by starting with the unhedged EBITDA from the prior slide and adjusting for the impact of our power hedge position. These hedges include financial hedges, our West Pen Polar contract, which expires at the end of 2010 and other marketing contracts. The margin contribution on these hedges has contracted versus 2009 reducing our forecast of adjusted EBITDA by $277 million.

Please note that the average contract price and contract market value include energy, capacity and ancillary services. The contract market value represents the replacement cost of these contracts as of December 31. Moving on to the next slide, we’re showing additional information you might find useful in modeling our merchant generation business.

The generation volume shown on this slide are based upon market information and other factors as of December 31, 2009 and as mentioned earlier will change every time we update our projections as forward market prices and other modeling inputs change.

As previously noted we intend to update this information on a quarterly basis. Coal prices and volumes reflect estimates for delivered coal. Capacity revenues reflect the actual results of PJM auctions including supplemental auction. On this slide we’re providing you with forward market pricing data as of December 31. This data is derived from different sources and is used in our internal modeling.

The coal prices are based on broker estimates and do not include transportation costs and are not necessarily reflective of what we might pay to contract for coal at our plants. Slide 46 provides a high level estimate of merchant generation’s pre-tax income sensitivity to commodity price moves. These are simplified calculations where each sensitivity is derived by holding all other variables constant.

Everything we have shown you up to this point has been as of December 31. Since that time supplies entered into some additional marketing contracts which are summarized here. Moving on to slide 48 utility operations, keep in mind that consistent with our new segment reporting, we are including the regulated generation business of [Mon] power in these results.

Our estimates are virtually the same as our last call. EBITDA for utility operations is estimated to grow by $8 million. Please note here that the West Virginia rate case driver reflects the full amount requested in our case and assumes that the increase is granted mid year. After adjusting for the effect of the Fort Martin securitization that we closed in December and recent adjustments due to supplemental tax information, we’re requesting an annual increase of $106 million, of which about $40 million relates to full recovery of income tax expense.

We expect to incur capital and operating costs in 2010 for Pennsylvania Act 129 and assume these costs will be passed onto customers in an annual adjusted surcharge. We will earn a return on our investment that is expected to increase EBITDA by $11 million. Recovery of securitized interest and depreciation related to the Fort Martin scrubbers and remaining West Pen securitization is being reflected at the EBITDA level.

While this benefits EBITDA it does not effect earnings because there are offsetting impacts in depreciation and interest. Despite additional costs attributable to Fort Martin scrubber operations O&M expenses that are non-formulaically recovered are decreasing by $6 million reflecting the company’s cost reduction efforts.

Finally we have assumed here that the Virginia asset sale closes in the second quarter of 2010 which would reduce EBITDA by $29 million. There will also be offsetting effects of the sale on depreciation, interest and income tax expense. We estimate that after using the proceeds from the sale to reduce debt the net effect of the sale on earnings will be flat year to year.

Slide 49 shows estimated growth in rate base for the utility operations. Please note that these are estimates only and our plans are always subject to change. Not included here are additional transmission investment opportunities that we have identified, some of which will be subject to the PJM planning process.

A portion of these projects would be owned by our utility companies and the remainder by our transmission expansion company. We intend to pursue regulatory approval for pass through of these projects costs. Assuming appropriate cost recovery we expect to invest $600 to $900 million in these projects in 2011 through 2014. Our transmission expansion EBITDA will continue to grow as we invest in the TrAIL and the PATH lines.

TrAIL is expected to be in service in mid 2011 and for purposes of this forecast PATH is assumed to be in service in 2016. We’ve reduced the estimate for our transmission expansion EBITDA primarily because of reduced financing costs that will lower our revenue requirement. Decreased costs are due to lower than previously projected interest rates for TrAIL financing and the movement of estimated PATH capital expenditures to future periods.

We are now projecting Allegheny’s share of spending for the transmission expansion business to be about $380 million for 2010. The rate base in our transmission expansion business is expected to grow to over $1.3 billion by 2014. We collect a return on this business as capital expenditures are made.

At the consolidated level depreciation expense will increase by $47 million in 2010 due primarily to the scrubbers going into service in 2009. Transmission expansion, smart meters installed pursuant to Pennsylvania Act 129 and Fort Martin scrubbers will increase depreciation but will not effect earnings because these items are recovered through formulaic rates.

The outlook for capital expenditures is reflected on slide 53, spending in the merchant generation business is expected to decline now that we have completed the Hatfield scrubbers. And utility operations we expect to spend about $275 million in 2010 through 2011 for investments driven largely by Pennsylvania Act 129 subject to Commission approval.

Moving back to the income statement 2010 current estimated interest expense for transmission is $34 million lower than our last call primarily due to lower interest rates in our TrAIL financing and less financing needs for PATH in 2010. Interest expense changes for transmission expansion will not effect earnings because its recovered in formula rates.

The Hatfield scrubbers have come online and interest that was previously being capitalized will now be expensed. Throughout this presentation we have focused on EBITDA for the three businesses we expect O&M excluding amounts recoverable under formulaic rate making to be flat versus 2009.

Finally while not reflected here, we expect our effective tax rate 2010 to be about the same as our 2009 rate which was 38%. With that I’ll turn the call back over to the operator for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Greg Gordon – Morgan Stanley

Greg Gordon – Morgan Stanley

On slide 54 the other interest driver, is significantly lower than it was in the last presentation, I’m making the assumption that that’s because you’ve got this extra $120 million of cash from this tax collection that’s lowering the amount of debt you have to raise, is that right or is there some other factor.

Kirk Oliver

Yes its basically to cap structure optimization, so we’re paying down debt.

Greg Gordon – Morgan Stanley

And that comes from having a better cash flow position than you had—

Kirk Oliver

A better cash flow position from that and then from deferring some of the PATH CapEx as well.

Greg Gordon – Morgan Stanley

Now also, I know you said to keep to two questions, I have three I hope you don’t mind, the second one is the 36 terawatt hours, I know in the script you talked about having done a dispatch model to get comfortable with that but, I can’t recall the last time that your fleet actually ever got to that level of output so I think there’s a little bit of trepidation amongst investors this morning that that’s an aggressive assumption, can you give some comfort as to why we should feel that that’s achievable.

Kirk Oliver

What happens there is a function of two things, it’s the function of the power price that we expect to realize and it’s a function of the dispatch costs. So if you think back 2008 was a pretty strong year on power price but we had coal piles that were running down so we put in a higher replacement, we don’t bid our accounting costs for coal.

So we bid in a higher economic value for the coal in 2008 and emissions costs were higher as well. Then you get to 2009 and we were bidding in more aggressive and lower costs, something much closer to what our accounting costs are, but power prices were very low and in fact too low to even dispatch on occasion.

And now you get to 2010 and power prices are up a bit so we’re also projecting the dispatch at lower cost for a number of reasons. Some of it coal, some of its emissions, some of it’s the way we’ve adjusted some of the derating of the plants. So we had a little bit lower dispatch costs and a little bit higher expected realized price and that’s what results basically in the output being up.

Paul Evanson

And by the way in 2006 we had close to 38 million megawatt hours, 2007 was 35, 2008 was like 34, 5, so we’ve been at that level or pretty close to is in some prior periods.

Greg Gordon – Morgan Stanley

And you inferred on the transmission front not withstanding the deferral of construction on PATH that there’s $4 to $600 million of potential other projects that could be spent over the next several years that’s not in the current budget, is that correct and can you elaborate on that and what would be the method for getting that firmed up into earnings.

Paul Evanson

Its about $600 to $900 million is our preliminary estimate in projects. They’d be spent in the period 2011 to 2014 and they’re mostly to address reliability and replace aging infrastructure. They really are in two bucket, one bucket is what we think from a preliminary discussion with PJM, that they will be ordering us to build that’s about half of it.

These are non backbone type projects and to the extent that bucket happens it’ll probably be done by our transmission company recovered through the same kind of formula rate. The other half is existing infrastructure within our own AP system. Likely to be constructed again by the regulated utility.

Greg Gordon – Morgan Stanley

And so what we should be, at what point do you think you’ll be giving us an update on whether that is going to, whether those projects are going to be going forward. Is it going to be sort of a lot of little projects or is it going to be one big sort of announcement from PJM. How do we think about that.

Paul Evanson

I think the PJM process as they get approved, we’ll announce them. The next time will be June of this year and the other ones we’ll have to start working on and we also need to, would like to have the same kind of recovery at the state level for the second batch of investments that we have with FERC so I think we’ll be going particularly to Pennsylvania to try to get through some kind of comparable cost recovery formula rates before we start launching into that spending.

But we thought we should make you aware of what the opportunity may be in transmission within our own existing footprint.

Greg Gordon – Morgan Stanley

So the bad news is PATH has got an indeterminate delay but there’s other projects that might slot in in front of PATH that could still be earning accretive.

Paul Evanson

I don’t like that word indeterminate. PJM, these determinations come out of the PJM process which is really a very comprehensive process. They complete it every June annually. In June of 2009 they said PATH had to be ready by 2014. They obviously haven’t done the June 2010 one, but the issue came in Virginia where the staff started saying, well give us your latest update to your comprehensive process. Demands have been coming down or extended out, demand response is there, what do you think is going to happen.

And the estimate that PJM made at the time was that it looks like it will be pushed out which it may well, we don’t know if it’s a year or two or longer but I think what it really needs is that full comprehensive review so we’d expect and hope that coming out of that June process we’ll be able to say definitively when PATH would be constructed, because these aren’t things you just turn on and off as you know.

Operator

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

Michael Lapides – Goldman Sachs

In your guidance for transmission CapEx for 2010 and 2011 can you break out how much is TrAIL versus how much is other.

Kirk Oliver

In 2010 TrAIL is about $250 million and in 2011 its about $50 million.

Michael Lapides – Goldman Sachs

And what’s imbedded in the rest of the transmission CapEx.

Kirk Oliver

There’s other PJM projects of about $74 in 2010 and $30 in 2011, and then there’s the balance of that is PATH, there’s about $30 in each year for PATH.

Michael Lapides – Goldman Sachs

And I assume that’s just siting and engineering and prep work and filing and not actually hard string and wire on PATH.

Kirk Oliver

That’s correct.

Michael Lapides – Goldman Sachs

And your rate case assumption in West Virginia in your guidance.

Paul Evanson

We’ve put in which is I think the only way to do that, what exactly we requested. And what we’ve requested on an annual basis is $106 million so we have $53 million imbedded in the case of which $20 million is the tax issue that Kirk referred to earlier. So there’s $20 tax, $33 everything else leading to the $53 million that’s imbedded in this year’s last half of the year income.

Michael Lapides – Goldman Sachs

And I want to touch on Greg’s question just a little bit on the generation output are you, would your output historically because you referenced some levels of output in 2007 and 2008, was that weighed down by some of the environmental work, so the numbers would have actually, if I go back I think the 08 number was like 34.5 million megawatt hours from some of your key units, really your coal units, was that weighed down at all by the environmental work so that number would have been higher in 08 had the scrubber work not been underway.

Kirk Oliver

No I don’t think it was a big, there was a big impact from that. I think it really is more that we tried to use an economic dispatch approach. So we don’t bid in the coal at the cost, at the weighted average cost of which we’ve acquired the coal. We try to bid it in at what the market value is for coal and emissions, and other things and we were using higher costs back at that time.

If you think back in 2008 our coal piles were going down and forecast for coal prices were going up so we were using a higher value for the coal that we priced into the dispatch. And that’s really what drives it.

Operator

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

Reza Hatefi – Decade Capital

Can you talk about your 11 and 12 hedges ended up being a little lighter than your goals had been, as far as percentage hedge levels, can you talk about why it ended up a little lower or what’s the process and strategy there.

Paul Evanson

It was kind of at the low end of the range. It was within the range but clearly the low end of the range. And we just thought that more opportunity for upside in prices that was in that broad range that we have that we’d come in at the low end, that’s where the judgment came in. We set targets, percentage targets, and within that range we do exercise a little of our own judgment on whether we want to be at the high end or the low end and our sense is we want to be at the low end for awhile.

Reza Hatefi – Decade Capital

And just a follow-up to Greg’s question earlier the generation volumes for 2010 through 2012 they also increased pretty materially about a couple of terawatt hours versus your disclosure in the third quarter presentation, what caused the quick or swift increase in expectations for generation in the last three months or so.

Kirk Oliver

It’s the same phenomenon that causes it if you go back and look at the historical numbers, basically what’s happened since we did the last call is that the forecasted price we received for power went up by about a dollar and the average cost to produce went down by about $2.00 per megawatt hours so you factor that in and you’re plants get dispatched more often.

Reza Hatefi – Decade Capital

And it seemed like your coal hedged prices also went down a buck or two, is this just because of special adjustments in some of these contracts.

Kirk Oliver

Its basically the escalators in the contracts, those contracts have the cost escalation in them and we use different econometric projections to try to estimate what those are going to be so those are estimates of what those costs will be now going forward.

Reza Hatefi – Decade Capital

And if you could confirm these hedged coal prices include transportation of $8 to $10 or something like that.

Kirk Oliver

Yes, they include transportation which you could say on average would be around $8 to $10.

Operator

Your next question comes from the line of Brian Chin – Citigroup

Brian Chin – Citigroup

When it comes to the upcoming first energy [inaudible] transition auction are you planning on trying to bid into that auction from megawatts outside of that territory.

Kirk Oliver

No I don’t believe we are.

Brian Chin – Citigroup

And then when we’re looking at Kern River, on slide 42 you mention that other net revenues includes Kern River, that $85 million in 2010 how much of that rolls off in 2011.

Kirk Oliver

About $30 million. We have the capacity on the pipeline, its just that particular trade rolls off about $30 million.

Brian Chin – Citigroup

So we may want to consider just the replication of that trade when we think about that contract rolling off.

Paul Evanson

We hit a pretty good time when we locked it in before for that period so it would be nice if we could repeat it but I wouldn’t count on it.

Brian Chin – Citigroup

And I think you mentioned in your comments that the PATH line is based on a 2016 [r tep] is that your assumption or is that something that PJM has tentatively told you.

Paul Evanson

That’s what we’ve put in the plan, they have not tentatively told us that.

Operator

Your next question comes from the line of Lasan Johong – RBC Capital Markets

Lasan Johong – RBC Capital Markets

You mentioned that internally you’re on the low end of the hedging portion because you exercised the prerogative to assume there was going to be upside, how much are we talking about in terms of, I’m assuming it relative to the fourth quarter, how much optimism do you have for 11 and 12 above that forward curve.

Paul Evanson

I really couldn’t, I wouldn’t want to pick a number. Its just a feeling that the economy has seen some really tough blows and if I think the forwards are based off of the trough that we’re at although they show a little improvement in PJM west but not a heck of a lot. And its just an evaluation or an expectation that if things pick up we’ll do well and very well and on an unhedged basis we got 36 million megawatt hours out there so every buck means something.

Its just basically a judgment we think there’s more up than down from what the forwards are saying. Now if we’re only doing that within the context of this range that we have, so we’re not betting the ranch on prices going up by any stretch.

Lasan Johong – RBC Capital Markets

I would agree with you that prices will probably go up so I think that’s a good bet. On the 09 versus the 2010 I want to get one more question in on the terawatt hours that you are projecting, was 09 effected by coal to gas switching and are you suggesting that some of that will come back in 10.

Paul Evanson

Yes.

Lasan Johong – RBC Capital Markets

Could you quantify how much that was.

Kirk Oliver

Coal to gas, its kind of hard to quantify that. We can tell you that our gas plants dispatched quite a bit more during the quarter than what you might typically see. But we can’t, I think in the back of the earnings release we have some capacity factor information. If you go to the second last page of the press release you can see our supercritical capacity factor was like 58% down from 78% the prior year.

And if you look at gas you can see that the gas we don’t have the capacity factor but you can see the gas output 321,000 megawatt hours versus 44 in the prior period, up over 600%. So clearly there’s some gas displacement of coal and as prices move up and gas prices move up which the forwards imply they will do this year, we would expect to see a lot of that turn around.

Lasan Johong – RBC Capital Markets

So can we assume that the delta in the gas output is more or less equivalent to how much coal to gas switching you’re looking at.

Kirk Oliver

I don’t think you can do that, you’ve got to look at the whole PJM, I don’t think it—

Lasan Johong – RBC Capital Markets

No I’m talking about for your particular coal units.

Kirk Oliver

I’m not sure I’m understanding the question.

Lasan Johong – RBC Capital Markets

You said your gas generation increased about 600%, if you normalize that back down to one six, is the delta what I would call coal to gas switching within your own portfolio.

Kirk Oliver

No because we get displaced by other gas as well, not just our own.

Operator

Your next question comes from the line of Gregg Orrill – Barclays Capital

Gregg Orrill – Barclays Capital

I was wondering if you could talk about the approval process for the sale of the Virginia operations and how its going and whether you’re confident it’ll get done.

Paul Evanson

We filed last year and we had a hearing date set for March of this year, before the state corporation commission. The staff retained a special consultant to advise them and you might have seen last week or so, they issued a report that raised certain questions and issues about rates of customers post June 11 and the co-ops I think have addressed a lot of their concerns expressed in the report, there were I think some inaccuracies in that report and I think we and the co-ops both feel that this is going to be beneficial to our customers.

So we’re still both expecting a successful conclusion and an approval by the commission sometime shortly after their March hearing. So probably sometime by the end of second quarter.

Gregg Orrill – Barclays Capital

And then I was wondering if you could remind us whether you’re expecting a change in the book tax rate given that the factors on page 56 seem to add up to a net positive, it would seem to indicate EPS growth expected year over year unless there’s other normalizing adjustments.

Kirk Oliver

Could you try that one again, I didn’t—

Paul Evanson

You’re saying what the expected tax rate is in 2010, is that the question.

Gregg Orrill – Barclays Capital

Yes.

Kirk Oliver

The same, 38%.

Paul Evanson

It had a little bobble here and there because of, largely because of the Pennsylvania NOL in the first quarter and the fourth quarter, a charge and a credit.

Operator

Your next question comes from the line of Neil Kalton – Wells Fargo Securities

Neil Kalton – Wells Fargo Securities

The question on the free cash flow, can you remind us what you said for free cash flow before dividends for 2010.

Kirk Oliver

Yes between $125 and $175.

Neil Kalton – Wells Fargo Securities

So if I’m thinking about this, about $1.1 billion of CapEx and net income and D&A I get roughly around $750 million, call it so there’s about a $500 million delta there, can you explain what is making that up.

Kirk Oliver

Remember the way we look at that free cash flow number is we have the project financings and securitizations in there for TrAIL and some of the scrubber. And so there’s a delta year over year on that. So if you look at the net CapEx number I think is up $400 some odd million.

Operator

Your next question comes from the line of Ivana Ergovic – Jeffries & Co.

Ivana Ergovic – Jeffries & Co.

I notice that there’s been a reduction in forward power price differentials between PJM west hub and [AB] hub, given what you gave out in the November call, I’m just wondering what’s your, why this happened, I think differentials when down but like $1, $1.50. Slide 45, if you compare it to what your October call, the most of the differentials were like $10 and then going to I think $8, and now they’re down in 2010 to $9, then $8 2011, and $6.50 in 2012.

Paul Evanson

We’re really just adjusting for the forwards and the forwards and using AD hub and western hub has narrowed in—

Ivana Ergovic – Jeffries & Co.

I’m just wondering why this happened.

Kirk Oliver

I wish we knew, if we knew why then we could predict what was going to happen and none of us would be on this conference call. We’d be very wealthy. We don’t know, its forwards market.

Ivana Ergovic – Jeffries & Co.

Another thing related to the [inaudible] auction, if I’m right you didn’t give out the realized energy price, you used to give for the other auctions and the break down of the whole pricing.

Kirk Oliver

We’re not going to do that anymore because we’re starting up a small retail effort and its fairly competitively sensitive information so we’re going to pretty much stick to the disclosure we’re doing here when we give you hedge book on kind of an aggregate basis.

Ivana Ergovic – Jeffries & Co.

And another thing did you notice I think [inaudible] coal prices kind of went up and on your last call but it seems that from what you just gave out the central Appalachian didn’t change much.

Kirk Oliver

That’s correct we don’t we don’t burn central App.

Ivana Ergovic – Jeffries & Co.

But any view why there hasn’t been movement in northern Appalachian versus there has been movement in central Appalachian.

Kirk Oliver

No I don’t know why that would be. I don’t follow central App as closely.

Operator

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

Paul Patterson – Glenrock Associates

I’m sorry to follow-up on this terawatt hour question but it sounded to me like you are saying that there was a better price that you were seeing in 2010 through 2012 and that’s what’s causing the increase is that correct.

Kirk Oliver

There’s really two things, there’s the cost to produce the power so we tend to run, we don’t run if it costs us more to produce it than it does to sell it. So it’s the price that we expect to receive and it’s the cost that we expect to be able to dispatch at.

Paul Patterson – Glenrock Associates

Because I’m looking at the previous, slide 45 that you have in current slide and I look at the previous one it doesn’t look like, it looks like prices are actually lower, the forwards are lower although the coal price is down by $1.10 it doesn’t look like its that much. Is it just that or is there, are there other factors such as transportation or—

Kirk Oliver

The emissions and then we’ve changed the way, some of the derating of the plants have been changed so there’s a lot of things that go into that cost.

Paul Patterson – Glenrock Associates

I wanted to ask you about those emissions—

Paul Evanson

The basis narrowed a bit too. So the price change should reflect more our realized prices then the PJM western hub price so that was another plus.

Paul Patterson – Glenrock Associates

And then the emissions, you now have a little note there about the S02 allowance to ton of emissions ratio for 2009 at 1.1 and 2.1 for 2010, 2012, is there some change in these estimates that’s come about or is this just simply what’s happened with the forwards.

Kirk Oliver

No it’s the way the rules work. You’re going to have to start having two allowances per ton starting in 2010 through 2012.

Paul Patterson – Glenrock Associates

And that’s a recent change.

Kirk Oliver

No that’s the way it works.

Paul Patterson – Glenrock Associates

Okay so you’ve just decided to put that information in now I guess. So its additional information you’re providing.

Operator

Your next question comes from the line of Chris Ellinghaus – Wellington Shields

Chris Ellinghaus – Wellington Shields

Can you just give us a little bit more detail on the hydro purchase including what the gain was in the fourth quarter.

Kirk Oliver

That’s a fairly technical accounting and if you want to spend some time with one of our accountants, we could do that, but basically it’s a bargain purchase. We paid about $2 million for the hydro facility and then we have to estimate what the fair value of that facility is which is pretty tough to do but we did it. And you get about a $10 million gain from doing that exercise and then there was an associated contract that got cancelled, that gave us another about $7 million.

Chris Ellinghaus – Wellington Shields

And that was all booked in the quarter.

Kirk Oliver

That was booked in the quarter, $7 of it down in, its credit to O&M and then the other $10 is up in merchant revenues.

Paul Evanson

I think the contract was the $10. The value of the contract was $10.6 million and that got terminated in the deal so instead of getting income over time, we kind of realized it in one fell swoop. So that’s why it got reported in the period.

Chris Ellinghaus – Wellington Shields

And the tax benefit related to the change in elections for repair expensing, how should we be thinking about that for 2010 and if the tax rate is kind of flat year over year what would that benefit be offsetting in 2009.

Kirk Oliver

Not offsetting anything in 2009 its really a timing issue, you’re basically just booking a big deferred tax. So in 2010 we will make up for as far back as we can go on this accounting change, it will be a big impact in 2010 and then it will kind of unwind over time going forward.

Operator

Your next question comes from the line of Philson Yim – Luminus Management

Philson Yim – Luminus Management

Sorry another question on the terawatt hour outlook, as you update these merchant generation outlook slides, will that generation outlook also change.

Kirk Oliver

Yes it can change according to what, we use forward prices so what we would expect to realize in terms of forward prices and what we would expect our costs to be on a forward basis. That can change that output up or down.

Philson Yim – Luminus Management

So as we move through the year, and you update the slide for the commodity prices, its likely that the expected output will also change.

Kirk Oliver

It could conceivably move every quarter.

Operator

Your next question comes from the line of Danielle Seitz – Dudack Research

Danielle Seitz – Dudack Research

I was wondering if there was any changes in the dates for the West Virginia rate case, staff recommendation etc.

Paul Evanson

It got extended out I think it was two weeks or three weeks because of the staff needed some time to evaluate this new tax election. Other than that we expect to be on the same schedule.

Danielle Seitz – Dudack Research

And [inaudible] if I look at page 54 where you are mentioning $258 million, what is the difference between that and the $291 that’s in the income statement. The $291 in the income statement and the $258 in your handout. I’m sorry there is probably a lot of AFC but AFC will go the other way.

Kirk Oliver

It’s the tender has been adjusted out.

Danielle Seitz – Dudack Research

And so should that be also included in 2010.

Kirk Oliver

We adjust tender premiums out.

Operator

Your next question comes from the line of [Unspecified Analyst] – SunTrust Robinson Humphrey

[Unspecified Analyst] – SunTrust Robinson Humphrey

Going back to West Virginia on the whole issue of whether you can get relief for taxes or not given your own change in your overall corporate tax rate now that you’re not a cash tax payer in 2010 I know that theoretically that should have nothing to do with West Virginia but given the last time they ruled against you for that very reason that you are not a cash tax payer at the parent, do you feel that that makes your hand more difficult now as you’re dealing with this rate case this time around.

Paul Evanson

Yes it would make it more difficult than if we didn’t have that item. How we distinguish this item from the prior is this is a special one-time kind of adjustment. Its almost like a restatement of taxes where you, that’s the cumulative impact of those capitalized repairs. So commission [inaudible] normally to look at normalized items and normalized tax liabilities, so we’re hoping they kind of see through this item and if they normalize it then we’d be back to the position we were in when we filed the case, namely that we would be paying tax.

Now that’s the logic as you say, whether they’ll look at it that way I don’t know. We’re hopeful but we’ll see, but clearly it makes it more difficult that we’re not paying tax although we’re quite happy not to pay tax.

[Unspecified Analyst] – SunTrust Robinson Humphrey

And separately the transmission rate base numbers that you’ve updated now with the reduction in the PATH expenditures you now have them going up slightly toward $1.3 billion by the end of 2014, previously I think you had them going up to $2.3 billion, so now if you believe PATH is completed by 2016 should we expect that incremental billion that we lost by 2014 will all be picked up in the following two years.

Kirk Oliver

Yes it should be pretty close.

[Unspecified Analyst] – SunTrust Robinson Humphrey

So it will be a pretty big ramp up in 2015 and 2016.

Kirk Oliver

Yes.

Operator

Your next question comes from the line of Greg Scheer – Unspecified Company

Greg Scheer – Unspecified Company

This question may be a little theoretical and two years early but wondering given moves to put FERC regulated gas transmission into MLPs I’m wondering if you have any thoughts about the long-term practicality or viability of dropping electric transmission into MLPs over time.

Paul Evanson

We like the transmission, we like it in our portfolio, but we have structured it in a way that its really kind of a stand alone operation. We try to maintain the maximum flexibility we could whether its an MLP or just a plain spinoff of it, what ever way would optimize value to most. But I think you’re right, that’s a question that’s out there a little bit and right now we’re sharply focused on getting it done by June 11.

Operator

Your next question comes from the line of Ryan Moody – [Ducane Capital]

Ryan Moody – [Ducane Capital]

I have one more question on the terawatt hours of output can you give us a further sense on what you’re seeing for the supercritical dispatch versus the [inaudible] dispatch within the 34 to 34.5 terawatt hour range of output that you’ve laid out.

Kirk Oliver

Supercritical I’ll give you 2010 and 2011 we’re looking at 78-ish percent capacity factors, [inaudible] are looking at low to mid 30’s.

Ryan Moody – [Ducane Capital]

As we think about the upcoming PJM auction and I look at the 6200 megawatts that you’ve laid out have cleared on slide 44, how do I reconcile that with the 6900 megawatts of nameplate that you have. Is that [E4] adjustments or are there plants that aren’t clearing, just trying to think of a good run rate.

Kirk Oliver

Yes its basically our guys take a look at how they expect the plants are going to run and what kind of capacity they’re going to be able to make available and they bid that number in.

Ryan Moody – [Ducane Capital]

So it’s a combination of all of the above.

Kirk Oliver

Yes its anything that could effect plants operations, so if you bid in more than you can make available you’ve got to go out and cover it in the market. So you tend to try to get that number right.

Operator

Your next question is a follow-up from the line of Lasan Johong – RBC Capital Markets

Lasan Johong – RBC Capital Markets

Now that you’ve got all your supercritical plants scrubbed does it make sense to try and migrate more towards higher BTU, but higher [inaudible] coal let’s say from Illinois that tends to be a little cheaper.

Paul Evanson

Well we constantly look at that kind of trade off, the coal for example, Harrison as you know where we sit right on top of the coal field and it comes by conveyor, nothing is going to beat that. But we have done some Illinois coal and we regularly look at the economics on the trade off of that and its possible over time we could migrate a little more over there.

Lasan Johong – RBC Capital Markets

On the PATH situation I don’t mean to be a dour messenger, but is there a chance that that could get cancelled and if it does what would be the cost of, how much money have you put into it so far.

Paul Evanson

Probably what would happen is it would be deferred for X number of years. I doubt they’d say there’s no need for this line period having just identified for the preceding three years why it was essential. So I think they’d kind of keep it in a holding pattern and push it out a little bit. But if they took the action that said cancel the project, under our FERC tariff we’d be entitled to recover all of our investments to date which have not been that material.

Operator

Your final question comes from the line of Unspecified Analyst – Beckett Capital

Unspecified Analyst – Beckett Capital

Just a quick follow-up I guess you’ve had a lot of questions on the terawatt hours of generation volume and I guess the question is what your view is given that a lot of your competitors have also guided to fairly healthy volumes return to healthy generation volumes in 2010 but some of the utilities actual loads in terms of guidance hasn’t been as robust and there seems to be a miss match between a lot of generators’ expectations for volume versus the coming back of utility load. I guess could you talk about that phenomenon and is there differentiation between maybe your generation versus maybe some of your competitors and PJM or how should we think about that.

Kirk Oliver

I guess the way I think about it is you’re basically asking a question on is the forward market wrong. We’re taking forward power prices which take into account what the market expects the supply and demand situation to look like. So if the forward market is wrong and the prices that we’re seeing in the forward market are too high, and actually come in lower than what we expect then our output would be lower as would all the other generators who I’m sure run models very similar to what we run.

Unspecified Analyst – Beckett Capital

Is overall demand part of the equation or how does that sort of get formulated.

Kirk Oliver

The demand is reflected in the expectations for forward power prices so if demand were expected to be, if we weren’t in this economy and demand were expected to be stronger then I would expect power prices to be higher. And if demand is expected to decline I will expect power prices, all other things being equal, to decline as well and that will effect our dispatch.

Paul Evanson

I’d add one other item, most of use the same industry tested dispatch model and its conceivable the model might miss some things in this kind of down and up process that we’ve been through. Its been a unique process the last year through the economy and the recovery, etc. so if we’re all using the same model and its all telling us the same thing, we’ll see. Maybe there’s a quirk in the dispatch model. I wouldn’t say that’s an impossibility by any stretch.

Kirk Oliver

Although we’ve back tested ours and its worked pretty well.

Paul Evanson

So far.

Well thank you very much. We appreciate all the interest and your interest in the company and if there are any further questions, Max will be available later in the afternoon. Thank you. Good afternoon.

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Source: Allegheny Energy, Inc. Q4 2009 Earnings Call Transcript
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