Allegheny Energy Inc. Q3 2009 Earnings Call Transcript

| About: Allegheny Energy (AYE)
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Allegheny Energy Inc. (AYE) Q3 2009 Earnings Call October 29, 2009 1:00 PM ET

Executives

Paul Evanson – Chairman, President and Chief Executive Officer

Kirk Oliver – Senior Vice President and Chief Financial Officer

Max Kuniansky – Executive Director, Investor Relations and Corporate Communications

Analysts

Daniel Eggers – Credit Suisse

Neil Kalton – Wells Fargo Securities

Ashar Khan – Incremental Capital

Gregg Orrill – Barclays Capital

Lasan Johong – RBC Capital Markets

Neil Steiner -Levin Capital

Michael Lapides – Goldman Sachs

Reza Hatefi – Decade Capital

Ivana Ergovic – Jeffries & Co.

Jonathan Arnold – Deutsche Bank

Philson Yim – Luminus Management

Brian Chin – Citigroup

Brian Russo – Ladenburg Thalmann & Co.

Edward Heyn – Catapult Capital

Paul Patterson – Glenrock Associates

Danielle Seitz – Dudack Research

Operator

(Operator Instructions). Welcome to the Allegheny Energy Third Quarter 2009 Financial Results conference call. 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 9 am on November 6 and you can listen to it by telephone, on our Web site or by podcast.

Some of our statements will be forward-looking. These statements involve risks and uncertainties and are based upon 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. The presentation includes some non-GAAP financial measures. On our Web site, 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

Okay thanks, Max and good afternoon everyone. Today, we reported adjusted earnings of $0.59 per share for the third quarter compared to $0.54 a year ago. Earnings growth in the period was driven by improved performance in our delivery segment.

For the third quarter '09, delivery earned $56 million as compared to a small pretax loss in the same period a year ago. This was largely due to improved recovery of purchased power cost in Virginia and increased revenues from our transmission expansion projects.

These results for delivery were achieved despite lower sales due to the weak economy. Total megawatt hour sales were down 4% from the prior comparable quarter with industrial sales down almost 9%. Our generation business continued to be hurt by the recession.

Although higher rates in Pennsylvania helped the segment, plant output was down sharply. While supercritical availability was about the same as in the third quarter of last year, the capacity factor was only 44%. This low level primarily reflected weak demand and low natural gas prices and also the planned outages at Hatfield for the tie in of the scrubbers and our favorable portfolio of coal contracts.

The price of electricity in PJM was down by about 55% in the third quarter compared to last year. But we were largely protected in the quarter by our hedges, including the Pennsylvania Polar contracts and financial hedges.

Natural gas prices for the period averaged $3.15 per 1,000 cubic feet versus $9.15 the year before. At that level, combined cycle natural gas plants displaced subcritical coal-fired units and while more difficult to measure at times displaced supercritical generation.

Our coal contracts however enable us to reduce deliveries under certain circumstances. As a result, we expect to defer or cancel deliveries of over 3 million tons of coal this year. This gives us the flexibility to run our plants only when economic to do so.

Now in this challenging economic environment, controlling costs and maintaining liquidity and financial flexibility are of critical importance. As you know, over the last six years, we have done an extraordinary job in controlling costs and improving quality.

After reducing O&M by about 40%, we have held these costs flat for four years now. While we've been driving cost out of the system, our operating performance continues to improve. We are on track to have the best operating and safety performance in the history of our T&D business, and we continue to rank very high in customer satisfaction surveys. That's what I call high performance.

On the liquidity front, we've made major strides forward in the quarter. Allegheny Energy Supply, our merchant generation company, raised $835 million of long term financing and put in place a $1 billion revolving credit facility. This greatly improves our financial strength and flexibility

Looking now at other business developments in the quarter, earlier this month, our regulated delivery business held its third auction in Pennsylvania to procure generation post 2010. For residential customers, the average retail generation price in that auction was $65.29 per megawatt hour.

This includes energy, capacity, gross receipts tax and line losses. We have now procured over 60% of the power necessary to serve residential customers in the state for the year 2011. Based on the results of the three auctions held so far, residential customers would see less than a 10% increase in their electric bills when rate caps expire. This should make for a seamless transition to market-based rates in Pennsylvania.

In that October auction, Allegheny Energy Supply won all the contracts to supply power. That's about 1.8 million megawatt hours of Pennsylvania, residential and small and medium commercial load. Also this month, delivery had an auction for its Maryland residential and small commercial and industrial customers.

Allegheny Energy Supply won all of those contracts. That totals about 1.8 million megawatt hours to be delivered primarily in 2010 and 2011. Now our goal was to hedge our generation output by the end of each year, 80 to 90% of the succeeding year, 30 to 50% of the second year and up to 30% of the third year out.

With the recent Pennsylvania and Maryland contracts and other recent hedging activities, we've now hedged about 87% in 2010, 27% in 2011 and 4% in 2012. We're likely to remain in the low end of these ranges to maintain our leverage to an economic recovery.

We've also made progress in hedging our coal position. We've now hedged nearly all of our coal needs at our merchant plants for next year at a cost of about $57 per ton. Switching now to our transmission projects, the Trans-Allegheny Interstate Line or TrAIL is on schedule for in-service in 2011. We have about 85% of the total property we need for the project under option or easement.

We're making progress on substation and line construction, and we received the final permits we needed to begin construction on the western portion of the Line in West Virginia and Pennsylvania, a major project milestone giving us now all the approvals needed for construction in the three states that the Line crosses.

We're also working on securing approval of a collaborative settlement for the Pennsylvania only reliability need. Now excluding that portion of the Line, our latest projection for total cost of the TrAIL project is now $850 million. In our Potomac-Appalachian Transmission Highline project or PATH, West Virginia just completed public hearings on the project and evidentiary hearings are now scheduled for February.

In Virginia, evidentiary hearings are scheduled for January. In Maryland, the Public Service Commission ruled recently that our application was improperly filed. The Commission found that our subsidiary, Potomac Edison may not seek authorization to construct on behalf of its affiliates.

Now that ruling did not address the need for the line but rather who the proper applicant was. We are optimistic we can work around this issue. On the environmental front, I'm happy to report that the two remaining Hatfield Scrubbers went into service in mid-October ahead of schedule and on budget.

The first scrubber went into commercial operation in early June, so all three units are now operating successfully. At the Fort Martin plant construction on the scrubbers for the two units is still progressing with a view to a year-end completion. We did however experience a problem on one of the large fans that could delay the in-service date for one of the units until spring.

This should not in any event have a material impact on cost or earnings. We still expect the project to be completed on budget. Now I'd like to make a few comments on some regulatory developments. In West Virginia, the Public Service Commission approved the settlement agreement earlier this month that allows securitization of the remaining $100 million in cost for the Fort Martin Scrubber Project.

Also in West Virginia, we filed in August for a $114 million increase in base rates. We have not had a base rate increase in that state since 1994 and we're under-earning significantly. About half of the amount requested relates to a net operating loss tax issue.

An evidentiary hearing has been set for March of next year. We think we have a solid position for our requested increase but the proceedings will be challenging given the commission's previous stance on that tax issue.

In Pennsylvania, we filed the plan in August for the implementation of smart meters in the state. It calls for investment of nearly $500 million over the next five years for new meters, communication equipment and a customer information system.

Pennsylvania Act 129 provides for a surcharge for recovery of these costs. We also received regulatory approval for our Energy Efficiency and Conservation Demand Response Programs in both Maryland and Pennsylvania. We'll be rolling out these programs shortly.

Regarding the sale of our Virginia territory, the State Corporation Commission recently scheduled the hearing for March 2nd, but we now expect to close this transaction early in the second quarter.

At the federal level, the Senate Committee on Environment and Public Works is now holding hearings on a draft climate change bill known as the Kerry-Boxer Bill. This bill is reasonably similar to the Waxman-Markey Bill that passed in the House, but a number of important provisions still need to be debated and finalized in the committee.

Then, the bill must be considered by certain other Senate committees, including the Finance Committee. My sense is that it's very unlikely any legislation will passed this year. So in summary, we made solid progress on meeting our goals and priorities in the third quarter.

Unfortunately this progress is being overshadowed by the economy and its impact on PJM. While there are some signs the economy is recovering, we're planning on 2010 being another challenging year for us. Based on today's forwards, we expect little or no growth next year.

Power prices of course can change and they do change rapidly and sharply as economic conditions change. Most of us believe we're at the trough of a cycle. As we move through the next cycle, Allegheny is very well-positioned to benefit from an economic recovery.

Finally, Kirk will now present our outlook for 2010 using an enhanced framework of financial disclosures. Our prior format, which focused on drivers of growth served us well for a number of years. But as we move toward a more market-oriented business model, a new disclosure framework is more appropriate.

I want to thank many of you who shared your thoughts and ideas on how we could improve our financial disclosures. We think you'll find this new format much more helpful. With that, let me turn the call over to Kirk.

Kirk Oliver

Today we report a GAAP net income of $77 million for the third quarter of 2009 compared to $89 million a year ago. Earnings were $0.45 per share compared to $0.52 in the same period a year ago.

Adjusted earnings for the third quarter were $0.59 per share as compared to $0.54 per share for the third quarter of last year. Adjusted earnings exclude net unrealized losses associated with hedging activities and $19.3 million of expense associated with the debt tender offer.

We completed another tender offer in October and we will have a similar adjustment in the fourth quarter. For the nine months which ended September 30th, earnings were $1.57 per share on an adjusted basis compared to $1.79 per share last year. Despite the effects of the recession our adjusted earnings increased in the third quarter.

I'd like to summarize some of the key factors that impacted the increase in adjusted pre-tax earnings. The first two items on Slide 31 benefit our delivery and services business. The Virginia increase of $38 million reflects increased purchase power cost recovery as a result of our settlement last year.

We continue to make progress on our transmission expansion projects. Year-to-date we've spent $340 million, which resulted in a $13 million quarter-over-quarter increase in pre-tax earnings. With respect to our unregulated business, higher generation rates in Pennsylvania improved revenue by $43 million.

Our Pennsylvania generation rates increased nearly 20% on January 1st of this year. In January 2009, residential customers in Maryland moved to market rates for generation. This benefited pre-tax earnings in the third quarter by $23 million following the methodology we used when we first quantified our 2009 earnings growth drivers.

Our marketing and financial hedging activities largely protected us from a significant decline in market prices, which were down about 55% at the western hub year-over-year. Lower generation output and market prices, net of the benefits in our hedge position and increased capacity revenue reduced margin by $82 million.

Higher coal prices at AE Supply increased pre-tax income by $12 million. Our fully delivered coal price increased by about $6.00 to $56.00 per ton. We also experienced higher adjusted interest expense and lower T&D revenues, which were offset by positive items including the benefit realized on Kern River Gas Pipeline strategy in the quarter.

In total, pre-tax earnings adjusted for unrealized gains and losses were $160 million, which was a $23 million increase over last year. Our effective tax rate this quarter was 37%, which compares to 33% for the same period a year ago. The rate was lower in 2008 due primarily to tax benefits associated with audit adjustments.

Cash flow from operations was $262 million after adjusting for the tender offer premium payment in the quarter and includes a $38 million pension contribution. Capital expenditures were down $320 million.

Free cash flow netting the securitization proceeds used to fund the Fort Martin scrubbers and project financing for TrAIL was a positive $107 million for the quarter. Making the same adjustments for the full year 2009, we expect to have negative free cash flow of $25 million to $75 million.

We have adequate liquidity to support the business and our hedging objectives, and we have recently taken steps to further strengthen our balance sheet and liquidity. We have extended our debt maturities raising nearly $840 million of 10-year and 30-year financing and repaying about the same amount of near term debt maturities in 2011 and 2012.

We have also strengthened our overall liquidity position, replacing our $400 million revolving credit facility at Allegheny Energy Supply, which was expiring in May 2011, with a $1 billion revolving credit facility maturing in September 2012.

We now have access to over $1.7 billion of total corporate liquidity. Furthermore, we expect to receive approximately $340 million on closing of the Virginia asset sale next year and to raise about $100 million at Mon Power through incremental securitization in December.

Now let's turn to the outlook. I would like to highlight the earnings drivers for 2009 that have changed significantly from our last call. Our estimates are based on, among other things, forward power prices at September 30, which for the balance of 2009 were $37 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 now expect pre-tax earnings from transmission expansion to be $40 million.

Capital expenditures for TrAIL are expected to be over $450 million for the year, which is about $180 million more than we expected coming into the year. During an intense effort to reduce O&M expending, we expect approximately flat versus 2008, excluding discovery-related expenses and after adjusting for expenses recovered in formula rates.

This is down $20 million from the last call. Coal prices are now expected to adversely affect earnings by $75 million for the year, a $25 million improvement compared to our last call. As Paul mentioned earlier, we continued to defer purchases of high-cost coal into later years.

We also have been able, in some cases, to eliminate purchases of high-cost coal due to reduced burn at the plants. The interest expense driver is a negative $30 million, which is $10 million better than we expected on our last call. We completed our refinancing at lower interest rates than we had originally projected.

This driver excludes premium payments associated with tender offers in the third and fourth quarters.

Market prices, hedging activities and generation output are now expected to reduce earnings by $90 million more than our estimate on the last call. A combination of lower generation output, lower market prices and lower polar demand was partially offset by our hedge position.

Western Hub prices for the second half of the year are down about $4 per megawatt hour from the last call. Generation output for the year is now expected to be down about 7 million megawatt hours, compared to last year, which is about 3 million megawatt hours below what we were expecting at the time of the last call. Later, I'll give you further detail on market prices and hedging for the full year of 2009.

Today we're providing our first outlook for 2010 and as Paul has already mentioned we're also introducing a new framework for our earnings' drivers. We feel that this new approach will facilitate a better understanding of the factors that drive our operating results and values.

We separate the operations into three businesses, merchant generation, which includes our own regulated generation business, utility operations, which include our state-regulated T&D operations, and Mon Power's regulated generation business and transmission expansion, which consists of TrAIL, PATH and other PJM projects.

We show EBITDA for each of these businesses based upon market information as of September 30, 2009. Again, these estimates are based upon a number of highly variable factors including market prices and other commodity inputs, load forecasts and other factors impacting plant dispatch. As a result, our estimates will change frequently. Going forward, we intend to update this information on a quarterly basis only.

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 for rate base for a number of years. Depreciation, interest expense and other items will be shown on a consolidated basis.

Column one on this slide reflects our 2009 estimates, while column two reflects our estimated increase or decrease in pre-tax earnings in 2010, over our 2009 results. We'll now go through these drivers line-by-line.

Moving to slide 38, merchant generation, we estimate an $8 million increase in 2010 EBITDA. As the following slides will show, this increase is driven by growth in our un-hedged energy margin due to projected increases in price, volume and capacity revenues. These increases are offset substantially by a contraction in the benefit from power hedges.

Slide 39 summarizes, among other things, what we include in un-hedged energy margin, the contribution of capacity, other revenues including ancillaries and operating expenses, bringing this down to un-hedged or open EBITDA.

We first reflect estimated generation volumes, which are derived from an industry-standard dispatch model. Estimates of generation volume are based upon various inputs, such as forward commodity prices, estimated costs and our unexpected plant outages, volumes in 2010 increase over 2009 due to increased dispatch of our coal units given higher forward power prices.

To estimated un-hedged energy revenues, we start with around-the-clock pricing at the PJM Western Hub, which is the most commercially relevant trading hub for our business. We then adjust this price to derive the bus bar price at our power plants. This basis differential results from transmission constraints between our plants and the western hub.

The realized energy price includes this basis differential and a premium for shaping, which reflects the fact that our plants run more when prices are higher. The $164 million forecasted increase in un-hedged energy margin is primarily due to an increase of $4 per megawatt hour in realized energy prices, partially offset by increased fuel costs.

Coal expense reflects the forecast tons of coal burned at our delivered coal price. This includes coal at contracted prices and the estimated delivery cost of our open coal position. We're also reflecting our estimated cost of other fuels as noted on the slide.

Forty-nine million-dollar increase in capacity is due to a $23 per megawatt-day increase in capacity prices. Operating expenses, primarily O&M and state and local taxes will decrease by about $2 million and are subtracted from un-hedged net revenues to get to un-hedged EBITDA.

Adjusted EBITDA is calculated on slide 40, by starting with un-hedged EBITDA from the prior slide and adjusting for the impact of our power hedge position. These hedges include financial hedges, marketing contracts and polar contracts, including the west pin polar load, which expires at year-end 2010.

Margin contribution of these hedges has contracted, impacting adjusted EBITDA by $225 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 September 30.

On slide 41, we're showing additional information you might find useful in modeling our merchant generation business. The generation volumes on this slide are based upon market information and other factors as of September 2009. And as mentioned earlier, will change every time we update our projections as forward market prices and other inputs change.

As previously noted, we intend to update this information on a quarterly basis only. Coal prices and volumes reflect estimates as of September 30. The past few revenues reflect the actual results of PJM auctions, which are held annually to determine kit capacity prices three years out.

On slide 42, we're providing you with forward market pricing data as of September 30. 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 43 provides a high-level estimate of merchant generation's pre-tax income sensitivity to commodity price moves. Please note that the sensitivity for realized energy prices adjusted for volumes consumed at Bath.

These are simplified calculations where each sensitivity is derived while holding all other variables constant. Everything we have shown you up to this point has been as of September 30. As Paul has already noted, since that time, supply has entered into some additional contracts, which are summarized here.

Moving on to slide 45, utility operations, please keep in mind that we are including the regulated generation business of Mon Power in these results. EBITDA for utility operations is estimated to grow by $60 million Please note here that the West Virginia Rate Case driver reflects the full amount requested in the case based on an assumption that the increase is granted mid-year.

We requested an annual increase of $114 million of which $52 million relates to full recovery of income tax expense. We expect to incur capital and operating costs in 2010 for Pennsylvania Act 129. We expect these costs to be passed onto customers formulaically and we will earn a return on our investment that is expected to increase EBITDA by $10 million.

Recovery of securitized interest and depreciation related to the Fort Martin scrubbers and the remaining West Penn securitization is being reflected at the EBITDA level. While this benefits EBITDA, it does not affect earnings because they're offsetting impacts in depreciation and interest.

Despite additional costs attributed to Fort Martin scrubber operations, O&M expense that are not formulaically recovered are decreasing by $8 million reflecting the company's cost reduction efforts.

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

Slide 46 shows estimated growth in the rate base for utility operations. Please note that these are estimates only and our plans are always subject to change. Our transmission expansion EBITDA will continue to grow as we invest in the TrAIL and PATH lines.

We are now projecting Allegheny's share of spending for this business to be about $500 million for 2009 and $400 million for 2010. The rate base in our transmission expansion business is expected to grow to over $2 billion by 2014. We earn a return in this business as capital expenditures are made. TrAIL is expected to be in service in mid-2011 and PATH is expected to be in service in 2014.

Depreciation will increase in 2010 due primarily to the scrubbers coming online in the second half of 2009. Transmission expansion, smart meters installed pursuant to Pennsylvania Act 129, and Fort Martin scrubbers will increase depreciation but will not affect earnings because these items are recovered through formula rates.

The outlook for capital expenditures is reflected on this slide. Spending in the merchant generation business will decline after the Hatfield Scrubber is completed this year. Utility operations business will substantially complete spending on the Fort Martin scrubber this year.

We expect to spend about $340 million through 2011 for infrastructure and software investments driven largely by Pennsylvania Act 129 and we also anticipate continued investment in transmission expansion.

Moving back to the income statement, interest expenses is estimated to increase by about $100 million year-over-year. Fifty-six million is for transmission expansion and will not affect earnings because it's 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. As Paul has already shown, we expect O&M excluding amounts recoverable under formulaic rate making to be 10 million better than 2009.

And finally, while not reflected here, we expect our effective tax rate to be 38% for 2010. Due to a large first quarter charge, our year-to-date tax rate in 2009 is about 40%. With that, I'll turn the call over to the operator for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Dan Eggers – Credit Suisse.

Daniel Eggers – Credit Suisse

Kirk, maybe just a little clarification for all of us could be useful. If we were to go to the slide 41 and we look at, just to make sure we understand the definitions, the contract price versus the estimated market value, what is the breakdown in those numbers? Is that going to be energy plus ancillaries pre-capacity or it looks like that's a pre-capacity revenue number? Is that fair?

Kirk Oliver

No, that's loaded up with everything in it that's in the contract. So that's got capacity, shaping, ancillaries, basis, everything is in there. Basically, the estimated market value is basically what the replacement value for the contract would be on September 30th.

Daniel Eggers – Credit Suisse

And then the percentage utilization or how are you guys allocating out the dollar per megawatt hour of value capacity revenues? Are you just taking the targeted 34 terawatt hours of output in 11 and dividing it in the capacity revenue and putting that number into the price per megawatt hour?

Kirk Oliver

What we tried to do, Dan, was to make it simpler. When we provide service through a contract, a full requirements contract, we have to provide the capacity so we charge for the capacity, but then we get paid by PJM for capacity.

So what we've done is we've broken the capacity out in a separate driver, which is shown – we show that on the bottom of slide 41 what the capacity is doing. And then in the contracts basically we're getting paid by our customer for the capacity but we're paying PJM for the capacity, so the capacity eventually washes through but it's showing here in the pricing.

Daniel Eggers – Credit Suisse

The basis you guys show at $8 in 2010, are we more effective to look at AD Hub versus PJM West as a more representative hub for your generation, and how does your generational price from that zone for your plant's dispatch?

Paul Evanson

We've talked in the past so much, Dan, about the PJM Western Hub really because it's just a much deeper, much more liquid trading hub, and of course it's next to where our load is and very close to the AP zone load.

But as you know, there's meaningful transmission constraints and congestions at times between our plants and the hub, so those basis differentials can grow and widen depending on a lot of things. So whereas, the AD Hub, the AEP-Dayton Hub has much less constraints between our plant and that hub, electrically, there's just not a lot of constraints, but, the problem is it's not really a robust trading hub.

It does about one-tenth of the trading in the early years as the PJM Western Hub, so since it's much less liquid, the price is much less reliable as you move out in time. So while it may be a better indicator of our prices it's much less reliable looking forward.

So I think you've got to look at both. We do, and what we've done in here is kind of played through that basis differential and plug the number in that we think represents, in some ways, how the forwards are in time between those two hubs.

Kirk Oliver

The other thing, Dan, just to make sure you're clear on is the $8 also includes shaping, so it's basis and shaping together.

Daniel Eggers – Credit Suisse

And the shaping should be a net positive for you guys, correct?

Kirk Oliver

That's correct.

Daniel Eggers – Credit Suisse

So the basis would then imply that your basis at PJM West is probably more like $10 or $12 in that number? Is that ?

Kirk Oliver

Yes, that's in the ballpark.

Daniel Eggers – Credit Suisse

Just one last question, as you guys look out to '11, '12 with your TrAIL getting lit up if on target, how are you guys modeling the look in basis because you're going from three to eight is a pretty big number.

Paul Evanson

Yes, that basis should clearly narrow over time. There's no doubt about that, and I think it's reflected, to some degree, in the forwards already but, it probably, I think, over time should be reflected even more.

Operator

Your next question comes from Neil Kalton – Wells Fargo Securities.

Neil Kalton – Wells Fargo Securities

Just a question on slide 41 again on the coal contracts, looking into 2011, you've hedged, I think, 67%. How should we think about the open position? What kind of coal price should we be using? I think on slide 42 you provide both the mid SO2 and high SO2. Should we skew that more toward the mid-SO2 or how should we think about that?

Paul Evanson

I'd skew it a little bit more to the high SO2 because now we'll have scrubbers on all of our major supercritical units at that point, and of course, these are broker estimates. They're kind of the best thing we could put down here but coal is quite a bit unique, as you know, so it won't necessarily work out as simply as this slide might suggest.

Neil Kalton – Wells Fargo Securities

Okay and then separately in terms of the Kern River pipeline, I believe that's providing pretax earnings of about $30 million a year annually, that rolls off in 2011. How should we think about that roll off in 2011? Should we assume that all of it goes away or a percentage goes away?

Kirk Oliver

Thirty million is about the right number to assume rolling off in '11 and that shows up – if you're trying to figure out where that number is, it's on slide 39 in other net revenue, that's where Kern River is right now.

Operator

Your next question comes from Ashar Khan – Incremental Capital

Ashar Khan – Incremental Capital

I just want to just make sure I'm doing this. If I go to slide 39, Kirk, is this telling us that the un-hedged EBITDA, that means if the situation was totally open as of September would have been 576 for the company.

Kirk Oliver

For '10, for 2010, yes.

Ashar Khan – Incremental Capital

For 2010.

Kirk Oliver

Yes.

Ashar Khan – Incremental Capital

And then if I go to slide 40, what we are going to achieve in 2010 in our projections is 545, is that correct?

Kirk Oliver

Yes, that's correct because we have a lot of 2010 locked up already.

Ashar Khan – Incremental Capital

So we have done pretty well I guess current prices then are pretty reflective of our actual earning position in 2010, is that a fair statement?

Kirk Oliver

I think what you're saying is what we've got locked in is pretty close to what the market prices are, so we end up getting close to what the sort of totally open power price EBITDA would be even with all the stuff we have hedged in. If that's what you're asking, I'm trying to answer your question.

Ashar Khan – Incremental Capital

Yes, that is what I was asking. Okay and then if can just –

Paul Evanson

Market price, Ashar in the 10s, right, in the '10 forward price, not today's price.

Ashar Khan – Incremental Capital

Then if I can just – because you give us '11 and all that, so if I can use the same framework that you provided on slide 39, can I just – if I was to, for my own theoretical modeling purposes try to figure out '11, can I just substitute from what you've given September 30 data for the $48 and put in the 5144 and I guess coal costs would be something else and all that. But would that be the framework to use, that the upside is going from $48 to $51 if I was to do an '11 un-hedged EBITDA calculation on this on a rough basis?

Kirk Oliver

That's exactly what we've tried to allow you to do here is in fact we've been using the word framework ourselves. We've been trying to set this up so that you can make your own assumptions on some of the key items beyond where we provide guidance and calculate your own numbers. So yes, you're absolutely correct.

Ashar Khan – Incremental Capital

But then, Kirk, if I do the same thing for coal because you're showing coal is contango it's going up from '10 to '11 and if the capacity's going down, what this is implying that the generation business as things stand today and of course they can change, based on September 30 is going to have no increase in EBITDA from '10 to '11.

Paul Evanson

I wouldn't necessarily conclude that, Ashar. I mean, there are some other – you'd have to estimate basis in there and what some of the other movements are, but I think you have the information to calculate it.

Ashar Khan – Incremental Capital

But, Paul, how much basis can we expect go down between '10 and '11?

Paul Evanson

Well, we're not giving the '11 guidance here. We're giving you the tools and the information for you to make we hope a more intelligent estimate of it. And frankly when you look out to '11, the biggest variable in our earnings will be obviously that PJM Western Hub price, I mean that's the forward today but that can change dramatically. And then that's where your judgment comes in.

If we looked at June '08, the forwards for '09 were $90 for '09 and they're coming in averaging $39, so six months before those forwards were way off and personally I think the forwards will change a lot depending on what you think the economic recovery is or may be in '11 and '12.

Ashar Khan – Incremental Capital

No, I agree with you.

Paul Evanson

That data you'd have to factor in but if you just take the forwards there, you'll do whatever you'll do.

Ashar Khan – Incremental Capital

No, no I was just – I agree with your analysis in terms of going forward but I was just thinking from the data that you have provided, if you just put the numbers in you come out to – assuming if assume the basis is similar, you don't see any pickup. Of course we can put in whatever prices we want, but from the data that you've provided, it provides as if there is not much pickup in EBITDA from '10 to '11 from the data that you provided, which is of course September 30 data.

Paul Evanson

Yes, well I think you'd see some but not a huge amount.

Operator

Your next question comes from Gregg Orrill – Barclays Capital

Gregg Orrill – Barclays Capital

I had a couple of questions, just going back to one of the earlier questions about the emission prices and just to confirm that out in 2011 that you would be a net seller at that point of allowances.

Kirk Oliver

SO2 we are long, Knox we are not long but we're not very short either, I guess would be the way I'd answer that.

Gregg Orrill – Barclays Capital

Okay, so that doesn't sound like a material outcome either way.

Paul Evanson

No, we have a sensitivity on page 43 that it says if prices double from what they are, it's about a $1 million to $2 million in '11 and '12. No big deal one way or the other.

Gregg Orrill – Barclays Capital

Kirk, you also talked about the coal prices on page 42 there as not being representative of what you would contract for. What did you mean there?

Kirk Oliver

Well these are basically – we went out and got some broker estimates so that we could give people some guidance on the coal market. But these are for certain coals, we buy certain coals for our plants depending on what kind of coal they like to burn, where they're located, what the transportation is, and we do long-term contracts, we don't buy on some brokerage exchange.

So coal's kind of a funny commodity, it's not like natural gas or electricity. There are a lot of different kinds of coal and a big part of the coal is the transportation. So what we're trying to say is these are brokerage estimates and that's pretty much what they are when we negotiate for a coal contract, we'll get something that's different than what these numbers are.

Gregg Orrill – Barclays Capital

That might be a few dollars or more lower.

Kirk Oliver

It could be lower it could be higher depending on the plant and the transportation, etc.

Gregg Orrill – Barclays Capital

Then on Act 129, I wasn't clear if that was actually an earnings contributor in 2010 and I guess whether it would be in 2011.

Kirk Oliver

Yes, it is. We give you – for 2010 we give you the EBITDA for 2010 for Act 129, what our estimate is anyway. And then I think Paul on one of his slides, I can't remember exactly which one, shows you kind of what the investment is for Act 129, so you can kind of hone in on it. Max is saying that slide's not in here. That'll be at [EEI], I'm sorry, I got ahead of myself.

Paul Evanson

Well, page 45 shows a $10 million contribution and then if you go back to the depreciation page, it's like $2 million of depreciation, so it's like an $8 million net pickup in '09 for Act 129. And it'll increase going forward as the spending goes on and we'll present that later I guess the details by year.

Gregg Orrill – Barclays Capital

Okay and last one, Paul, you commented that you'd held the O&M pretty constant for the last four years. What's that look like going forward? Is that kind of over at this point?

Paul Evanson

Well we always try to hold it flat and do a little better if we can, and I think the targets we're trying to set for '10 is to keep that flat again, so we'll do the fifth year flat.

Operator

Your next question comes from Lasan Johong – RBC Capital Markets.

Lasan Johong – RBC Capital Markets

Paul, I've got a strategic question for you. The generation business hasn't been treating you too well over the last 18 months and it doesn't look like it's going to be treating you too well in 2010 either. Obviously as you've pointed out when and if the market recovers you're going to probably see a pretty big jump in that business but that kind of contravenes the stability of your cash flow and earnings PAR from your utility business. You have any thoughts around kind of strategically what you want to do with that generation business?

Paul Evanson

Well first of all as you probably know, Lasan, I like the idea of three balance business the distribution, the transmission and the generation and the cash flows in the [line] are a lot more stable but the other ones that we've seen in the past and even next year I mean the open EBITDA is more than $0.5 billion on current flow so that's not so shabby in and of itself.

So I kind of like the balances of the businesses. At different times there are opportunities to invest in different ones of those businesses. Now we're putting a lot of money into transmission and maybe more some into that Act 129 and there will be a time I think generation will also have that attractive profile for us and we've been looking at some things in that regard.

But I think we could clearly get better and bigger if we had more scale in generation. I think we could manage that very well but I think we do a good job running the business and I'm happy with that business and it's making money and I think it's got a tremendous upside potential for us.

Lasan Johong – RBC Capital Markets

I agree with the upside potential. Did I just hear you right that you are potentially looking for assets to add to your generation mix?

Paul Evanson

Well I said over time.

Lasan Johong – RBC Capital Markets

Over time.

Paul Evanson

Over time. Yes I don't think today is the time to do it given still the uncertainties in the financial markets and the economy but I think over time that's a business we'd like to grow in.

Lasan Johong – RBC Capital Markets

One quick question, more administrative, on the coal looks like there is about 2.1 million tons of deferred coal and you said it was relatively high cost which is why your expectations for coal is down $25 million in terms of cost. When are you obligated to take delivery of those tonnage and what kind of pricing would that have and how would that affect your future margins?

Paul Evanson

Well we've pushed off most of that under the contracts. Some that we could cancel for sure are gone. Others that are the higher cost that we've pushed off we'd probably have to take in '10 and I think in the last call I said that's why '09 would be down a little bit and '10 would be up a little bit from where we thought.

But in addition since then we've priced maybe 2 million tons of additional coal and that we were already contracted for that was unpriced and then we've also optimized some of the movement in transportation of that coal so that's why you end up with the number that we show in there, I think, it's 57 for next year. We were thinking it was going up to 59 but I think we have it back down a little bit now.

Lasan Johong – RBC Capital Markets

So that reflects 100% of those deferred tonnages coming back?

Paul Evanson

Generally, yes.

Lasan Johong – RBC Capital Markets

So then if we have a low gas price environment next year does that mean you have to defer more tonnage next year as well? Or can you take the deferred tonnage that you deferred from '09 to '10 and defer it again from '10 to '11?

Paul Evanson

You can take – it wouldn't necessarily be those tons specifically but yes you could. We have rights under our contract to defer from what the expected take would be so I think we'd have some flexibility next year even having exercised some already this year. And as I said in the chart we did totally cancel over a million tons so we have that flexibility going forward.

Operator

Your next question is from [Brendon Navy] of Levin Capital.

Neil Steiner -Levin Capital

It's actually Neil Steiner at Levin Capital. I have some more clarifying questions on page 41 some of them were redundant if I could. The first is this contract price so that's a full requirements price that you've actually contracted out that includes capacity and energy and all that.

Kirk Oliver

Yes.

Paul Evanson

Yes.

Neil Steiner -Levin Capital

What is this estimated market value and how does that relate to the contract price?

Kirk Oliver

What we did, Neil, is we September 30 if we would priced these contracts out with the market prices that existed on September 30th for forwards, etc. that's what that amount represents. So it's effectively the replacement cost of the contract.

Neil Steiner -Levin Capital

Would it be – is it the right way to think of it if we're thinking of the 80% of unhedged output that you have for 2011, you think you could get $61 per megawatt hour for it, at least at September 30th prices if it were a full requirements contract? Of if you were selling a full requirements product?

Kirk Oliver

Well you can't really – that's kind of oversimplifying because in that 6.8 million megawatt hours that are hedged some of that is full requirements and some of it is financial. So that's a blend of pricing.

Neil Steiner -Levin Capital

So some of it is energy only and some of it is forward moving?

Paul Evanson

Really kind of a hodge-podge.

Kirk Oliver

And there's basis in there as well.

Neil Steiner -Levin Capital

Yes but the estimated market value – okay that's for all the same – that's for everything that's contracted just mark-to-market at the end of the quarter?

Kirk Oliver

Right.

Paul Evanson

Right. So on an identical basis as the contract price.

Neil Steiner -Levin Capital

And then when we think about the capacity revenue forecast at the bottom of the page I guess some of that is probably double counting with what you're showing at least for where you're hedged at for 2011? To the extent that you're including the capacity decline in the extent you have some forward requirements products bundled into your hedge portfolio?

Kirk Oliver

No, Neil, it's not because what happens is the capacity that we price into those contracts basically nets out. We have to provide – we are the ones who are providing the capacity to the customer so we charge the customer for it but we have to pay PJM for the capacity so if you think about it the capacity just kind of nets to zero on the contracts and then we've shown you here then what the total capacity payment we get from PJM is for the capacity we make available for PJM.

Operator

Our next question is from Michael Lapides – Goldman Sachs.

Michael Lapides – Goldman Sachs

Two unrelated ones I apologize the first to be quick follow up on page 41 if I just take the $63 a megawatt hour in 2011 what's the energy component embedded?

Kirk Oliver

We are – it's a mish mash of a bunch of different contracts so there's not one energy component.

Michael Lapides – Goldman Sachs

Is there a weighted average or kind of a rough estimate that you could provide?

Kirk Oliver

If we wanted to do a lot of work I think we could probably calculate a number, but we're not going to be doing that.

Michael Lapides – Goldman Sachs

Would it be something that's dramatically different than the energy component that you publicly disclosed when you've given detail after the Pennsylvania auctions?

Kirk Oliver

For Pennsylvania no, but this has got Maryland and Virginia and financial and munis and you name it – it's got a lot of stuff in there so but what we've shown for Pennsylvania is that it would be a good approximation.

Michael Lapides – Goldman Sachs

Second on PATH so unrelated a little bit. What's your level of concern regarding delays in PATH and how do you kind of alleviate those concerns if any?

Paul Evanson

Well I'd say there are two levels of types of concerns. I'm not sure if you're asking about one or both but one is the approval process by the three states and one is just the absolute need for it. And I think on the absolute need some people have thought – some people who normally oppose these kinds of things have started to question well, we've created demand response and the economy as weak as it was maybe there's not – the need isn't as pressing but I'd say – and we'll be hearing that for some time.

And I think the only thing to rely on there is the PJM RTEP process that they went through it a few months ago and said yes, we still need PATHs. It still has those same violations. It has to be cured. And I think unless you think the economy is really gone into a real relapse I think they're going to continue to demonstrate that so we have questions about it but I think the need is really there.

And the second is the approval process and we had – we're filed into three states that is required. We're filed in all three. Maryland we had a little setback in the sense that the PSC decided that we didn't use the right applicant technically to file it.

We did it on Potomac Edison our Maryland Company on behalf of its affiliate the TrAILCo Company. But as I said, you really can't do that on behalf of someone else. You have to do it yourself. And that other company has to meet the rules of Maryland law.

So we've been, and other states now have kind of questioned if Maryland's not going to do it what does it mean? But I think we are clearly focused on dealing with that issue. I don't think Maryland of all places needs the power one, talk about need, and two it's going to drive down prices in Maryland. So you'd think they'd be the last folks to stand in the way of this project.

So I think we're going to be able to work ourselves through that. We have similar alternatives from discussions with them, and I'm reasonably optimistic that we'll get through that. I'll just say finally in our transmission projects, you get opposition every step of the way from a lot of different folks for a lot of different reasons. And that's just part of the territory that you got to go through to get these things approved.

Michael Lapides – Goldman Sachs

If it's delayed a few months, how much wiggle room is there before it would actually impact the, I guess it's the capacity market auction for 20, what is it, 2014, 2015 for the auction being held in '11?

Paul Evanson

How much impact would it have?

Michael Lapides – Goldman Sachs

No, how much wiggle room do you have in terms of in-service dates before it pushes out the impact of PATH into the next auction?

Paul Evanson

I wouldn't be able to guess that at this point.

Operator

Your next question comes from Reza Hatefi – Decade Capital.

Reza Hatefi – Decade Capital

Just a couple of questions. I don't know if you mentioned this earlier, but could you talk about the timing of TrAIL and PATH and how the projects are going? And what is the latest expectation for online time for each of those projects?

Paul Evanson

Well, TrAIL, I think I covered that a bit in my opening comments. It's going along very, very well and we're slated for a June '11 in-service date, and I'm very confident we're going to meet that. PATH is slated to June 2014 and we've got to get through this approval process, and that's what we're all focused on now. I mean, we're doing some preliminary work. But really, we're focused intensely on getting through the three states that we need to be on that schedule.

But based on the schedule and the speed at which we're getting TrAIL done, I think if we get PATH done reasonably – I mean, this is only nine, we have five years from now and we're already kind of a year ahead of TrAIL in a way. So I think if we get those approvals in the year period plus a little bit, we still can make that June 14 date.

Reza Hatefi – Decade Capital

Just also a clarification question on slide 39 where you have the coal expense, that's not an open coal. That's your hedged plus whatever is open at the open price, correct?

Kirk Oliver

That's correct.

Paul Evanson

In '10, yes.

Operator

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

Ivana Ergovic – Jeffries & Co.

Just a quick question related also to the call on slide 39. So basically you're combining the un-hedged and hedged portion in terms of pricing to get to the $764 million in 2010?

Paul Evanson

Yes.

Ivana Ergovic – Jeffries & Co.

What do you use for the un-hedged numbers? Should we assume that you're using more higher SO2 coal once you start covers in 2010 or what would be the good mix?

Paul Evanson

Yes. We'll move a little bit more to higher sulfur coal and we have some estimates in there on that.

Ivana Ergovic – Jeffries & Co.

Yes, because you have both estimates and there is like a $10 difference, so that's why I'm asking [inaudible] better one to use?

Paul Evanson

Well, the high and the mid, you could probably skew it more toward the high. But we do use some of the mid sulfurs. We can do 25/75, something like that if you wanted. It's not going to make a big difference.

Ivana Ergovic – Jeffries & Co.

Another thing, that [CR] volumes, in 2010 you are assuming they're going back to almost normal versus how they were back in 2008? I think Exelon said that they think they would need like five years to get back to their 2007 or '08 numbers. So I was just wondering how come you think you can pickup from this year so quickly to go back to normal?

Kirk Oliver

Well, I didn't listen to Exelon's call, but they may be talking about their load in their utility businesses, which is a little different. This is basically how much we think our plants will dispatch based on the prices they see in PJM. So when prices are higher and we're just using what the forward prices are, then our plans, our economic to dispatch and they dispatch and this is the output you get. We use a standard industry model to derive that number. So that's kind of how we come to it.

Ivana Ergovic – Jeffries & Co.

Just another quick thing, the differential of $8 per megawatt hours, that's an average differential over next couple of years? I mean, I know this year is really much lower. But if you look at the previous years, there's an average and how come you come up with this number?

Kirk Oliver

You mean the basis and shaping number?

Ivana Ergovic – Jeffries & Co.

Yes, the $8.

Kirk Oliver

Yes, that basically as Paul mentioned earlier, that represents an estimate of the difference between the Western hub and what our plants see in terms of price and then plus some premium in there for shaping. So our plants are not at the Western hub note, so we don't see the Western hub price directly. And as Paul said earlier, a way to estimate that difference would be to look at the AD hub. And then you can compare the AD hub to the Western hub to kind of estimate the basis that our plants see.

Operator

Your next question comes from Jonathan Arnold – Deutsche Bank.

Jonathan Arnold – Deutsche Bank

A quick question on just your un-hedged position on the power side, how long would you leave these numbers kind of way below your targets? And could you imagine a scenario where you were still very little committed on 2012, say a year from now, for example?

Paul Evanson

Well, for starters, I mean we're not well below them for where we expect to be the end of this year. Our target's 80 and 90 for next year and we're right in the middle of it, 30 to 50 the second year and we're at 27%. So we're pretty close to hitting it and the last year isn't much, 0 to 30. But I think as we move through '10, all the years shift one and we'd like to get by the end of '10, '11 to be the 80, 90 and '12 to be the 30, 50.

And as I think I probably suggested in the call, we're probably shooting for the lower end of these ranges because of I think the skewing more to the up than the down side on how the futures may go. So no, I think we just think it's right to approach those targets and that's what we intend to do during the year.

Jonathan Arnold – Deutsche Bank

You'll stick with the targets but be flexible within the range basically.

Paul Evanson

Exactly. Yes, and at this side be on the low end of those ranges.

Operator

Your next question comes from Philson Yim – Luminus Management

Philson Yim – Luminus Management

If you were to continue to win load in the Pennsylvania power options, how should we think about those margins versus what you would get just serving flat ATC prices?

Kirk Oliver

Well, we don't like to give out margin information for obvious reasons. But where we bid on that load, the Pennsylvania load, we have FTRs that make us whole for any kind of basis risk, which we don't get when we bid on – when we do a financial contract. So I think that's probably the primary difference that you need to be thinking about.

Philson Yim – Luminus Management

But maybe we could take maybe the last, the third option that just completed as an example. I guess that was – you had indicated was $53 kind of energy price?

Kirk Oliver

Yes, I think that's right.

Philson Yim – Luminus Management

And PJM West prices were like $53 also?

Paul Evanson

PJM Western Hub at the time of the auction was 53.

Philson Yim – Luminus Management

But we should subtract – we should really be comparing that to what you guys would see at your plants which would be $10, $12 lower than that?

Kirk Oliver

Well, $10 lower that's just the basis. You have to add shaping to that number and then you have to add in any kind of risk that we might price in for customers switching and other things and then also we put a margin into those bids. So the 53 is really just the starting point.

Paul Evanson

Were you asking would we rather win in an auction than do a financial hedge?

Philson Yim – Luminus Management

Yes, I guess so.

Paul Evanson

Yes.

Philson Yim – Luminus Management

One other question related to any other rate cases you guys may be filing in other jurisdictions?

Kirk Oliver

We don't have any plans yet. We're watching. We're definitely under earning in West Virginia. We're fine at Potomac and in Pennsylvania we're keeping an eye on it, we're closer. So it will kind of depend on how our numbers shake out over the next couple of years in Pennsylvania.

Philson Yim – Luminus Management

Can you say what you're earning in Pennsylvania?

Kirk Oliver

Yes, we're earning about 10% in Pennsylvania and our allowed there is 11.5%.

Operator

Your next question comes from Brian Chin – Citigroup.

Brian Chin – Citigroup

For the basis and shaping, is that net of firm transmission rights or not, and am I thinking about that the right way, that firm transmission rights should be reflected somewhere on slide 39.

Kirk Oliver

The FTRs are in our hedge contracts. They're not in the basis and shaping at all.

Brian Chin – Citigroup

The FTRs you count them as being part of your hedges but if I understand it right you guys get assigned FTRs on an ongoing basis by PJM, right?

Kirk Oliver

The loads get the FTRs so West Penn gets FTRs and then when we win the load, we bid in for the – we buy the FTRs when we win the load. So we have to price those into the contract but then they provide us with protection against any kind of change in basis.

Brian Chin – Citigroup

And then I know that this was asked earlier, that the coal expense includes both hedged and un-hedged. Why wouldn't you show the coal expense as totally open to the market?

Paul Evanson

Well, that's a great question and we thought about doing it but there's so many unique elements to the coal, different qualities of coal, different needs of particular plants, transportation because it's an important element that it's pretty tough to – and we think our coal portfolio is really advantageously structured. But maybe we're short changing ourselves, but we decided just to use what our actual is rather than trying to put some hypothetical number that's very difficult to calculate.

Kirk Oliver

Having said that, I mean I think we've given you enough information that you could actually calculate it that way if you wanted to. Right, I mean we give you how much of a hedged and then we kind of give you some brokerage estimates for what market would be if you wanted to use some sort of market and calculate an open, a more fully open number.

Operator

Your next question comes from Brian Russo – Ladenburg Thalmann.

Brian Russo – Ladenburg Thalmann & Company

On slide 41, what's driving the decline in year-over-year terawatt hour sales in 12 versus 11?

Kirk Oliver

There's some higher plant outages in 12. So that is some of it and then a little bit of it is just what's going on with power prices versus the assumptions we have in there for coal prices.

Operator

Your next question comes from Edward Heyn – Catapult.

Edward Heyn – Catapult Capital

I wanted to just circle back, not to belabor Ashar's point, but I wanted to make sure that I was understanding the slides correctly. And in on slide 39, you talk about the open EBITDA in 2010 for the un-hedged EBITDA, it looks like your 34 terawatt hours if you look at the open market, is moving up about $3 a megawatt hour or about $100 million in margin.

Is it correct that offsetting that is going to be $100 million down in capacity prices? This kind of goes to what [Neil] was asking too about his capacity getting double counted. But I mean if I assume that basis is flat and that fuel prices are flat is basically EBITDA going to be flat on an un-hedged basis too?

Paul Evanson

Well the capacity number of 305 and 406 if you go back to page 41 you can just insert the 308 in the 11 column. So that $100 million is a reduction in 11 that's coming and you have a three buck increase at the Western Hub before basis.

Edward Heyn – Catapult Capital

So those two kind of offset each other, and then I guess for the hedges you can say that on page 41 it also says that you've hedged $14 million in the money right now. So you would kind of add that to the open 11 to get a kind of an earnings power if you were to mark everything as of the end of the quarter.

Kirk Oliver

That's pretty much how you would do it, yes.

Edward Heyn – Catapult Capital

The other question was just on the PATH line. I know Maryland has said you need to re-file. How do you address that and then how are you – what kind of gives you comfort that's going to get moved forward at some point?

Paul Evanson

Well, there are several alternative structures that I think accomplish what we want to do namely get that project going, but we're in discussions with the staff and others and I don't think it'll be appropriate for me to go into those suggestions on the call. So reasonably good about it, given as I say the objectives that both parties have on this. They're not trying to kill the line as I've tried to make clear.

Edward Heyn – Catapult Capital

So it seems like it's more of an administrative thing and the view from the parties aren't necessarily against the line so you think you can work around it.

Paul Evanson

Well, that's how we look at it and I think that's the objective for Maryland to state, so I'm hopeful we're going to be able to work through it.

Operator

Your next question comes from Paul Patterson – Glenrock Associates.

Paul Patterson – Glenrock Associates

On page 41 if I were to look at the power hedges, it looks to me that there would actually be a $45 million delta between 2010 and 2011.

Paul Evanson

Yes.

Paul Patterson – Glenrock Associates

Okay, and then on the contract prices of coal, is that including transportation?

Kirk Oliver

Yes.

Paul Evanson

On page 41 on the other page 42 it's not.

Paul Patterson – Glenrock Associates

Right, so we're going to see some of that's going to obviously offset – there's going to be an increase in fuel costs that would offset that to a certain degree. Let me ask you this, O&M for 2011, can you guys keep it – I mean is there any deferral of O&M or expenses that we should sort of be thinking about going on here?

Paul Evanson

They're a lot of elements to O&M. No, there are very few items that were just pushed off from one period to another. I mean it's a constant challenge to try to keep that O&M flat and you really have to just improve productivity. And as I tried to say in the beginning, the real trick is to do that while you're increasing the quality of service to customers and we've been able to do it for the last four years. We're really focused on doing it next year and I don't want to get the organization too upset to say I think we can do it in '11. So I'm not going to say that yet.

Paul Patterson – Glenrock Associates

On slide 45 just to quick a clarify there. I think you had said that you have the PEVA sale I think you said that it actually might be a non-impact. Could you just clarify that a little bit?

Kirk Oliver

Yes, what you see there it looks like a pretty big number, that's an EBITDA number, right, for PE Virginia sale. And some of that for accounting purposes we had to stop depreciating that because those assets are held for sale. So if you work it down to – and there's also some corporate allocations that we had to back out. So I think on a prior call Paul said that the earnings associated with those assets was

about $10 million – ballpark of $10 million.

Paul Evanson

After tax.

Kirk Oliver

After tax. So if you work that all down – if you take the allocations, etc --

Paul Patterson – Glenrock Associates

I understand what you're saying. What you're saying is it flows through different elements that you guys have already given in terms of the guidance.

Kirk Oliver

Right.

Paul Patterson – Glenrock Associates

Right. I got you.

Kirk Oliver

You assume kind of a debt rate. If you use the proceeds at a debt rate, it's about breakeven. If you use them out of whack it's actually accretive.

Paul Patterson – Glenrock Associates

And the West Virginia rate case, you guys are planning on 100% recovery of that because of the tax issue? You think that you're going to get good treatment on that?

Paul Evanson

Well, no. What we've done is put in there the full amount of the request. It's the kind of thing you either put in the full amount or you put in nothing. It's hard to say. I'm asking for $114 but I think I'm getting $77. You can't put that in. So you either do one or the other and we just put the full amount in and say the tax issue is going to be a challenging issue. We're hopeful on it. We think we have a good case, but that's a challenging issue and great cases are always challenging.

Operator

The next question is from Danielle Seitz – Dudack Research Group.

Danielle Seitz – Dudack Research Group

Just a quick one, what would be the major factor to change your estimates in terms of the total generation for 2010? Is it basically gas prices would change that number?

Paul Evanson

Power prices, yes.

Danielle Seitz – Dudack Research Group

Okay. I just was wondering. And the number that you have here is based on the assumptions you make below.

Paul Evanson

Yes, they're based on the forward as of September 30th.

Danielle Seitz – Dudack Research Group

Yes, okay.

Paul Evanson

All of them, yes.

Danielle Seitz – Dudack Research Group

Thanks and the other quick one is that which of the two transmission lines would have the most positive impact on margins or basically your business?

Paul Evanson

Boy, that's a tough question Danielle. We love both of those lines. I mean, what we like about TrAIL is gee, it's more –

Danielle Seitz – Dudack Research Group

Not from a point of view of return on the investments that you are making but more from point of view of easing the passive power to –

Paul Evanson

Oh, you mean easing the transmission congestion?

Danielle Seitz – Dudack Research Group

Yes

Paul Evanson

Well, the first one in is going to have the biggest impact and PJM once estimated that it relieved 80% of the congestion on a major congested line [benefiting] the blackout line, which is our line. So they said 80% of that congestion would be relieved by TrAIL. So in terms of that impact, that's the most important.

Danielle Seitz – Dudack Research Group

And how does that translate into your EBITDA numbers or into any of your profit margins? Does is translate into something really easily measurable?

Paul Evanson

Well, it will be very helpful because it will reduce the basis between our power plants and the PJM Western Hub and even further east than that. So that's that basis we were talking about earlier. That's the deduct now that, hopefully, will be contracting over time, particularly as that line is completed.

Danielle Seitz – Dudack Research Group

Is the impact already in the numbers that you are assuming into 2011 or no?

Kirk Oliver

Well, to the extent, it's reflected in the forward prices. So the folks who are out there making a market in forward prices or are pricing that in, then it's reflected, but it's – we can't really tell how much of it is.

Danielle Seitz – Dudack Research Group

Okay. No, I just thought that you knew. Thank you very much.

Operator

The next question is from Daniel Eggers – Credit Suisse.

Daniel Eggers – Credit Suisse

I just wanted to come back and get a little more clarification on this. If I look at the mix of your generation fleet obviously the Pennsylvania assets on the west side of the hub are a big piece of it, but going back and looking at my numbers, it's about 10 terawatt hours a year produced either for in Virginia or Maryland. Are my numbers correct to start with?

Kirk Oliver

I don't have it by terawatt –

Paul Evanson

Do you mean how much of the production comes from --

Daniel Eggers – Credit Suisse

About a third.

Paul Evanson

From those states?

Daniel Eggers – Credit Suisse

Yes. Or that would be serving the traditional utilities in Maryland and Virginia.

Kirk Oliver

I think the – if you're asking about basis – I'm not sure you are – but I think that the supercriticals are all pretty much sitting closer to the AD Hub.

Daniel Eggers – Credit Suisse

Well, they're west, but if I look at the total output of generation that you guys have on an annual basis it give 33 to 34 terawatt hours a year. Not all of that is sitting west of PJM West Hub at a $10 to $12 a megawatt hour basis negative position. And if you look at it you sold 1.8 terawatt hours into Maryland in October.

So obviously you were selling generation on the other side of the hub, for sure, that I feel like we're respectively overstating the amount of generation that's being sold at a big wide discount to the PJM west forward. Is that a fair interpretation?

Kirk Oliver

I don't think it is because we don't contract to deliver electrons out of our plants to certain loads. I mean, we're selling into the market. You think of the electrical markets you almost have to think of putting something into a lake and someone else is taking it out of the lake somewhere else. We can't – the electricity flows the way it flows. We don't deliver electricity from one plant to one load.

Daniel Eggers – Credit Suisse

Understood, but I guess geographic location of a chunk of your fleet is going to be notably further east than west.

Kirk Oliver

Yes, but I think if you look at the base load plants where the bulk of the generation is, it's mostly west and much closer to the AD Hub.

Daniel Eggers – Credit Suisse

Okay. I'll follow up with you guys then.

Kirk Oliver

We can do a little more detailed work on that if you'd like, Dan, and take you through it.

Operator

(Operator Instructions). The next question is from Lasan Johong – RBC Capital Markets.

Lasan Johong – RBC Capital Markets

Paul, just another strategic question, can you take your experiences in PATH and TrAIL and migrate that to, I don't know, somewhere in California or Texas where there's [quick] congestion that needs to be relieved?

Paul Evanson

Well, I think the skills and capabilities that we have and are developing are transportable. In fact, we're probably the first guy and the only guy building a line as big as TrAIL is, but whether we'd want to move to California and Texas and take opportunities there, I'm not so sure.

I think there are other opportunities that we're working on within our own region, within PJM where there's a lot of need for transmission, not only because of congestion but because of renewables. I think there's opportunities there and we're looking at working on ways to try to expand that transmission footprint, but I'm not – I wouldn't think we'd necessarily be headed to that far afield.

Lasan Johong – RBC Capital Markets

Last question I have is more tactical. Over time, eventually, the generation that's being kind of basically shipped east along your PATH and TrAIL corridors are going to be needed in the local territories. How is that going to affect the economics of PATH and TrAIL? Am I thinking about this totally in a wrong way?

Paul Evanson

Well, I mean, both of the projects are built and approved solely for reliability. I mean when PJM goes through this they're not so much looking at the economic impacts or the pricing impacts, they're looking at reliability violations and exposures and it's on that basis that they authorize both TrAIL and now PATH and one or two other lines.

So I mean, they look at it solely from reliability. There are a lot of secondary results on what it does to pricing. You're saying what does it do to demand, growth, etc.? But we haven't, at this point, we haven't focused so much on that as maybe we want to get that line built as soon as we can – both of them.

Lasan Johong – RBC Capital Markets

So you're saying it's kind of not subject to obsolescence at some point?

Paul Evanson

The line? No, I don't think so. No, I think given the extraordinary difficulty of building generation in states such as Maryland or some of the other eastern states, the idea of bringing power from the Ohio River Valley is I think going to continue to be essential.

Operator

The next question is from Ashar Khan – Incremental Capital

Ashar Khan of Incremental Capital

Hi, I just wanted to go on the rate case slides on slide 48 and I guess 50 for, I guess, the back up to this transmission expansion. If I'm right, Kirk, the way I'm looking at it, TrAIL is nearly all done by 2010 in terms of CapEx in 2011 it's basically, am I right, it's majority of it nearly all of it, the big push up is because of PATH, is that correct?

Kirk Oliver

Yes, TrAIL goes into service in the middle of '11, so TrAIL should be kind of winding down in '11 and –

Ashar Khan of Incremental Capital

Do you have how much of TrAIL is in '11, approximate?

Kirk Oliver

Yes, it's about $110 million in 2001.

Ashar Khan of Incremental Capital

Okay and then PATH, this picks up right? Then the remainder would be – the 620 would be the remainder would be – like $500 million of PATH then?

Kirk Oliver

Yes.

Operator

Gentlemen I have no further questions in the queue. Would you like to make any closing remarks today?

Paul Evanson

Well, I would just like to thank everybody for joining us and next week, Sunday through Wednesday, Max, Kirk and I will be down in sunny Florida and would love to meet with as many of you as we can. So we look forward to seeing you. Thanks so much for joining us today.

Operator

Thank you, gentlemen. This concludes today's conference. Thank you for attending the Allegheny Energy third quarter 2009 financial results conference call. You may now disconnect.

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