Allegheny Energy, Inc. Q1 2009 Earnings Call Transcript

May. 5.09 | About: Allegheny Energy (AYE)

Allegheny Energy, Inc. (AYE) Q1 2009 Earnings Call May 5, 2009 2:00 PM ET

Executives

Max Kuniansky - Executive Director of IR and Corporate Communications

Paul Evanson - Chairman, President and CEO

Kirk Oliver - SVP and CFO

Analysts

Greg Gordon - Citi

Emily Christy - RBC Capital Markets

Neil Stein - Levin Capital

Brian Russo - Ladenburg Thalmann

Michael Lapedis - Goldman Sachs

Ameet Thakkar - Deutsche Bank

Reza Hatefi - Decade Capital

Ivana Ergovic - Jeffries

Gregg Orril - Barclays Capital

Paul Patterson - Glenrock Associates

Operator

At this time, I would like to welcome everyone to the Allegheny Energy Conference Call. (Operator Instructions).

At this time, it is my pleasure to turn the conference over to the Executive Director of Investor Relations and Corporate Communications, Mr. Max Kuniansky. Please go ahead, sir.

Max Kuniansky

If you have to leave the call before it's over, you can listen to the taped replay. It's available until midnight on May 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.

Now, let me introduce Paul Evanson, Chairman, President and Chief Executive Officer of Allegheny Energy.

Paul Evanson

Today we reported GAAP basis earnings of $134 million or $0.79 per share for the first quarter. Excluding net unrealized gains associated with economic hedges that don't qualify for hedge accounting, adjusted earnings were $0.67 per share compared to $0.80 in the first quarter last year.

Results for the quarter were down from last year due to some special state and other income tax items. On a pre-tax basis, however, adjusted income was up $8 million year-over-year, a solid financial performance given the environment.

Primary drivers of the quarter were higher generation rates in Pennsylvania and Maryland, as well as increased cost recovery from our settlement with the commission in Virginia. These were partially offset by lower generation volume due to plant availability being lower and lower demands.

Market prices for power in the first quarter were down substantially compared to the same period a year ago. Average round-the-clock prices at the PJM Western Hub fell nearly 30% compared to the first quarter a year ago. With about 90% of our power under contract or hedged going into the year, we were largely protected from the decline in the market.

Indeed, we took advantage of the low market prices to do some additional maintenance at several of our supercritical plants. This was one of the reasons our outage factor was up significantly in the quarter. We also experienced unplanned outages due to turbine problems, tube leaks and other equipment problems.

At Allegheny Power, our regulated delivery business, we are seeing the impact of the recession in our industrial sector. While industrial usage was down in the first quarter, this weaknesses was more than offset by increased residential usage.

Now, let me comment on a few recent developments affecting Allegheny, and I'll begin with our most recent news. We signed a definitive agreement to sell our Virginia distribution business to Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative. These co-ops are acquiring a service territory that's experiencing solid growth and that's located adjacent to their territories.

Now, for Allegheny, Virginia is a small part of our regulated business and we serve only a small part of the commonwealth of Virginia. Running this Virginia business requires as much management time and attention as our other three states. So, the sale will allow us to focus even more on our three core states and generation fleet.

The sale is for the distribution assets only. We'll retain ownership of our transmission system in the state, including the Virginia segments of the TrAIL and PATH projects. The purchase price is about $340 million and is payable in cash at closing. Our net book value is approximately $215 million. Now, both of these numbers are subject to closing adjustments.

Given our federal net operating loss position, we would not expect to pay any current taxes on the expected gain. So these cash proceeds will further strengthen our financial and liquidity position. The sale is subject to regulatory approvals and certain other conditions, but we expect to close by the end of this year.

Now, I'd like to provide an update on the transition to market-based rates in Pennsylvania. Allegheny Power has obtained PUC approval to hold auctions over the next three years to procure power for its customers for the period after rate caps expire in 2010. At our request, the PUC authorized us to accelerate the initial auction from June to April, so as to take advantage of current low market prices.

In the April auction, five contracts were awarded with an average weighted retail price of $72.80 per megawatt hour. Assuming all subsequent auctions were at that same price, our customers would see only an 8.5% increase in their rates in January '11, when caps expire. This is a very positive step in transitioning to market-based rates in Pennsylvania for us.

The next auction will be held in June. We recently asked the commission to allow us to procure an additional 300 megawatts of residential load in this auction, so as to lock-in even more power at current low market prices for our customers. If the commission grants our request, we will have secured more than half of the residential load for the year 2011 by the end of June.

Now, let's look at the impact of that auction on our generation base. Allegheny Energy supply won approximately a third of the initial auction or about 650,000-megawatt hours. Supplies winning bid would suggest an increased energy margin of approximately $10 per megawatt hour pre-tax from 2010 to 2011. At the time of the April auction, the PJM Western Hub price was $55 per megawatt hour for '11.

As supply continues to contract for power in '11, this $10 uplift will fluctuate with a number of factors, but the single largest variable will be the price of power at the PJM Western Hub at the time of contracting. I know that this uplift is the energy component only. We have netted out the capacity element from the $52.50 polar price in 2010.

Capacity prices have already been set through May 2012 in a series of PJM run auctions. The average price per megawatt day for 2011 is $137, down about $40 from 2010's price. So we will have a negative price variance in 2011 for our roughly 6,400 megawatts of total unregulated generated capacity.

Moving now to transmission, we've now obtained easements for about 75% of the entire length of the Trans-Allegheny Interstate Line or TrAIL. Construction has begun on two substations and segments of the line in West Virginia and Virginia where we have all of the necessary permits.

On our other major line, the Potomac-Appalachian Transmission Highline or PATH, PJM recently confirmed that the project remains critical to regional reliability, but decided to delay its in-service date another year to 2014 primarily because of recent load forecasts.

We plan to make filings for state approval later in the second quarter in West Virginia, Virginia and Maryland. The approval process should take at least a year. We broke ground in April for our new transmission headquarters building in Fairmont, West Virginia. About a 150 professional employees will be located in the new office building, which will be built to environmentally-friendly standards.

Now in the environmental area, our scrubber projects are moving forward on schedule and on budget. We expect to tie in the first Hatfield unit in June with the remaining units at Hatfield and Fort Martin scheduled to come online in the fourth quarter.

We continue to participate in a debate on the comprehensive energy and climate change legislation at the federal level. Recent draft legislation circulated by Congressman Waxman and Markey include stringent caps on carbon dioxide emissions, but does not address the important issue of allowances.

The Obama administration strategy favors an auction approach, whereas we and many others advocate and allocation process similar to what's worked so well for us too.

I think there has been a growing appreciation that the proposed bill could result in significant rate increases for customers and have a disproportionate impact on certain regions of the country, specifically coal and industrial states. So I'm somewhat optimistic we will end up with a reasonable bill coming out of the Congress. We shall see.

Before I conclude, I'd like to say a few words about our outlook for the remainder of 2009.

Our earnings growth drivers have moved a little in our favor since the last call. Our expected coal costs are down somewhat, and our NOx allowance costs are also expected to be down. We've purchased some credits at lower prices than anticipated earlier and made some operational adjustments at the plants to reduce NOx emissions.

As I mentioned earlier, lower power prices are not hurting us too much this year, because of our hedged position, but will begin to have a greater impact in 2010 as some of our financial hedges roll off at the end of this year.

Against the backdrop of an ongoing recession, unstable credit markets and low commodity prices, we're staying focused on the fundamentals of running our business, particularly in controlling costs, both operational and capital, and maintaining a strong financial position.

We've made steady progress in improving our operations, transitioning to market, building a major transmission business, and securing fair, regulatory returns. When this recession ends and an economic recovery begins, Allegheny will be very well positioned to prosper and enhance shareholder value.

Now let me turn the call over to Kirk.

Kirk Oliver

Thank you, Paul, and good afternoon, everyone. For the first quarter of 2009, we reported GAAP net income of $134 million compared to $136 million a year. We earned $0.79 a share in the first quarter compared to $0.80 in the same period last year.

Adjusting for net unrealized gains, which are associated with economic hedges that do not qualify for hedge accounting, earnings for the first quarter of 2009 were $0.67 per share. Earnings for the same period a year ago had no adjustments.

While after tax earnings were down, let me summarize the key factor that's contributed to the $8 million increase in pre-tax earnings for the first quarter. Higher generation rates in Pennsylvania increased revenue by $31 million.

This is a net affect of the nearly 20% increase in generation rates offset by the expiration of a $14 million earnings benefit related to Pennsylvania's stranded cost recovery. The Virginia increase of $29 million reflects increased purchase power costs recovery as a result of the 2008 settlement.

In January 2009, residential customers in Maryland moved to market rates for generation. The uplift in earnings of $23 million is attributable to the fact that the below market polar contract in 2008 has now transitioned to market.

The affect of market prices hedging activities and generation volume reduced pre-tax earnings by $43 million. Unregulated megawatt hours generated were 19% lower this quarter compared to the same quarter a year ago. This was a function of decreased demand and market prices and an 8% increase in unplanned outages. Our marketing and financial hedging activities along with capacity revenues offset a 30% decline in market prices.

Higher coal prices at AE supply reduced pre-tax earnings by $26 million. All other adversely impacted income by $6 million due to higher fuel-related and other costs which partially offset by increased revenues from transmission expansion and the settlement of the Kern River hedges.

Adjusted pre-tax earnings for the first quarter of 2009 were $203 million. Although adjusted pre-tax earnings increased $8 million, adjusted net income was down because of a higher effective tax rate.

A higher effective tax rate was the result of a $10 million Pennsylvania NOL valuation adjustment in the first quarter of 2009, as well as lower taxes in 2008 which benefited from favorable income tax settlements and tax law changes in West Virginia.

Paul mentioned that the recession has continued to impact our industrial usage. However, as you can see, despite the industrial decline, total regulated customer revenues were slightly positive when compared to last year.

Moving on to cash flow. Net cash flow from operations was $7 million in the quarter compared to $106 million last year. This quarter's amount was impacted by changes in working capital, which included a $44 million increase in fuel inventory and increased collateral requirements of $92 million, resulting from a change in PJM policy. These collateral requirements are expected to decrease by $30 million to $40 million when PJM settlements change from monthly to weekly effective in June 2009.

Capital expenditures were $254 million in the quarter. This includes $49 million of spending on our Fort Martin scrubbers, which are funded through securitization proceeds. It also includes $50 million of transmission expansion CapEx, which is funded from our TrAIL bank facility.

Free cash flow, excluding capital expenditure, funded through the securitization proceeds and project financing was a negative $148 million for the quarter. Making the same adjustment for the full year 2009, we expect to have free cash flow of between 0 and negative $100 million.

Our capital expenditures for 2009 are estimated to be about $1.1 billion. We have reduced our 2010 capital expenditures to $880 million, primarily reflecting the delay in PATH timeline and management efforts to further reduce capital spending.

Our liquidity position and credit metrics remain strong. Cash on hand was $206 million as of March 31. Capacity available under both of our credit facilities remains at $773 million for a total liquidity of almost $1 billion. We have no significant debt maturities until 2011.

Here is an update of our key earnings drivers for 2009 compared to 2008 actual results. This is a list of key drivers for the year and does not reflect everything that impacts our results. I will focus first on the drivers that have changed, which are highlights. I will also spend a little time on some of the others just to remind you of what's included. All of these drivers are estimated using market prices as of March 31.

The coal driver is changed from $140 million negative to $130 million negative. Since we are expecting to burn less coal in 2009 than we estimated on our last call, we have been able to divert purchases of high coast coal into later years and in some cases to eliminate such purchases.

Emissions and other fuel-related costs have improved by $20 million since our last call, driven primarily by lower costs for annual NOx allowances. This is due to reduced prices, reduced generation output and operational improvements at the plants.

As you can see, prices for annual NOx have come down significantly. This allowed us to recover much of our position at prices lower than we had previously estimated. As of March 31, we have covered 90% of our expected 2009 annual NOx requirements.

Moving on to the market prices, hedging activities and generation volume driver, this driver has changed from a negative $25 million, which was a result of our Maryland and Virginia contracts, to negative $60 million. This includes the $43 million loss that we experienced in the first quarter plus the impact of the Virginia and Maryland contracts for the balance of the year.

Moreover, we have about 2 million to 3 million megawatt hours of open generation for the remainder of the year, almost all of it off-peak that we estimate will provide about another 35 million decrease based on our forecasted dispatch, again, using March 31 forward prices. Of course, providing this estimated $35 million decrease, we are not attempting to convey that our open megawatt hours in 2009 will be sold at current 2009 forward prices.

We would like to present some additional information on our financial hedges as they are providing a significant benefit in 2009, but roll-off at the end of the year. For the year, we have on-peak financial hedges of about 3.6 million megawatt hours. The average contract price of these hedges is $88 per megawatt hour. We also have off-peak hedges in 2009 of about 0.5 million megawatt hours at an average contract price of $55 per megawatt hour.

Now, just let me touch on some of the drivers that have not changed. For the Pennsylvania rates driver, I want to remind you that it includes 160 million polar rate increase offset by a $20 million benefit from stranded cost collections that expire in May 2008. The entire year-to-year $20 million negative amount occurs in the first two quarters of this year.

The interest expense driver remains unchanged, but it is important to note that both in 2008 and 2009 interest expenses benefited from capitalized interest related to the Hatfield scrubbers. These scrubbers will be put into service by the end of the year and we will stop capitalizing interest at that time. Capitalized interest in 2009 for the Hatfield scrubbers is about $30 million.

In addition, our depreciation driver includes a $9 million increase in 2009 related to the Hatfield scrubbers. Annualized depreciation expense will be about $30 million. These drivers are provided in a pre-tax basis. Earlier, I discussed some year-to-year tax differences for the first quarter. We expect the remaining quarters in 2009 to have about a 38% effective tax rate versus a 36% effective tax rate for the last three quarters of 2008.

With that, let me turn it back to the operator for questions.

Question-and-Answer Session

Operator

(Operator Instructions). We'll take today's first question from Greg Gordon with Citi.

Greg Gordon - Citi

So it's a good news, bad news, good news, bad news, good news story, I guess, for 2010. I'm glad I got a laugh. I thought hard about that one.

Paul Evanson

I'm glad you had more good news than bad news there, Greg.

Greg Gordon - Citi

Me too. Can we talk about the $384 million of cash that you'll get in hopefully at the end of the year from the sale of the Virginia. What was the expected net income contribution in '09 and '10 from Virginia that will go with the sale?

Kirk Oliver

It's about $9 million or $10 million.

Greg Gordon - Citi

Is that $9 million or $10 million of net income in 2090.

Kirk Oliver

'10.

Greg Gordon - Citi

In '10? So in 2010 $9 million to $10 million of net income goes away and $384 million of cash comes in.

Paul Evanson

$340 million.

Greg Gordon - Citi

I'm sorry. I wrote that down incorrectly. The second question, where will the parent NOL balance be after you offset it with this gain? Will you have fully depleted it?

Kirk Oliver

I don't think so. I think its close.

Greg Gordon - Citi

Because that begs the question of when you go back to West Virginia and argue that you need a rate hike because they've offset revenue requirement in West Virginia with the assumption that you can subsidize it with these NOLs.

Paul Evanson

You are exactly right. An additional major benefit from the Virginia sale is the acceleration of the income tax benefit. I think it pretty well carries us through '09 and we'd have some in '10. So we may be able to adjust somehow in the rate file in West Virginia already to pick up that in anticipation.

Greg Gordon - Citi

Would you expect to file in '09?

Kirk Oliver

We're certainly looking at it and we may well do that in the fall.

Greg Gordon - Citi

So, if we were to presume that the West Virginia regulators were reasonable that would be up to a $55 million revenue requirement benefit in '10?

Paul Evanson

That would be the full amount, but it could be less than that.

Greg Gordon - Citi

If they give you less than you deserve, right?

Paul Evanson

Right, or if their NOLs continue a carryover, things of that kind. We haven't finished the calculations of the Virginia sale and what it does yet, but obviously it takes a big piece of it out.

Greg Gordon - Citi

Now, West Virginia, the price, you've given a lot of different information on how to sort of triangulate around 2011 versus '10, and I think you're just trying to be helpful, but a little of it is confusing. So let me ask you a simple question.

In the 2010 Pennsylvania all-in bundled rate that you will be realizing which is 52.5 hours, how much of that is energy?

Paul Evanson

There's about $13 of capacity and the balance is really attributable in total to the energy fees.

Greg Gordon - Citi

So take $52.50, subtract $13, right, and that's the energy piece on which you're seeing a $10 improvement, but we're going to see a couple of dollars of megawatt hour decline in the equivalent price per capacity.

Paul Evanson

That's the price before you make all of the adjustments, shaping costs, renewable costs, et cetera. You'll recall on the last call what I tried to do to simplify all that was to take all of those adjustments out and come up to the comparable number at the PJM Western Hub based on the $52.50. That number was approximately $40.

That I think is the simplest way, because all of these adjustments; A) are pretty complex; and B) some of them are quite proprietary because that's how we use in bidding.

Greg Gordon - Citi

What you're trying to tell us in your disclosures today is that $40 goes to $50 on the load that you won, the capacity is what it is and the ancillary services may go up or down depending on how you price them?

Kirk Oliver

Right. We made assumptions about 2010 capacity and deconstructed the $52.50 to get the energy price. So capacity prices are going down from 2010 to 2011.

Greg Gordon - Citi

If I wanted to build my model with capacity independent of energy, I know that in 2010 to 2011 capacity is going from 140 to 320 because that's the disclosure on page 15 of your last presentation, right? Energy is going up $10. That's what you're trying to tell me?

Paul Evanson

No. When we get to the $40 price, that's deducting the $13 of capacity to try to make capacity comparable to the number that you're getting in '11. That was the whole purpose of that. So we built into the $52.50 a reduction of $13 which in '11 is $10 as the capacity element. So there is a $3 negative price variation you might say in the capacity fee.

Greg Gordon - Citi

So $13 goes to $10 and $40 goes to?

Paul Evanson

$40 goes to whatever it is. It was $55 in April and I think the forwards today are now running about $56. So it's kind of stabilized right at the $55 level for right now for '11.

Greg Gordon - Citi

All right. So you see a $10 improvement in energy, a $3 decrement in capacity relative to 10? That's what I think investors want to understand. So I just wanted to make that clear.

Paul Evanson

I'm glad you've done that and that's what I tried to do on that one capacity auction. We've had some confusion in the past. What we've done here is take the entire amount of revenues on a pro forma basis to '10 and '11, and that's a $90 negative for capacity all-in.

Greg Gordon - Citi

Understood. I think what you're trying to tell us in the disclosure on page 31 is that if I were to look at a comparable price for today for on-peak and off-peak power, on the same amount of megawatt hours and assume that you rehedged at current forward curves. It looks to me like you get closer to $60, relative to the $84 price that you're showing us here.

So are you trying to explain to us that you've got about $100 million negative potential variance in gross margin, '10 versus '09 relative to how you've hedged?

Kirk Oliver

Well, we don't give '10 guidance, but certainly, we lose this margin at the end of 2009. I think the way you did the calculation would be correct. You basically take a look at the on-peak and off-peak forward prices for '10 and then compare them to the average contract price we have on the slide.

Greg Gordon - Citigroup

So negatives for 2010, although that you've disclosed today are this issue with regard to the hedge, higher Hatfield scrubber interest and depreciation, offsetting that, we hopefully will get something in West Virginia, remains to be seen. You're also at a lower cost run rate in '09 that will roll into '10. There should be some accretive benefits to exiting Virginia. You've also meaningfully cut your CapEx. Is that fair?

Kirk Oliver

Yeah, I think that's a pretty fair assessment.

Paul Evanson

Pretty reasonable.

Operator

Our next question comes from Emily Christy with RBC Capital Markets.

Emily Christy - RBC Capital Markets

In terms of the coal generation for this past quarter, did you see any impact from coal to gas switching?

Kirk Oliver

It's pretty hard to see that. We think that that's affecting our subcritical plants, but not the supercriticals. Now if you look at the supercriticals, they've been running less, but that's largely a function of demand and price, not being displaced by gas. So we try to look at what the gas plants are doing. They're not running when we're not running the suppers, but we have seen a little bit more of a pickup in the gas during shoulder periods when we might otherwise be running the subs.

Emily Christy - RBC Capital Markets

At this stage, how concerned are you that there may be changes from regulators from legislators to the transition to deregulation in Pennsylvania?

Paul Evanson

Well, I think that this has always been an issue, particularly a year, year and a half ago, when power prices were at the higher point. As I say, sometimes the good news and the bad news of lower prices that this transition likely at least for us is to be pretty easy, because if you look at an 8.5% increase, I don't think there is going to be legislation or problems of any kinds on that.

I think Exelon and the PECO territory is very low and you have some others that are higher. So I wouldn't say there wouldn't be legislation. I mean there's another bill that's been introduced in the House, but nothing has gone through in the prior year where prices were much higher all around.

I think, frankly, if any legislation were, it probably won't have any meaningful impact on Allegheny power at this point in time, given the first auction. Remember our whole procurement plan was supposed to begin in June. We went in because of these lower prices and asked to start it in April. Now we've gone in again and asked to increase the June auction significantly.

The commission will decide that mid-May, May 14th, I think. If we do, we'll have 53% of our entire 2011 residential load already sold by the end of June. So I think we've taken the risk at least as to us for transition in the market pretty much off the table.

Operator

Our next question comes from Neil Stein with Levin Capital.

Neil Stein - Levin Capital

I had a couple of questions here. First, just with respect to coal contracting, the usual slide that you normally include wasn't in the deck today. So, I wanted to see if anything has changed and any issues on any contract renegotiation.

Paul Evanson

There has been no new contracting. So I think the slide we had last time still stands. The only thing that I would say would have changed on it is, I think as Kirk might have mentioned, we've done better on the coal side because we've pushed some deliveries out into '10 and usually it's been the higher cost coal.

So the number we showed in '09 is probably going to be a little bit less than we showed the last time and accordingly probably '10 maybe a little bit higher.

Neil Stein - Levin Capital

To a different topic, just with respect to the '11 uplift. On the fourth quarter call, you talked about a $60 energy price equating to $20 uplift in '11 for the margin.

Paul Evanson

Yes. I know exactly.

Neil Stein - Levin Capital

With the most recent disclosures, you said that $55 equates to only a $10 uplift. So based on the logic of what you talked about previously, you would have thought it would have been maybe a $15 uplift equating to the $55. So just wondering what's changed?

Paul Evanson

Well, no, exactly. The 20 that I mentioned on the call was based off the deconstruction of the $52.50 down to the PJM at the Hub of $40. When I did that call, the forwards were at $60 so that gave me the $20 margin. When we actually got to the April auction, it was, as you mentioned, $55, so it brought the $20 down to $15. $5, frankly, is a whole slew of all those other adjustments including basis and FTR value from ['01] period into '10 period to the '11 period. They happen to be five negative.

Frankly, when we get to do the next auction that $5 negative could be the same or it could be zero or it could be positive. There are a lot of unique elements that take place that move that. So in this particular auction, it was a negative $5.

Neil Stein - Levin Capital

Just could you confirm, Greg touched on this in some of his questions and you had alluded to this earlier on the call. When we're thinking about the uplift in '11 versus '10, there is the $10 per megawatt uplift from energy, but capacity will be an offset to that $10?

Paul Evanson

Yes. In that 200, of course, that uplift is all premised on the April auction. That number could change quite a bit, whereas the capacity is pretty well frozen at this time, because it's based on all of the PJM actual auction results.

Operator

Our next question comes from Brian Russo with Ladenberg Thalmann.

Brian Russo - Ladenburg Thalmann

With the initiatives you have that you implemented in mitigating the NOx emission exposure, have you mitigated your exposure post 2009 as well?

Kirk Oliver

Well, only to the extent that some of the operating improvements will reduce the emissions in '10 and '11. We haven't gone out and secured any credits for 2010 or '11.

Brian Russo - Ladenburg Thalmann

So there is still variability around that cost post 2009, relative to where you guy have locked in '09.

Kirk Oliver

Yes. That's right. Just to be clear, we do have some credits already for '10 and '11, but we haven't been out actively purchasing them.

Brian Russo - Ladenburg Thalmann

Any comments on the upcoming PJM auction and will the delay in PATH have any impact on that, do you think?

Paul Evanson

Well, the auction has already started this week, and we'll get the results, I think its May 14, May 15. I think I'll refer to what actually happens. I mean there are factors that might suggest it's down and we might as well just wait another week and a half and see exactly what it is.

Brian Russo - Ladenburg Thalmann

Then just to be clear, the decrease in the capacity revenue per day is being offset by the increase in the amount of capacity that you guys have submitted into the auction, right, 2,400 in 2010 going to 6,400 in 2011?

Paul Evanson

That's yes and no. I mean in a pure technical way, the polar agreement did not specifically provide for capacity with kind of pro forma in those numbers in calculating what the energy margin was. So now under the new contracts, the utility kind of shifts that capacity payment to supply that bills it into the price and repays it to PJM.

So you'd see a net increase in actuality, but relative to the way we've deconstructed the $52.50 you will not see it. So it's kind of either in one bucket or another, is basically what I'm saying. We've tried to reconstruct it in a way that we've pro forma it as if we would pay a net positive in '10 for the capacity.

Operator

Our next question will come from Michael Lapedis with Goldman Sachs.

Michael Lapedis - Goldman Sachs

We've seen a big uptick coming out of the EPA regarding the good old friend new source review litigation coming back in the sector given [Karen Kamer] sitting on the side lines. Can you talk a little bit about, obviously, you're mostly done with scrubber projects, but exposure both to NSR and to potential implementation of SCRs or other NOx and mercury controls?

Paul Evanson

We do already have a lawsuit pending in the Pennsylvania federal district court under the NSR umbrella. That was started back in '04. The trial date has not been set yet, but is likely to be maybe late '09. We think we have a reasonable case.

The good news is over the four years now that this darn thing has been pending, it hasn't even gotten to trial yet, we have put now scrubbers on the five other units. So, all of our fleet will be fully scrubbed. So the issue will probably come down to in terms of a settlement or decision on the SCR that we don't have on Hatfield and Fort Martin and maybe on one or two of the subcriticals and levels, penalties, et cetera.

I think at this state we think that thing seems to be moving forward and we have a reasonable case.

Michael Lapedis - Goldman Sachs

Can you talk a little bit about potential cost impact if you were to put SCRs on the supercritical units.

Paul Evanson

I think the rough estimate ballpark was like $200 million a unit. We have five units, so we are getting close to $1 billion.

Michael Lapedis - Goldman Sachs

Over what kind of timeframe?

Paul Evanson

We have no present intention to do this. So it would only be a function of a lawsuit judgment or a settlement, and then that would have to be worked out in the settlement.

Operator

Our next question comes from Ameet Thakkar with Deutsche Bank.

Ameet Thakkar - Deutsche Bank

I don't want to belabor the point, but I want to make sure I understand it correctly on the example that Paul did, walking through to the $10 margin uplift following the results of the most recent Pennsylvania polar supply auction.

So, you started off with $52.50 which was this last year of the polar supply auction and then you subtracted $13, which is taking what current PJM capacity price values are for 2010 and we arrive at an energy price of $39.50. Is that correct?

Paul Evanson

Yes, energy at first blush, but not the PJM price. Everything for energy component and all of the adjustments relative to coming up with that.

Ameet Thakkar - Deutsche Bank

That's like a shaved energy price.

Paul Evanson

Everything in it is exactly shaping, renewable obligation, basis adjustment going back out, FTRs, you name it. Everything is in there, margin, if somebody is bidding on this. So there is a lot in it. That's why it's so difficult to communicate and get a sense of what uplifts could to communicate and give a sense of what uplifts could be.

That's why we got to the idea of why don't we just do it ourselves because some of this we, for proprietary reasons, can't disclose and give you the number that we think, having deducted that $13 for the capacity, is a PJM Western Hub round-the-clock price and then you can track it. That number is $40.

That, frankly, is the biggest variable. We get caught up in $2 or $3 here and there, but the price for '11, back nine months ago, was $80 and now we just went out in $55, so you got a $25 change. That's $0.5 billion change. That is clearly by far the biggest driver, and we thought it would just soak us on that by kind of trying to simplify that disclosure.

Ameet Thakkar - Deutsche Bank

I guess that margin applies to your residential load, is that correct?

Paul Evanson

Yes.

Ameet Thakkar - Deutsche Bank

If I factored in kind of the amount of industrial load you have, and it's going to be up for bid in one of the subsequent auctions, how should we think about the total margin uplift on the 20-some megawatt hours of West Bend load you guys have?

Kirk Oliver

That would be about the same.

Ameet Thakkar - Deutsche Bank

It would be about the same?

Paul Evanson

Yes.

Ameet Thakkar - Deutsche Bank

If I can just ask one more quick question on the sale of the Virginia LDC assets, that $340 million, does that include any assumption of debt or is that an equity value?

Kirk Oliver

There is no assumption of debt. It's an asset sale.

Operator

Our next question comes from Reza Hatefi with Decade Capital.

Reza Hatefi - Decade Capital

So this Virginia sale, what's the use of proceeds? How much debt, I guess, is associated with Virginia that you could pay down or are you not going to pay it down?

Kirk Oliver

We'll probably pay down debt with that. It may not be all at FPE.

Reza Hatefi - Decade Capital

Your generation volume in the first quarter was a little lighter than last year. What's your current expectation for total unregulated generation in 2009?

Kirk Oliver

It's between 30 and 32.

Reza Hatefi - Decade Capital

Is that kind of the total that we should expect going forward or is 2009 sort of an anomaly?

Kirk Oliver

It's a function of demand and power prices. So, I would hope that it would pick up after 2009 as the economy starts to come back.

Reza Hatefi - Decade Capital

In reality, the $52.50 is embedding maybe like a $3 capacity number and like $30.35 energy and the rest is shaping and ancillaries, et cetera, but you're just trying to simplify it so you're representing it differently. Is that how the reality is, something more like the numbers I represented?

Paul Evanson

The reality is this was the price set back in 2004 and it was a pure negotiation among all the parties when we were extending rate caps from '08 to '10. You'll remember we extended them because they were pretty flat for four or five years and we got a step-up over a period of time. So it made economic sense to do. It's a pure, you might say black-box negotiated number.

I mean there was a capacity market, but it was nothing like the three year market that's there right now. So we thought the simplest thing was to take what we know is already preset for '10 as capacity prices in the PJM auctions and just use that as the deduct from the $52.50, so you got a more apples-to-apples comparison of capacity in PJM West to PJM West.

Reza Hatefi - Decade Capital

The $40 you mentioned being the energy component, that's a PJM West price, and then you compare that to the $55 in the recent auction, that again is a PJM West price.

Paul Evanson

Exactly. That was the price at the April auction. In a sense, that PJM Western Hub at 55 is really the starting point that people use when they're bidding. So it's the right and most significant measure. So that's why we did it. We're sorry if it confused people a bit, but I thought in the end it was a much cleaner way to do it once we were able to communicate it.

Reza Hatefi - Decade Capital

On top of that I have to deduct the basis differential, which is like $5 or $10, is that right?

Paul Evanson

There is a basis differential going from the PJM Western Hub to the load, of course, from there to the generator. Those are some of the items including the other items that we really are not disclosing.

Kirk Oliver

You have the number right in terms of the size that the basis differential could be. If you go from $40 to $55, you'd get $15. There's a $5 offset to that because the basis and other items that we use to deconstruct the $52.50 in 2010, those items change going into 2011. That resulted in a $5 negative impact.

So you had a $15 impact at PJM Western Hub to Western Hub, '10 to '11, but then you had a $5 offset because of some of the other items that changed going from '10 to '11.

Reza Hatefi - Decade Capital

When you say some of the other items, are you also including the capacity going lower.

Kirk Oliver

Both of those were net of capacity. So those would have been things like basis and shaping and renewables and ancillaries and things of that nature.

Reza Hatefi - Decade Capital

So capacity is incremental to that?

Kirk Oliver

Capacity, yes, completely separate. We backed it out to do an energy-only comparison.

Operator

Our next question will come from Ivana Ergovic with Jeffries.

Ivana Ergovic - Jeffries

Just a quick question relates to generation. You said that you are going to have 30 million to 32 million megawatt hour this year. That last year is around 34 or bit more. So where is the difference in generation reflected, in which driver?

Kirk Oliver

It's in the market prices, hedging activity and generation volume driver. You can see there is a footnote there that tells you how much of the generation is open.

Ivana Ergovic - Jeffries

What would be the sensitivity in terms of a change on the 1 million megawatt hours of sales? How much would that impact your pre-tax margin versus last year?

Kirk Oliver

Well, that's a really hard and I'm not trying to be evasive, but it's very difficult to say, because if we lose megawatt hours, in general, those would tend to be the megawatt hours, where the margin that you make on it is lower. Because, obviously, those are the marginal megawatt hours.

That open position that you see is not all around the clock megawatt hours. In fact, almost all of that is off-peak. So what happens is we make assumptions for what we're going to do in 2009 based on running a model that simulates the marketplace and our plants in the marketplace, and then we run that again and the output will change.

So it's kind of difficult to just say, 1 million megawatt hours will have $X of impact. You can do that as a rule of thumb, if you want to, but you have to understand that that's a pretty rough way to estimate it.

Ivana Ergovic - Jeffries

What was the reason for the increased outages in the quarter?

Paul Evanson

The increased forced outages? Yeah, we had a very high rate in the quarter. I think it was actually 15%, which was extremely unusual to have this kind of performance, particularly given the progress we've made. There were a few special factors.

One, prices, particularly in some of those shoulder months, were very low. So we decided to take some and do some special maintenance work on three of the supercriticals. That constituted about 3% of that total.

Then we had some issues with one of our units at pleasant, where we've had a recurring vibration problem with one of the turbines. This and the unit 1 are the only two Siemens turbines we have. We had the identical problem recurring with unit 1 and we took it out on a major planned outage, worked on that extensively and that unit has been operating the last two years without a problem.

So we have pleasant unit 2 came down with a forced outage because of vibrations, but it's now in an extended planned outage. So, we expect to eliminate that problem going forward. The rest were kind of a mishmash of the usual suspects.

Ivana Ergovic - Jeffries

So you are still targeting 80% availability or is that going down?

Paul Evanson

It will be down in '09, because we have five tie-in outages on the scrubbers. Each one takes about three weeks. So that alone is close to a 3% planned outage factor. So it would bring our 87, if we were at that level, down to about the 84 level, plus or minus.

Last year, if you recall, was kind of the best year we ever had, 87.5%, which put us definitely in the top quartile of supercritical plants. Sadly, the supercritical grouping of plants, the benchmarking that we do over the last few years, the top quartile unfortunately has been coming down for all of the units. So while we've been going up, we've kind of now gotten into the top quartile at the 87.5.

Operator

Our next question will come from Gregg Orril with Barclays Capital.

Gregg Orril - Barclays Capital

Maybe this a bit repetitive, but I was wondering if you could update us on hedge position for 2010 and then just what your financial hedges are hedged at?

Kirk Oliver

Yeah, the financial hedges, there is a slide that shows you what those prices are at in 2009. Bear with me a moment and I'll pull it up here.

Gregg Orril - Barclays Capital

I was asking for the same information for 2010.

Kirk Oliver

Yeah, we're not giving 2010 guidance, but there are financial hedges in 2010. They're a much smaller amount than this.

Gregg Orril - Barclays Capital

The unhedged amount for 2010?

Kirk Oliver

In 2010, we're about 80% hedged by volume, so 20% unhedged.

Operator

Our next question comes from Paul Patterson with Glenrock Associates.

Paul Patterson - Glenrock Associates

I think most of the questions, I have, have been answered, but just a few things. The tax rate, it's now 39%. Is that correct? Is that what you're now expecting for 2009?

Kirk Oliver

For the balance of 2009, for the remaining three quarters, it's 39%. Then, of course, for this quarter, I can't call it a one-time, but we had the tax item on the Pennsylvania NOL.

Paul Patterson - Glenrock Associates

So, before it was 38%, I mean it's in the ballpark but that's what I think you guys were planning for 2009 longer term. Is your long-term tax rate expected to be the same or has that changed at all?

Kirk Oliver

Yes. You know I might have given you the wrong number. I think it is 38% for the last three quarters.

Paul Patterson - Glenrock Associates

Okay. 38%?

Kirk Oliver

Yes.

Paul Patterson - Glenrock Associates

Then just going forward, it's roughly going to be in that neighborhood.

Kirk Oliver

Yes.

Paul Patterson - Glenrock Associates

Then just finally on slide 25, cash flow from operations, what was the working capital impact on 2009, just obviously a big change there.

Kirk Oliver

There were two big items for working capital in 2009. One was coal inventory was up about $44 million, and then the other was a policy change at PJM, where PJM has you post collateral based on kind of the two months highest outstanding you have with PJM and they changed the way they calculate that to exclude the FTR credits.

That had a large impact on us, larger than it did on others in PJM because we tend to have a significant amount of FTR credits. So that resulted in us having to post more collateral. So the PJM collateral that that affected working capital, that was about $92 million, so that gets you close to $140 million working capital impact in the first quarter.

Paul Patterson - Glenrock Associates

Okay. So $140 million was the additional hit from working capital versus 2008, is that the way to think about that?

Kirk Oliver

Yes.

Paul Patterson - Glenrock Associates

Then I guess the FFO, I mean that's what I'm really trying to figure out. What would be funds from operations? Was there a big change there at all? I can wait till the 10-Q comes out, I'm just wondering.

Kirk Oliver

So you are saying you want FFO, which would define as before working capital item? I don't know if we've got that number.

Paul Patterson - Glenrock Associates

It's okay. We can do it offline. I was just wondering if you had it right there?

Kirk Oliver

So that would be about 235ish.

Paul Patterson - Glenrock Associates

So it's little bit higher than I think last year.

Operator

Our next question comes from [Jesse Laudon] with Zimmer Lucas.

Unidentified Analyst

In terms of the transaction in Virginia, the 215 million that you talked about for net plant, is that equivalent to a rate base number or would the rate base have been significantly different than that?

Also, related to that, you have a contract I believe to sell power to serve those customers during the next couple of years. Does this transaction have any impact on that power contract?

Paul Evanson

Well, the net book value of 215, there were two big deductions to get to rate base. One is accounts receivable of about $30 million, and then there are some deferred taxes of not being assumed of about $30 million, so that brings the rate base down to about $150 million total. This doesn't require or mandate or there won't be any change at all in the contract that's already for supply for that power. That stays in place.

Unidentified Analyst

The approvals you need are just Virginia and FERC?

Paul Evanson

We got another little oddball, which is West Virginia, because a few of the poles that are in Virginia actually have lines that go out to serve some customers in West Virginia, So in theory West Virginia then has to approve it also, but I would expect that one to be about as perfunctory as anything could be.

Unidentified Analyst

In terms of the outages that you were taking advantage of some of the power prices in this quarter, is there a significant amount of O&M in this quarter as a result of that and were these outages planned for later in this year or maybe next year that you're now not going to have to take as a result of this?

Kirk Oliver

The maintenance outages, I'd say, were smaller items. There would be some O&M in there. Net-net in the period it may be $3 million, $4 million. That would be the total for those.

Operator

For our next question, we will return to Neil Stein with Levin Capital for a follow-up.

Neil Stein - Levin Capital

Just on the $5 per megawatt hour of FTR basis, et cetera, that kind of runs against you or acts against as an offset to the energy uplift. Had that changed since February or was the calculation you gave on the February call related to a different period? I'm trying to understand specifically.

Paul Evanson

No. There wasn't in the February call, any period to compare it to in '11. What we were doing was taking the '10 numbers and decomposing those looking at basis and ancillary and everything else as of '10 when you actually had to bid at '11. Now, what we're really saying is $5 is the series of deltas between '10 and '11. That's why it could change.

Neil Stein - Levin Capital

So if we look at what these might have meant from a margin perspective back in February, you might have drawn the same conclusion that it was a negative $5.

Paul Evanson

No, not necessarily.

Neil Stein - Levin Capital

I'm just trying to figure out the amount of variability that we've seen over a two-month period and has it really been $5 per megawatt hours or was it here all along and it just wasn't discussed.

Paul Evanson

No. Obviously, the PJM price is very clear. The $5 is a series of items in '10 that brought the number down to $40 that gave you the $40 that you'd presume could be and should have been comparable to what you might get in '11 or future years. That $5 as I said in the next auction could be $3, could be $2, could be positive $3. There is a variation in it. I couldn't tell you what it's going to be in the June auction or in any future period.

There is some variability. We're not trying to eliminate that kind of variability. The biggest variability is in the PJM Western Hub and that's why we focus so much on that. The other item, as I say, is very difficult to discuss because some of them are critical in terms of the bidding process, and we only won three of five of those auctions.

Neil Stein - Levin Capital

Okay.

Paul Evanson

I'm sorry, two of five of those auctions. So, we really don't want to get into the details of what those items are and how we do it. Somebody else might do it quite a bit differently. Somebody else bidding might use different factors than we did.

Neil Stein - Levin Capital

Then what about hedging in between auctions? My understanding was I think you guys were trying to put in place a credit facility with a lien structure to facilitate hedging over a longer period of time? What's the status of that and could we expect you to do more hedging in between auction?

Kirk Oliver

Yes, I think you could expect us to start doing more in the status of that lien facility is, would I say it's in the two to three weeks away kind of range. I think we're at the point of addressing some technical issues between us and the counterparty on the facility.

Neil Stein - Levin Capital

Then once you put that facility in place, what could we expect? Should we expect during the next quarter, so the next time we get an update of a significant ramp up in hedging independent of that auction?

Kirk Oliver

Well, what we'll be trying to do is balance the inputs and the outputs is pretty much where we'll head within a range. So you should see the power volumes that we hedge approach kind of the coal that we've got locked in.

Neil Stein - Levin Capital

Okay. Which is around 50% or something like that?

Paul Evanson

They're all 3.2 million megawatt hours that will be out in the June auction if the commission approves it this month.

Neil Stein - Levin Capital

Then I think Gregg Orril asked the question on financial hedging that you've done in 2010, which you couldn't answer, but maybe a more general question. Is there any notable market contracts that might be in place that will expire by the end of 2010 that we should be aware of when we're thinking about year-over-year uplift in '11 versus '10?

Kirk Oliver

There is nothing material that's just rolling off at the end of '10. We do have the Virginia and the Maryland contracts that you're aware of.

Neil Stein - Levin Capital

The way we should interpret this inclusion of slide 31 is that that was a very notable item, potentially negative, we'll see where prices actually wind up, that you wanted to highlight, but there is nothing else of this magnitude that we should be aware of while we're doing our forecasts nor the next couple of years.

Kirk Oliver

That's correct.

Neil Stein - Levin Capital

In terms of power pricing.

Kirk Oliver

Yes, that's correct.

Operator

We will take today's final question from Greg Gordon with Citi.

Greg Gordon - Citi

Can you give us specifically what the CapEx reductions are to get down from the 1.12 billion, I wrote this down, so hold on. Let me go back. It was 1.129 billion in the K and you're now at 880, where the cuts come from?

Kirk Oliver

It comes from transmission. About $220 million of that is transmission and a big chunk of it, about $185 million is moving PATH out, and then there was about $30 million, $40 million of TrAIL that we moved forward to '09. Then is about $20 million of environmental that we reduced in '10.

Greg Gordon - Citi

So that should all add up?

Kirk Oliver

Yes.

Operator

At this time, there are no further questions. I will turn the presentation back over to our leaders for any additional or closing comments.

Paul Evanson

Well, thank you very much for attending our conference call. We'll be talking to you soon. Bye.

Operator

Thank you very much, ladies and gentlemen, for joining today's Allegheny Energy conference call. This does conclude your conference. You may now disconnect.

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