賓州電力 (PPL) 2006 Q1 法說會逐字稿

Good day, everyone, and welcome to the PPL Corporation's first quarter earning release conference call.

Today's call is being recorded.

For opening remarks and introductions I would like to turn the call over to the Investor Relations Director, Mr. Tim Paukovits.

Please go ahead, sir.

Thank you.

Good morning.

Thank you for joining the PPL conference call and first quarter results and our general business outlook.

We are providing slides of this presentation on our Website, www.PPLweb .com.

Any statements made in this presentation about future operating results or other future events are forward-looking statements under the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995.

Actual results may differ materially from such forward-looking statements.

A discussion of factors that could cause actual results or events to vary is contained in the appendix to this presentation and in the Company's SEC filings.

At this time, I would like to turn the call over to Bill Hecht, PPL's Chairman and CEO.

Thank you, Tim.

Good morning.

With me today are Jim Miller, PPL's President and Chief Operating Officer;

John Biggar, our Executive Vice President and Chief Financial Officer; and Paul Farr, Senior Vice President, Financial.

This morning PPL reported first quarter 2006 earnings and our press release and the appendix to today's presentation material provide you with some detailed information about reported earnings and earnings which exclude the effect of unusual items.

Our remarks this morning will focus on earnings from ongoing operations.

The items we plan to discuss on the call include the following: First, a review of our strong first quarter 2006 earnings results; secondly, the increase in our 2006 ongoing earnings forecast; next, our long-term compound annual growth rate and earnings per share of 11%; opportunities and challenges for '07; our strong dividend growth and dividend growth opportunities beyond 2006; and a financial outlook including cash flow and balance sheet information.

Today, we announced a significant increase in first quarter earnings for 2006 of $0.70 per share.

Now, that is an increase of 30% when compared to the $0.54 per share that we reported for the first quarter of 2005 for ongoing earnings.

This is exceptional performance, we think, and is one of our best quarters ever.

It resulted in significant part from our ability to capture increasing margins and the improving wholesale energy markets.

But importantly, we saw very strong financial performance from all three of our business segments.

Both the supply segment and our international delivery segment each achieved a 31% increase in earnings per share, and the Pennsylvania delivery business achieved a 25% increase in earnings per share.

Now, based on that solid first quarter performance, we also announced this morning an increase in our 2006 earnings forecast.

Our new forecast for this year for ongoing operations is $2.20 to $2.30 per share.

That's a $0.05 increase, up from the previous increase of $2.15 to $2.25 earnings per share.

The 2.25 midpoint of the new forecast is about an 8.2% increase over our actual 2005 core earnings of $2.08 a share.

It is important also to note that we're increasing the '06 forecast despite a significant potential reduction in earnings from our synfuel operations.

In other words, we've taken the most conservative path with regard to synfuels when we created the new 2.20 to 2.30 earnings forecast.

And that also includes the effects of potentially higher replacement fuel costs for purchases from synfuel from third parties.

In other words, we have two elements to our synfuels benefits.

One is the production and sale of synfuels, the other is the purchase of synfuels for use in our own facilities.

And we've made conservative assumptions about both of those.

For '06, we're forecasting synfuel earnings of only $0.05 per share and that's $0.12 less than we realized in '05.

So despite that reduction in synfuel earnings, we're raising our forecast.

We're not issuing revised 2007 forecast at this time, but we do expect earnings per share growth despite a conservative assumption for '07 that the Company will realize no synfuel benefits next year, due to high crude oil prices.

As you know, synfuel tax credits phase out at higher crude oil prices and we're making the conservative assumption that synfuel tax benefits are not available in '07.

So despite the loss of the synfuel benefits we're forecasting growth.

In the event that we are able to realize any benefits from the synfuel tax credits, above the amounts now included in our forecast for this year -- $0.05 and for '07, zero -- that would be upside to our earnings forecast, and I know that some are forecasting synfuel benefits and including that in your guidance.

We're not.

In addition to increasing the '06 earnings forecast today, we're also reaffirming our forecast of a compound annual earnings growth through 2010 of 11%.

That 11% growth rate in earnings per share through 2010 is based on our 2005 earnings from ongoing operations of $2.08.

That's the baseline from which we're calculating that 11% compound annual growth rate.

The long-term forecast for 2010 is earnings per share of $3.50 and that remains unchanged.

And I want to emphasize at this point, as we have discussed in the past, that we will not have a rate check issue at this company in 2010, okay?

As we've discussed if the past, the forecast is based on visible growth, known quantities, not projections or extrapolations.

It incorporates our year-end 2005 view of 2010 forward energy prices, fuel and emission allowance prices, fuel transportation costs, and all other costs associated with operating this business.

And importantly, we have already started to make sales for 2010 at those prices, as well as making some longer-term fuel supply arrangements.

Now, I want to reemphasize that -- a lot of question about rate shock.

As many of you know, at the end of 2009, our stranded cost recovery expires.

And at that time, so does the Company's existing affiliate agreement for POLR supply, and that also expires, and at the end of '09, the Utility will be going to the market to purchase energy for its POLR contracts, and our competitive or emergent generation will be selling at the market.

Some of the market sales may be to an affiliate, some may not.

Our forecast doesn't depend on that.

Importantly, we will not have a rate shock issue in 2010.

There are ways to deal with the modest rate changes that will be required.

Furthermore, that forecast doesn't depend on further scarcity being reflected in energy or capacity prices.

That would be upside.

For example, PJM has been -- and its members, have been working with FERC for some time on so-called RPM reliability pricing model.

Other pools have tried to deal with capacity in other ways.

New England, with locational installed capacity.

Any material change in capacity markets would be upside to the forecast we've provided.

And of course, underlying forces like rising fuel costs and especially declining generation reserve margins over time in PJM, combined with anticipated construction cost for new base load generation, and the lead time to construct new base load generation, all suggest that 2010 energy prices could well be substantially higher than current market prices.

And certainly substantially higher than the current prices received by PPL Energy Plus under its POLR contract with the affiliate PPL electric utilities.

The forecast you see on this slide also excludes the effect of any asset acquisitions that we might make or greenfield development that we might make in a generation market that increasingly shows signs of scarcity in the out years.

We do continue to actively pursue opportunities that would provide benefits to share owners and in pursuing those and considering those opportunities, we look pretty closely at our ability to hedge the production from any assets, but none of those new facilities are included in this forecast.

Although each of our businesses did contribute to the success in this quarter, and importantly, we do continue to see, as we've said before, the supply business as the growth engine over the remainder of this decade, and the chart you now see has been updated to incorporate the strong first quarter and our current margin forecast for '06.

Again, at this time, we're not issuing a new 2007 forecast, so the margins that we have in that year have not been revised at this point.

As I said earlier, our growth drivers are very visible, and they are summarized here.

Starting this year, with the scheduled 8.4% increase in POLR prices, supply margins show steady and sustainable growth through 2010.

There are periodic increases in our POLR prices through 2009 that are built into our rate structure and built into our settlement agreement from the late 90s with the Pennsylvania Commission.

And those increases in POLR prices will add margin growth over that period, independent of what the remainder of the competitive markets show for growth.

There are other margin drivers as well.

The remarketing of expiring fixed price supply obligations, other than the affiliate, with higher margins at wholesale energy contracts, will provide greater margins for the unsold generation from our power plants.

The new contract opportunities include a number of full requirements bids like the New Jersey BGS contracts and sales in the Pacific Northwest that we would anticipate to layer in or are in the process of layering in now with the expiration of contracts with Northwestern Energy in mid-2007.

And as I said, we are layering in contracts post '07 in the Pacific Northwest out of our Montana plants as we speak.

An increase in capacity for our low cost nuclear and hydro generation by about 270-megawatts in 2010 also is helping to drive our supply business gross margins.

We also anticipate improved generation availability during that same period, and again, that is based on a hard business plan and a great deal of technical work that includes shorter generation maintenance outages.

So we have a great deal of confidence in that higher generation availability.

Our growth margins also include revaluing the output of our PJM fleet in 2010 at marketing prices, as I've been describing as the POLR contract expires at the end of '09.

It is important to reemphasize the forecasted increases in fuel, fuel transportation, environmental costs, and other costs of running the business, are reflected in that forecast and to the extent liquid markets exist, we've been hedging those costs.

And now, I would like to turn the call over to Jim Miller and he will discuss our results in more detail for the first quarter.

So, Jim?

Thanks, Bill.

Good morning, everyone.

Let's review in a little more detail our first quarter operating results as well as the 2006 earnings forecast.

Bill did mention that all of our business units contributed to the significant increase in earnings per share from ongoing ops compared to a year ago.

Looking at slide seven, it really highlights the earnings drivers for the supply business segment in the first quarter.

Supply earned $0.34 a share in earnings in the first quarter of 2006.

Now, that is a 31% increase over the $0.26 per share earned in the first quarter of '05.

Higher earnings were principally driven by higher energy margins, both in the East and in the West.

In the East, Bill mentioned our 8.4% increase in generation prices under our current affiliate contract with the electric utility, and as well, higher wholesale prices, as well in the New England power pool, and we've seen some benefits there.

They were offset, of course, by some higher coal and coal transportation prices.

And eastern energy margins were also positively impacted by some unrealized gains from our new forward contracts for wholesale energy and related services.

Out in the West, the increase in earnings were principally driven by higher average sales prices, and we're seeing higher hydro output currently in the West.

The $0.01 per share increase in synfuel earnings is primarily due to the unrealized gain on oil options purchased to hedge the risk associated with our synfuel tax credits for '06 and '07.

That was partially offset by lower tax benefits due to the anticipated phase-out of the Section 29 tax credits.

These positive earnings drivers were partially offset by higher O&M in the first quarter of '06 as compared to a year ago, principally due to higher costs for both planned and unplanned power plant outages.

Let's move over to Pennsylvania Delivery segment earnings drivers.

In the first quarter, delivery business segment earned $0.15 per share in earnings from ongoing ops compared to $0.12 per share earned a year ago.

Now, that's a 25% increase in per share earnings.

Increase in earnings in this area is primarily due to expenses incurred by PPL electric in the first quarter of 2005 to restore service to customers as a result of a series of ice storms that affected our service territory last January.

PPL electric did defer a significant portion of these expenses in the third quarter of 2005, and after we received the PUC accounting order, and we'll request recovery of these costs in the next rate proceeding.

Moving to International Delivery, that business segment earned $0.21 a share in the first quarter of '06, a 31% increase over the $0.16 a share earned a year ago.

The increase was principally the net result of higher delivery margins in the U.K. and Latin America, and lower taxes which were partially offset by the negative effect of some foreign currency exchange rates.

We're increasing our -- as Bill mentioned, we're increasing our forecast in 2006 earnings from ongoing ops from 2.15 to 2.25 to a range of 2.20 to 2.30.

And that 2.25 midpoint of the revised forecast, again, is nearly an 8% increase over 2005.

For slide 10, you're looking at highlights of the major drivers of our 2006 earnings.

An increase of $0.20 a share as a result of our increase in our generation prices under our POLR contract; an increase of $0.17 a share, primarily due to higher average wholesale prices in 2006; higher expected generation; and these benefits are partially offset by higher fuel and fuel transportation costs, including some higher costs to replace synfuel purchased from third party producers for our company's coal-fired plants.

And we also anticipate significantly lower synfuel earnings in 2006.

In 2005, synfuel operations provided us about $0.17 a share, which included the benefit from full production at our facilities and the unrealized gain on oil hedges that we put in place to hedge our synfuel tax credits.

Our previous 2006 forecast included earnings of about $0.10 a share for synfuel.

Due to the rising oil prices since the beginning of '06, as well as higher current forward prices for oil, we now expect about $0.05 per share from synfuel earnings in 2006.

We continue to expect higher O&M due to higher domestic and international pension costs, and inflationary increases throughout the organization.

We've all known that 2007 would be the last year for synfuel earnings.

Due to high oil prices, the reduction in synfuel earnings may be occurring sooner.

As I've already stated, we now expect earnings to contribute about $0.05 in 2006 compared to $0.17 a year ago.

Despite the decline in the earnings, we expect 2006 earnings from ongoing operations to be significantly higher than '05.

This increase will come from our higher energy margins and our supply business, and increased earnings in our international delivery business.

Let's look at per share earnings from ongoing ops by the segments. 2006 reflects an increase from our Supply business segment, driven by the factors I've outlined.

So we continue to expect our Supply business segment to account for about 57% of our per share earnings from ongoing ops, with the remainder roughly split between our Pennsylvania and our international delivery segments.

Although we're not issuing a revised 2007 forecast, as Bill mentioned, we do expect earnings from ongoing ops to grow in 2007, despite the synfuel situation.

Contributions from either of these items would increase the growth in 2007 earnings further.

That being said, we look now at 2007 earnings to really be driven by the expiration of fixed price contracts, some of which we expect to replace with higher margin wholesale contracts.

PPL continues to be an active participant in the basic generation service auctions throughout the Northeast;

Connecticut, New Jersey, Delaware, et cetera.

An increase in gen prices under the POLR contract as well, with our affiliate, will affect positively 2007 earnings.

There will be some offsets.

As I've mentioned before, we will see some increased fuel and fuel transportation costs.

Lower earnings, somewhat lower earnings, from our delivery business segments due to inflationary impacts.

Now, moving over to our construction program, environmental construction program on scrubbing our coal plants, we're really pleased we're making excellent progress on the scrubbers and we're currently well ahead of schedule.

We obtained these permits early.

They allowed us to get construction in the ground early.

And our costs are holding to budget.

We've updated our business case for more current market prices for SO2 allowances, which has been recently trading in the 6 to $800 per ton range, as compared to $1,400 a ton at the beginning of the year.

Even at the reduced market value of these allowances, scrubbers will still generate an estimated savings of over 40 million a year versus buying allowances.

These savings continue to reinforce the economics for the scrubbers, and we think we're well ahead of the pack from a construction and commercial operation standpoint in bringing these scrubbers online.

The next slide updates you on our mission allowance position through 2010.

And it reflects the real length we expect to have as our scrubbers go into service in 2008 and 2009.

Our forecast, as well, of allowance positions does assume a move to burning higher sulfur coal after the scrubbers go into service.

So it is important to notice that the positions in 2008 through 2010, the lengths you see in those positions, those allowance positions, reflects the consumption of increasing quantities of high sulfur coal.

Even after reflecting the use of these allowances to cover that higher sulfur coal, you can see we're well positioned to realize further economic benefits from the scrubber investment.

We will really obtain them in two ways.

It gives us the ability to purchase the most economical coal, whether it is high or low sulfur, and we have the ability to sell the length in our emission allowances into the open market.

Thanks for your attention.

I will now turn things over to John Biggar, who is going to review cash flow, strengthening balance sheet, and dividend growth.

John?

Thanks, Jim.

Good morning.

Reflecting our solid earnings performance in 2005 and our forecast for strong growth going forward, we increased the dividend rate on our common stock twice in 2005, and once in 2006, by a total of $ 34%.

The most recent increase was the 10% increase that was effective with the dividend paid April 1, bringing the annualized rate to $1.10 a share and bringing our dividend payout ratio to 50% of the $2.20 per share low end of our revised 2006 forecast.

Our future dividend action is, of course, subject to approval by the Board.

We expect the growth rate of our dividends over the next few years will continue to exceed the growth rate in our earnings per share and will result in a dividend payout ratio of about 50% after 2006.

In response to feedback we received from a number of you, you will notice that we've included a cash flow statement in the earnings release that was issued this morning.

Our cash flow is expected to improve over the next several years.

As we've noted before, there are essentially two components to our cash from operations: There is the portion that is dedicated to transition bond maturities, which averages about $300 million annually through 2008, when those bonds are fully retired; and cash available to meet our corporate needs.

We see significant improvements in cash available to meet corporate needs as we go out through 2010, driven by the POLR price increases that Bill and Jim have talked about, the additional 270-megawatts of capacity that's planned for our existing generating facilities as well as improved power plant availability.

As we've mentioned before, in 2009 we continue to recover stranded costs from customers with no offsetting transition bond maturities.

And by itself, that is about a $200 million after-tax improvement in cash from operations.

We're also -- the exploration of long-term supply contracts, including the Northwestern energy contract in Montana in mid-2007, and the POLR contract in Pennsylvania at the end of 2009, and as Bill already detailed, this provides an opportunity for us to re-market our supply at the higher price that is indicated by the current forwards.

Now, let's take a look at how that translates into free cash flow for PPL.

Free cash flow will be under some pressure in the 2006 to 2008 time frame.

But that's not surprising, with the major capital expenditure program that we have over the next three years, which is really divided into three -- what I call three major categories: sustenance CapEx, which allows us to comply with general regulatory requirements and to maximize the value of our low-cost generation and achieve increased availability and capacity factors; discretionary CapEx, which is really justified by strong project economics, such as the economics we see behind the 270-megawatts of planned power upgrade projects that we've talked about; and then environmental expenditures, which are primarily for the scrubbers being installed on our Eastern coal-fired generating plants, which are economically compelling.

These expenditures represent about a third of our total capital expenditures during the three years, 2006 to 2008, and then decline dramatically in 2009 and '10.

We expect our free cash flow to turn positive in 2008, as our environmental CapEx program begins to wind down, and to improve each year through the end of the decade.

We continue to strengthen our credit profile while maintaining a solid liquidity position.

In this regard, PPL has available credit capacity of about $3 billion under its $3.6 billion of bank credit facilities.

Looking at our capitalization ratios, GAAP equity was 40% at March 31 of this year, up from 36% a year ago, and we expect that ratio to get stronger, growing to 43% by the end of 2006, and 45% by the end of 2010.

On an adjusted basis, that is, excluding transition bonds and the debt of our international affiliates, all of which is nonrecourse to the parent company, our equity ratio increased to 54% at March 31 of this year, compared to 50% a year ago March, and continues to improve to our target level over this period of time of about 55%.

We have no plans to issue common stock over this period to fund our current capital expenditure requirements.

Inclusive of our plans to continue to grow the dividend over this period of time, our equity grows by $1.9 billion over the balance of the decade, averaging about $400 million a year improvement.

This allows us to meet our funding needs during this period, and still maintain credit metrics that support our current BBB credit ratings, with stable outlooks across the board and puts us in a position to buy back common stock, beginning in 2009.

And this buyback is reflected in the 2010 equity ratios that are shown on this slide.

There is visible growth in PPL in both earnings and cash to provide superior overall share owner returns.

Bill described the factors that will drive our earnings growth through 2010, and for your reference, those factors are listed on page A-6 in the appendix to today's presentation material.

And if you remember, those are the same factors that I just described that will improve our cash flow over the same period.

All of that translates into growing high quality cash earnings over the balance of the decade for PPL.

And to emphasize a couple of points that Bill made in his remarks, there are some additional value drivers that are not included in our forecast.

Higher capacity prices, further increase in the capacity at our base loaded generated facilities and higher equivalent availability at our power plants, and increases in energy prices above the current forward prices that we've included in our forecast.

The market forces we see today and anticipate in the future, such as higher fuel costs and tightening reserve margins, suggest even higher prices than reflected in the current forward curves.

And importantly, PPL's long-term forecast does not depend on new assets being added to the Company's portfolio.

Now I'd like to turn the program back to Bill to moderate the Q and A session.

Thank you.

Thanks very much.

Operator, we're ready to take questions.

Thank you. [OPERATOR INSTRUCTIONS] We will go to our first question from Paul Ridzon at KeyBanc.

Good morning.

Congratulations on a solid quarter.

Thank you, Paul.

How are you?

Good.

And yourself?

Good.

Actually, a handful of questions.

Can you give some indication on the eastern 2010 megawatt hour production, what percent has been sold?

I saw some comments from one PA commissioner that he would like the commission to look at phasing in rates ahead of expirations.

Kind of how you view that.

And just what your synfuel strategy is for the balance of the year, with the uncertainty around whether or not Congress is going to act on this proposal to change the look-back provision.

Okay.

A couple of items.

Paul, we would rather not disclose what sales we've made for 2010 for competitive reasons.

Yes, one of the commissioners did make the statement that he thinks the rate cap should be broken.

Each utility in the state is in a little bit different position with regard to what happens at the end of their transition period.

And for that matter, when their transition period ends.

In our particular situation, there are a number of actions that we can take that would smooth any rate change in 2010 without jeopardizing the 3.50.

Now, we haven't fixed in on one of those, and certainly, that would involve and is involving the commissioners themselves.

But there will not be a rate shock in 2010.

There may be some modest increases in the out years.

We don't think that it would be a good idea from our standpoint to propose to break the rate cap.

And we have abided by the settlement that we reached with the commission on restructuring in the late '90s scrupulously, and we think that that is very important.

It is an integrity issue for us.

And obviously, it is a practical issue to fulfill our expectations of taking our generation to market in 2010.

I don't know where the other commissioners stand.

I suspect that each commissioner is in a little different position philosophically and perhaps is looking for more information on a company by company basis before establishing a view on what might happen four years out.

Also point out that some of the commissioners' term, some of present sitting commissioners' terms will expire before 2010.

So, you know, all of those are moving parts.

But in our situation, once again, real important to point out that our POLR contract ratchets up over the remainder of the decade, as you know.

And our stranded recovery expires at the end of 2010, which provides a partial offset to the increase in energy costs for POLR.

I hope that has been responsive to your question, Paul.

Yes, yes.

Okay.

Now, synfuel strategy, I'm going to ask Jim Miller to talk a little bit about, it and do you put your finger on something that we are managing our way through and that is the synfuel operations without the tax credits on a pure operating basis actually lose money, and you don't know until the end of the period what your comparison price for oil is and whether or not the phase-in started.

So we've taken some actions to stay ahead of that.

Jim, do you want to talk a little bit about it?

Yes.

Given the situation Bill described, we currently have two synfuel facilities, one of which we've suspended operation at for the time being, as we watch the oil price indexes move upward.

Our second facility, Tyrone, is still running and we would expect that facility, under current conditions that we're looking at, to probably run through the month of June.

Now that can vary, of course, depending on what oil is happening -- what is going on with oil prices, but that is a pretty close call, end of June, beginning of July, somewhere in there.

And if the index continues to move, we will shut down that second facility and not restart unless we see either legislation come through that would allow us to know how many tax credits we would get in '06, we could then restart.

So we're sort of keeping our powder dry, watching the indexes and adjusting the plant operations, as Bill said, because the operations themselves operate at a loss, and your benefit is from the tax credits.

I know, Paul, some people have included in their outlook for the future significant synfuel tax credits, and that probably just represents partly a forecasting philosophy, because if we all get the same opportunity for tax credits, we're all based on the same oil index.

Paul, did you want to add anything to that?

Paul Farr?

Yes.

I think, Paul -- this is Paul Farr.

Probably a couple of other items as well.

I think the single biggest component of our strategy around synfuels really started in the second to third quarter of last year, when we evaluated and ultimately layered in hedges for a significantly large percentage of the exposure that we had for the '06 and '07 credits, and you see that preserved in the nickle that we're forecasting for this year, as well as supporting the legislative fix that others in the coalition are.

The strategy for us goes back several quarters.

Paul, I think you're aware that we discussed in previous calls having put in some oil hedges so that if oil went up and knocked out the tax credits, those would be partially replaced by some benefits in our oil position.

The nickel you're expecting from synfuel is the worst case of oil prices staying high and having no value for synfuels produced thus far?

Yes, that really reflects, basically, full mark-to-market on the hedge position without any contribution from plant operations.

Yes.

It is the worst case, yes.

And I don't know if you are going to put these things in hot mode or you're going to have to do a cold start-up, but how long -- how much production would you lose just going from having ramped down to having to start back up?

That's not a major issue.

These are not complicated facilities.

So it is de minimus, what you would lose.

We're not shutting down nor dismantling the plants.

We're just shutting them down for the time being.

They can be readily restarted.

And are you, at this point, selling any of your sulfur length, or do you want more clarity on getting the scrubbers operational?

Our scrubber projects are essentially on budget and on schedule.

First of all, I want to emphasize that.

We are in the emission allowance market and to kind of balance our position, but we are -- we're not -- really would rather not disclose any more detail about our allowance position on a year by year basis.

I really would rather not do that for competitive reasons.

I understand.

Thank you.

Sure.

Thank you, Paul.

We will go next to Daniele Seitz at Dahlman Rose.

Thank you.

I was wondering if you could quantify the impact of the better hydro conditions in the West.

I know it has been many years of bad hydro and I was wondering if you could quantify that for 2006.

We'll take a shot at it.

Jim?

Daniele, right now, we're -- first of all, we've seen a snow pack that more resembles 90 to 100% of normal snow pack in the West.

Not the snow pack that has existed during the long-term drought.

Right.

So we are seeing some better hydro conditions first quarter.

That being said, we still have to wait and really what will determine the rest of the year's production will be the spring runoff.

That has not occurred totally yet.

And so right now, we don't have any reason to anticipate large annual increases in hydro production, but yet, admittedly, we've had a good first quarter, but the real tale of the tape is how the spring runoff goes.

And in terms of either production or even earnings, in normal year, versus a bad year like last year, would be roughly [inaudible -- highly accented speech] not really tremendously precisely, but would it help your earnings by a large amount?

Yes, Daniele, it helped about $0.03 in the first quarter.

So again, the shape of that for the balance of the year, to Jim's point, depends upon the runoff.

Okay.

Thanks.

And in terms of the contracts that you anticipate to roll over in 2007, is there any -- can you share the quantity?

Daniele, we're not necessarily anticipating rolling over the contracts.

In fact, when the contracts with Northwestern expire, we've been selling some production and we would rather not quantify how much, again, for competitive reasons.

We have been selling production in the Pacific Northwest, so we might -- we're -- we have a great deal of flexibility in replacing the Northwestern contract with a variety of smaller contracts, rather than a single large contract with greater margins.

Okay.

And this could occur through the -- even through 2007 and 2008.

Oh, yes.

I mean, less of a precision for that.

That's right.

That's correct.

Okay.

Thanks.

Thank you.

We'll go next to Tom O'Neill at Citadel.

Good morning.

Very nice result today.

Just wanted to ask a couple of questions on the quarter.

Sure.

The first was, how much of synfuels and the oil option gains were in the first quarter?

Well, we will have to do a little bit of checking here.

Okay.

And then --

About $0.03.

$0.03?

Yes.

Okay.

And then, you mentioned what sounded like mark-to-market gains on new wholesale contracts signed during the quarter.

Did I hear that right?

Yes.

How much was that?

$0.03.

Okay.

It just happens to be the same number?

It's not --

That's right.

Okay.

And then, tax benefits in the U.K.?

I will have to do a little bit of checking there.

I think that might have been $0.03 too.

$0.03.

So, so far every question people have had is $0.03.

The answer is $0.03.

What's the question, right?

Right.

Okay.

And then, on your -- just a longer term question, should we anticipate that you will do any emission sales prior to 2009?

Or is that something you're going to hold off until later?

We will just evaluate the market and I would say that if we -- how much we sell and when is something we don't yet know.

Okay.

So it is fair to say there is not any of that showing up in current results?

That's correct.

Great.

Nothing material.

Okay.

Thank you.

Thank you.

We will go next to Paul Patterson at Glenrock Associates.

Hi.

Can you hear me?

Yes, I can, Paul.

Great.

Well, congratulations.

I wanted to ask you a little bit on the currency impact and your expectation for 2006.

The dollar is kind of weakened here a little bit and you guys are, I don't know, one of the better exposed to international operations, so I was just wondering, what's your thoughts about what the currency impact is going to be on your new guidance?

It is factored into the guidance, Paul.

We had about a penny and a half of positive in the quarter versus '05.

Or sorry, negative in the quarter versus '05.

We start the year fairly hedged from a currency perspective in the U.K. and Chile, so about 75% hedged.

So a good rule of thumb is for every nickel versus sterling move in the FX rate is about a penny a share for us.

Okay.

And so because you're hedged you're not going to see that much of an impact this year due to the strength, I mean the weakening of the dollar, is that right?

That's correct.

Okay.

But in 2007, you would.

That's correct.

Okay.

And then in terms of the annualized margins that I think Tom was asking about, the $0.03 number, one from the West and $0.02 from the East.

What exactly is going on there?

What is causing these unrealized gains?

The unrealized gains are resulting because certain contracts, either the short side or the long side, if we happen to be in the market purchasing for a portion of a supply commitment or load following deal doesn't meet the criteria to be considered normal and therefore get mark-to-market through OCI or the equity side of the balance sheet, it has to come through earnings.

So in certain instances, there is a benefit to if it is a cost -- a gain or a loss on a contract, both sides may not be in the speculative or mark-to-market bucket.

And it is either accrual or being marked through OCI.

So those just are related to positions that are in our speculative mark-to-market bucket.

So you guys are selling a contract, I mean, just to sort of understand the market dynamics here, you guys sold power, let's say, but it wasn't specifically associated with the plant?

Is that the idea?

Let me give you an explanation.

We don't generally enter into speculative arrangements as you would consider them from a business or economic standpoint.

We may write a contract, for example, to sell power and use the existence of our own production as our hedge initially, and then after we write the contract, depending on market conditions, we may go to the market to cover that contract rather than use our own production.

And we can do that for a variety of reasons.

We may do it because the market is lower than our own production costs during some hours.

We may do it to remove transmission risk to get to the delivery point of that contract.

And what that does is, it gives us our production still available for sale, and locks in, if you will, a margin between a sale contract and a purchase contract.

However, if the sale contract, for example, is load-following, and the family of purchases that we match up against it economically are standard products, like blocks, then it is not a perfect hedge and the accounting rules may require that one side or the other be treated as speculative.

So a spec arrangement from an accounting standpoint doesn't mean we're entering into speculative transactions from a business or an economic standpoint.

I hope that helps.

No, no, that explains it.

You're trading on the optionality of the plan from what have you.

I guess what I'm sort of wondering is that how much are you guys expecting for this to -- I mean, this would seem like sort of a timing issue, if that were the case.

So how much do you expect 2006 to be benefited by unrealized margins?

We will give a shot at it, Paul.

I don't know if we can.

It is not major.

Okay.

That's fine.

It is really not major.

You know, our marketing philosophy has fundamentally not changed.

We think we've improved our execution every year.

But we haven't changed our risk management principles.

What was the total unrealized EPS impact for 2005?

Do you guys know off the top of your head?

It was de minimus.

It was not material.

Okay, It was de minimus.

Okay.

That's what I thought.

Outside of the oil hedges.

I got it.

And then finally, you guys mentioned strengthening energy or capacity margins and the outlook on that and of course we've had a big announcement in Texas from TXU in terms of the opportunity they see for investing in coal plants.

Not only in ERCOT but actually in PJM, and they are talking, they seem to be talking about very large amounts, potentially, and since you guys are significant experienced market participants, I thought I would ask you what you think about that, particularly with the positive statements you're making about what you see in the market through 2010?

Well, we all have our own philosophy, not only on how we grow the business, but our own philosophy on what we announce and when we announce it.

We're fairly conservative.

Before we make announcements we pretty much know what we're going to do, and have reasonable certainty that we're going to deliver on what we tell you, meaning we know where we're going to build it, we know when we're going to build it, we have reasonable expectation we're going to get it permitted and that we can finance it and what the finance costs will be.

Other people announce projects when they're in the formulative stage, perhaps.

You know, we do -- as I said earlier, we examine the market, we examine the opportunities, both for acquisition and for greenfield development, and maybe I better leave it at that.

And you guys have to judge what is credible.

Okay.

And then finally, a break down of the supply, the 2006 supply margin that you guys see.

Could you give us a breakdown between east and west for your 2006 estimates?

We will give it a shot.

We could do a little bit of checking to give you -- to be as realistic as we can.

Well, I will let somebody else ask a question while you guys are looking it up.

How about that?

We'll do that.

We will come back to that question when we think we have a realistic number.

It is about 85% East and 15% West for 2006.

Excellent.

Thanks a lot.

Okay.

Thank you, Paul.

Take care.

Our next question comes from jed Arnold at King Street Capital.

Hey, guys.

Hi.

Great quarter.

Quick question for you.

You sort of answered my TXU question, actually.

Building on that, though, a little bit, you have about 700, 750 million that you're going to spend to buy back stock.

Would you consider using that money for Greenfield development or building new plants?

Yes.

I want to emphasize, we've used stock buyback as a baseline, because that represents something that you can do no matter what, almost.

You know, that represents the minimum that we would do.

And our business plan would be proportionately better than that baseline if we find opportunities that we think have the right earnings and risk profile for us.

So don't -- we're not -- I wouldn't call -- the 3.50 is a forecast.

The stock buyback is a place holder, from which we would judge better opportunities.

Okay?

Perfect.

And then with regard to Griffith, I know it is a small part of your portfolio, but there has been a lot going on down there.

It looks like asset values are trading for merchant gas plan, call it in the high fours to low fives per kilowatt.

And given the capacity prices, it is hard -- I don't have perfect information, but it sounds like during the medium to low-fours, and when you put those two numbers together, it sort of sounds like you're getting -- the market is pricing in -- call it a 7% all-in rate of return, and which doesn't look that great, maybe 5% to 7%.

Given that people are going to pay you more, essentially, and take that risk, and it is such a small part of your portfolio, I was wondering if you could just talk about your plans for the asset.

I know Alice Power bought the other half of it and you didn't, essentially, tag along, even though I assume you guys have tag-along rights.

We look at opportunities for isolated assets to get better value out of assets that may not have met expectations, and are perhaps isolated.

We evaluate opportunities, and we make announcements, again, when we think we have something firm to tell the Street that we can deliver on.

And that's the best we would like to say right now.

Okay.

Okay, thank you.

Great.

Thanks a bunch.

Sure.

We will go next to Vic Khaitan at Deutsche Asset Management.

Vic?

You may have your line muted, Mr. Khaitan.

Your line is open.

Hearing no response.

We will move to Reza Hatefi at Zimmer Lucas Partners.

Thank you.

I was wondering, what is normal hydro generation, as far as megawatt hours?

About 3 million-megawatt hours.

About 3 million?

And I had a question regarding slide 6, which shows upside of the remarketing of the POLR supply.

It looks like it's, rough numbers, around $800 million.

But if I then go to slide A-1, and your load following number there is 80 to $90, let's just use a midpoint of $85, that's about $35 more than the 2009 POLR price, so I just took $35 times the load, which is about 40,000 gigawatt hours.

That's like 1.4 billion.

So I just wanted to know why the upside in slide 6 is only 800 when just doing this crude math gets me 1.4 billion of upside.

It could be a lot of variables.

You know, remember, the generation that we have is available around the clock.

The POLR is load following.

And average prices can be misleading.

The generation that's available now to go to the market is much more in volume off-peak.

There are some other moving parts.

Paul --

Yes, Reza, I think there's two things.

One is, we did not update that slide 6 for the 80 to 90, so there may be some upside.

There is a difference in timing there.

Prices have moved up at the back end of the curve a bit.

And the second thing is, as noted on that slide A-1, if you look at -- it's kind of sub-bullet three there, there are several elements that are cost pass-throughs that are in the load following number that don't fall to the bottom line that result in net margin.

So the combination of those two things, I think, explains that differential.

I guess what I thought was that these costs that you're talking about, in that note three, shouldn't they already be reflected in the '09 number?

Because you're already experiencing such congestion and losses and so forth so the '10 would just be a pure price uptick.

But there is a complete new opportunity relative to shopping the utility, through 2009.

It has a pass in terms of compliance with the new alternative energy requirements.

There are several items that do become incremental versus the '09 number.

You have to remember, too, Reza, that those prices that are in the POLR contract were set almost a decade ago, when costs were at a much different level and issues were much different than they are today.

Thank you very much.

Okay.

And next we will go to Shalini Mahajan at UBS.

Good morning.

Could you give us some color on Montana.

There's been a lot of talk of repeating the restructuring in the state.

If you could just provide some color on that.

Well, we can a little bit.

If they do repeal restructuring in the state, the primary effect, as we understand it, would be that it would permit incumbent distribution utilities, like Northwestern, to build power plants.

Now, that construction cost would be much higher than the cost of imbedded assets, and it would not, however, re-regulate the power plants that we acquired.

The power plants that we acquired are now FERC jurisdictional and there is nothing on the horizon that would change that and nor does the state have any authority to change that.

So really, restructuring wouldn't have any -- repealing restructuring in Montana would have no material effect on our assets.

I hope that helps.

Okay.

It helps a bit.

And then when do you expect FERC to rule on your market power test in Montana?

We don't know.

I'm not able to predict what FERC will do and certainly not when they will do it, but our market power proceeding at FERC relates to a market area that is defined as the Montana control area.

So while FERC has been considering that, we've been making market sales outside the Montana control area, where we would be confident, absolutely confident, we would retain market-based rate authority.

So we're hedging the contract that will expire in mid-2007.

We're selling that power now outside Montana.

Okay.

But even if FERC was to conclude that you have mark hedge power and revoke your ability to sell at market rate, you wouldn't see a significant earnings impact?

It would have no earnings impact, no material earnings impact, because we are selling -- what we're selling now is outside Montana, where we would retain market-based rate authority.

There is no plausible analysis that can show that our few megawatts in Montana have market power in the whole Northwest.

Okay.

That's helpful.

Thanks so much.

Sure.

We will go next to Steve Fleishman at Merrill Lynch.

Hi, guys.

Hi, Steve.

Just to -- this is kind of a dumbing it down question, but if you look at the uptick in earnings guidance for 2006, including the fact that you're doing it on top of lowering your synfuel, I mean, what really is the driver to the higher guidance?

Is it just better expected wholesale results, both margins and production?

Yes.

It is mostly supply.

Okay.

You know, everything -- as you can see, everything performed well in the first quarter.

The marketing operations did.

The plants have performed okay.

We can even do better than that.

You know, you see, we've kept costs under control as well.

Supply margins are the big help.

Okay.

And then just to maybe close the loop on the question asked about the '09 to '10 change, is what you're saying that basically you -- if you look to '09, you hedged some of the costs of providing POLR load when the costs were lower, so that when you go to '10, you have much higher revenues, but some of the costs then also go up, because you haven't hedged '10.

Is that --

We've hedged -- different elements of costs have different abilities to hedge out into the future, you know.

There is obviously a less liquid market in every commodity the further out you go.

So I wouldn't say we've hedged '09 and haven't hedged 2010.

It is sort of more of a continuum.

Does that help, Steve?

Paul, do you want to --

Yes.

I think that, Steve, it is more items that are -- when you look at '09 to '10, if you were to presume that all of the existing generation that is there to support the POLR and '09 supports that are in 2010, there are truly incremental costs that will get born, because, again, for example, electric utilities has to comply with the alternative energy requirements, and that would come at an incremental cost for whoever is supplying them or for them on their own to go out and buy green tags or recs in the marketplace to be able to comply with that regulation.

In addition, to the extent that prices get re-sent to market at that point in time, shopping likely comes at a substantially higher risk and a truer cost for whoever is supplying that obligation, which isn't there today.

In addition, FTRs and transmission costs will get altered.

We don't presume that our generation goes to support [lower] growth.

It goes to market.

So it ultimately has to be moved somewhere, and that comes out of transmission costs.

Now, recognize that some of the things -- in fact, most of the things that Paul mentioned are pass-throughs to the utility.

Transmission costs are automatic pass-throughs, that has been reaffirmed, the way Pennsylvania, green tags, to the extent that increases the purchase power cost of the utility, there is a pass-through that the utility gets for energy procured to supply POLR loads.

So those are pass-throughs.

Okay.

You want to restate -- if there is an element of your question we could be more helpful with, give it another shot.

Okay.

I mean, I think the question was asked before, but I think it is just something maybe to follow up later, is the difference between you showing an 800 million margin upside and the price difference being, as the other questioner said, about 1.4 billion.

So how much of that 600 million is cost?

How much is it that you just set the 800 million when prices were lower?

I don't know that we can break that down.

When -- but we will over time re-evaluate the 3.50, and as people have pointed out, there is upside to that.

Okay.

Thank you.

Sure.

We will go next to Raymond Leung at Bear Stearns.

Hey, gentlemen.

A couple of questions.

Can we talk a little bit about, given that it looks like you're cash short for '06, and you have some maturities, and what your strategy is there?

Our plan is to issue debt and some preferred securities to meet our shortfall from a cash position.

We've already started that program with a $250 million preference stock issue this year.

We do expect to do some debt over this period of time.

As I said in my remarks, we expect to be able to meet our cash needs through 2010 through the issuance of debt and preferred securities.

We don't expect to issue any common stock over that period, but it is essentially debt refinancing.

Okay.

Would that be at supply?

Primarily the debt will be at energy supply, that's correct.

Okay.

And can you elaborate a little bit about synfuel and the cash flow impact, if anything?

Or is that sort of baked into the revised cash flow -- or not revised, but --

It's baked into the forecast.

Okay.

And finally, on the construction buildout, can you -- would you also consider outside -- would you also consider the West for expansion?

Or is it just PJM-specific, and how long before you think you can elaborate more on something?

I wouldn't want to give you a date on an announcement or anything like that.

We certainly look at the east and the west.

We found there to be substantial benefits to be in two markets that are only partially correlated, the Northeast generally, and the Northwest.

So there are some benefits there.

The other advantage is in the east, there are apparent -- greater load density and more integrated transmission network, and a more liquid market, especially in PJM and New England, so there are pros and cons.

We are considering an expansion of our Holtwood hydro project in Pennsylvania.

It is a modest expansion.

But we have been gathering public comment on that expansion.

But if you are talking about a much larger expansion, that would be a little bit down the road.

The Holtwood would be about 125-megawatts, but -- and would make better use of water that's now spilled during peak periods and allow the capacity to operate at -- allow that plant to operate at greater capacity during high cost periods.

So there is a good economic picture around Holtwood hydro, although it is modest.

Something major, base-load generation, which we believe PJM will need within the next decade, I wouldn't want to give you any expectation that we would make an announcement by a particular date.

Okay.

Great.

Just one last question: WPD, has it paid a dividend during the quarter?

Yes.

Okay.

And you still expect like somewhere in the $25 million range?

35-ish.

35?

Thank you.

Thank you.

And we will take a follow-up from Daniele Seitz at Dahlman Rose.

Thank you.

I just was wondering, what is your best guess as to the capacity, the addition or change for capacity in the PJM at this time?

When do you anticipate the decision to be made?

We don't have a guess on capacity charge at PJM, nor do I have a guess as to when FERC might ultimately resolve it.

You may be aware that within the past couple of weeks, FERC did consider it.

The chairman made his public statement that he believed PJM did need additional capacity in the planning horizon, but then took various elements of the RPM proposal and sent those to staff for some further work.

So I couldn't speculate on when they would make a decision or on what the quantitative benefit will be to us, other than to reiterate that if there is any, it is upside to our current forecasts.

Thanks.

And we will go to a follow-up from Jed Arnold at King Street Capital.

Hey, guys.

How many greenfield sites do you own and how many brownfield sites could you expand on?

I don't know that we own any brownfield sites.

If you would want to consider that an abandoned site, we do have expansion ability at a number of existing plant sites.

Okay.

We have expansion ability at Susquehanna.

We have additional room at Montour.

I mentioned Holtwood already.

And those are some examples of sites that we have that have capacity to expand physically, are likely to be permittable, and are likely to have available transmission, or at least a head start on available transmission.

Okay?

Perfect.

Thanks.

Sure.

And we have no further questions at this time.

We will turn the conference back over to management for closing remarks.

Okay.

I want to thank everyone for their participation this morning and wish you a good day.

Thanks again.

Goodbye.

That does conclude today's conference.

Again, thank you for your participation.