賓州電力 (PPL) 2010 Q2 法說會逐字稿

Good morning, my name is Celeste and I will be your conference operator today.

At this time, I would like to welcome everyone to the PPL Corporation second quarter conference call.

All lines have been placed on mute to prevent any background noise.

(Operator Instructions) I would now like to turn today's call over to Mr.

Joe Bergstein.

Please go ahead, sir.

Thank you.

Good morning.

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

We are providing slides of this presentation on our website at 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 the factors that could cause actual results or events to vary is contained in the appendix of this presentation, and in the Company's SEC filings.

At this time, I'd like to turn the call over to Jim Miller, PPL Chairman, President and CEO.

Thanks, Joe.

Good morning, everyone.

We'll start today's call with the general business update.

And we'll also obviously include a summary of the status of the E.ON U.S.

transaction, and commentary on our quarterly results, and then we'll take all of your questions.

Joining me on the call are Paul Farr, Chief Financial Officer; and Bill Spence, Chief Operating Officer.

This morning, we reported quarterly GAAP earnings of $0.22 a share compared with a loss of $0.02 a share in the second quarter of 2009.

Earnings from ongoing operations for the second quarter were $0.62 per share this year compared with $0.32 per share in 2009.

For the first six months of the year, our reported earnings were $0.88 per share, $0.26 higher than a year ago.

And our earnings from ongoing operations for this period were $1.56 a share, $0.65 higher than last year.

As expected, energy supply segment earnings drove the improvement in our financial performance for the second quarter and for the first half of the year.

These results in our forecast for the balance of the year put us on target to achieve significantly improved earnings in 2010 compared to our 2009 results.

Before we move on to a discussion of the earnings forecast for 2010, I'll take a minute to update you on our proposed acquisition of E.ON U.S.

As you all know, in late June we successfully completed the equity portion of our financing requirements for the acquisition, raising $3.5 billion in net proceeds through the sale of common stock and equity units.

The equity offering was significantly over-subscribed, which we believe validates our strategy and the decision to pursue this acquisition for our shareowners.

Also, we're on schedule to obtain all of the regulatory approvals related to the transaction.

These include change and control filings with the Kentucky Public Service Commission, state regulators in Virginia and Tennessee, and the Federal Energy Regulatory Commission.

In Kentucky, the PSC has scheduled hearings for early September, which is consistent with the timing we had anticipated.

Additionally, the Federal Trade Commission and the US Department of Justice have granted early termination for both of the notices that were required under Hart-Scott-Rodino Act.

Clearly, we remain on track to close this important transaction later this year.

You also may have read that late last week the Kentucky PSC approved a $189 million increase in rates for LG&E and Kentucky utilities, accepting a settlement agreement to buy most of the intervening parties.

The Commission also reiterated its position that the PPL transaction did not preclude a proper analysis of these rate increase requests, which were filed in January, well before the announcement of our proposed acquisition.

We remain confident that this acquisition will increase shareowner value in the long term by growing the size of our regulated businesses, while retaining the upside from competitive market opportunities as energy market fundamentals improve.

Now let's turn to our 2010 earnings forecast.

As indicated on this slide, we've adjusted our 2010 ongoing earnings per share forecast to reflect the dilution associated with the recent common stock and equity unit issuances.

It's important to emphasize that the change in the forecast range is based solely on the dilutive effect of the new equity.

Factoring in about a half year, weighting for the 103.5 million new shares and the interest cost of the equity units, our forecast for 2010 earnings from ongoing operations is now $2.70 to $3.05 per share.

While we don't provide guidance on a quarterly basis, I'd note that the results we will report for the third and fourth quarters will obviously reflect 100% weighting of the shares and interest expense for those periods.

Our forecast for GAAP earnings for the year reflect special items recorded through the first half of the year, and the dilutive effect of the new equity, now $2.10 to $2.45 per share.

Before turning the call over to Paul and Bill, I'd comment briefly on a request to increase distribution revenues in Pennsylvania.

Pennsylvania Public Utility Commission is continuing its review of our request for a 2.4% increase in revenues at PPL Electric Utilities effective January 1, 2011.

The public hearings have been held, and evidentiary hearings are scheduled for later this month.

We anticipate a decision from the PUC sometime in December.

Now I'll turn the call over to Paul.

Thanks, Jim.

Good morning, everyone.

Let's go to slide five.

Earnings from our supply segment increased significantly in the second quarter, as a result of higher realized prices on our Eastern baseload generation.

The supply business is clearly benefiting from the hedges we entered into at prices that are higher than current market prices for 2010.

Partially offsetting the supply segment performance were lower earnings in both our Pennsylvania and international delivery segments.

I'll begin the segment review with supply on slide six.

The supply segment earned $0.43 per share in the first quarter,(Sic-see press release) a $0.34 increase over last year.

As I already mentioned, the single biggest driver of the second quarter earnings was significantly higher realized sales prices for the Eastern baseload generation.

The second quarter also benefited from higher West energy margins, primarily due to higher average sales prices.

The second quarter was also impacted by higher O&M due to the timing of outages at our coal fired power plants, partially offset by lower costs due to the timing of the Susquehanna refueling and upgrade outage, higher depreciation due to the Brunner Island scrubbers that were placed in service in 2009, and higher realized earnings on our nuclear decommissioning trust funds, as well as lower income taxes.

Moving to slide seven.

Our Pennsylvania delivery segment earned $0.04 per share in the second quarter, a $0.01 decline compared with last year.

The decrease was the net result of higher transmission revenue resulting from cost recovery through FERC formula-based rates, and higher O&M expenses due to increased staffing and expanded vegetation management activities.

Turning to slide nine.

Our international delivery segment earned $0.15 per share in the second quarter, a $0.03 decline compared to last year.

The decrease was the net result of higher delivery revenue driven by higher prices, which were effective beginning April 1, 2010 under price control review five, higher O&M primarily driven by higher pension expense, higher interest expense on index linked bonds as a result of recent higher UK inflation, and interest resulting from the GBP400 million debt issuance that occurred in March of this year, more favorable exchange rates and positive hedging results, and higher income taxes.

On slide nine, we've updated our 2010 free cash flow before dividend numbers from the first quarter call.

The update includes the return of collateral to third parties of approximately $255 million in our supply segment.

Now I'll turn the call over to Bill for an update on operations.

Thanks, Paul, and good morning, everyone.

Let's turn to slide 10 with an update of our delivery businesses.

Last month, PPL Electric Utilities completed another [polar] solicitation for its 2011 to mid-2013 procurement needs.

In this latest round of purchases, the Company awarded a mix of 17-month and 20-month full requirements contracts, and this is about 11% of the electricity needed for January 1, 2011.

Also in this round, the Company awarded five-year contracts for two 25 megawatt blocks of around-the-clock electricity supply.

The Company has now secured approximately 80% of its power supply from a total of 16 companies for the first five months of 2011.

Based on the purchases made to date, PPL Electric Utilities believes its 2011 generation service charge may be 9% to 12% lower than the current default rate.

On the Susquehanna to Roseland transmission line, both PPL Electric Utilities and PSEG continue to work with the National Park Service to obtain approvals that may be required to route the line through the Delaware Water Gap National Recreation Area.

The National Park Service has indicated that its review will not be completed until 2012.

If the review is completed in this timeframe, the in-service date of the line will be delayed until at least 2014.

The CapEx chart in the appendix to today's presentation incorporates the revised spending driven by the delayed schedule.

On the international front, the new rates, as Paul mentioned, related to DPCR5, went into effect on April 1.

Now let's turn to slide 11, and take a look at the schedule for the PPL Electric Utilities rate case that Jim mentioned.

Rebuttal testimony was submitted by electric utilities on July 27.

Surrebuttal testimony is due today, and evidentiary hearings are scheduled to begin the week of August 9.

The ALJ's recommended decision is expected by the middle of October, and the Commission's final order is expected by mid-December.

We've also included some additional pertinent rate case information for your reference.

Now moving on to supply.

Let's start with an update on the status of the Susquehanna unit one nuclear plant.

Unit one safely shut down on July 16, following a condenser leak of river water into the turbine basement.

This was a non-nuclear incident that did not impact the safety of the public or our employees.

The unit returned to service yesterday, and continues to ramp up to full operating capacity.

The Susquehanna unit one outage is expected to impact 2010 ongoing earnings from operations by about $0.05 to $0.06 per share.

Also late in the second quarter and early in the third quarter, the supply segment sold several load-following contracts to provide additional cash support for the acquisition of E.ON US.

These full requirement contracts were for delivery for the remainder of 2010, as well as deliveries in 2011 and 2012.

We sold approximately 1,570 megawatts, which reduced our ongoing load-following exposure, and also resulted in $249 million of cash proceeds.

As noted in today's news release, we received $156 million from these sales completed in the second quarter, and we have additional sales in July which will net an additional $93 million.

We still expect to earn about $35 million in marketing and trading in 2010, and we are continuing to evaluate the possible sale of non-core generating assets.

Moving on to an update of our hedging program on slide 13, we've updated our hedge positions as of June 30.

These hedge levels have not changed significantly since the update we provided on our first quarter earnings call.

You will note, however, that the expected average hedged price has declined in the East for 2011 and 2012.

The decline in prices reflects a further adjustment to our assumption for basis.

As you know, we've effectively hedged our expected baseload generation output at West hub, but we are still exposed to basis price differentials between the generator buses of PPL plants and the West hub.

Results thus far in 2010 indicate the basis differentials for our baseload generation are likely to continue to see pressure as a result of three things, increased transmission work, lack of basis liquidity, and continued weakness in natural gas prices.

We see basis averaging negative $1 per megawatt hour in 2010.

However, after reflecting the benefit of hedges we have in place, we expect to earn about a positive $1 per megawatt hour basis for 2010.

For 2011 and 2012, what we've done is eliminated all the basis premium, but we will continue to update our expectations as we see market conditions change.

On slide 14, we've updated our fuel hedge positions.

During the quarter, we put on additional East coal hedges for 2011 and 2012, which substantially increased our hedge positions for these years.

And while the average commodity hedge price of the coal has changed only modestly, we continue to see rising coal transportation costs in 2011 and 2012, driven by both base rail charges and associated fuel surcharges.

Now I'd like to turn the call back to Jim Miller for the Q&A.

Jim?

Thanks, Bill.

Operator, let's open it up for questions.

(Operator Instructions) Your first question comes from the line of Paul Patterson with Glenrock Associates.

Good morning, guys.

Good morning.

On the transportation costs that you just mentioned and the basis differential, how should we think about that impacting 2011 and 2012?

On the basis differential, let me speak to that first.

It's Bill.

As I indicated, what we're seeing thus far is about a negative $1 to west hub -- from our generator buses to west hub.

Now we do have hedges in place that actually are producing value of about $2 so we're actually going to realize about $1 of premium for 2010.

As we look at 2011 and 2012, we're still seeing a lot of transmission-related work for various transmission projects, plus a fairly low natural gas price compared to the past.

Both of those things, as well as the lack of liquidity in the basis market really caused us to think about adjusting to a zero premium to west hub for 2011 and 2012.

But as you know, things are pretty dynamic.

As we see things moving back in our favor, we'll of course adjust it accordingly.

Okay.

When we think about this, you have a $2 benefit and $1 negative hit for 2010.

When we look at 2011 and 2012, if that was zeroed out, it would be about $1.

Is that how we should think about it?

No.

It's net effect of zero for 2011 and 2012.

Zero over 2010?

Correct.

Okay, excellent.

In terms of --

Paul, it's zero to west hub.

So, in effect just to be clear, if our actualized price in 2011 based on the hedges at west hub were $50 a megawatt hour, we would add no basis premium to the $50.

It would be a net $1 reduction to the 40 million plus megawatt hours that we -- in the generation to the east.

Okay.

Great.

Then on the Susquehanna outage, how much do we think that's going to impact the third quarter?

The combined margin impact plus O&M is around $0.05 to $0.06, probably a little bit closer to $0.06.

We have not adjusted the forward guidance, or the range I should say, for anything at the mid-point; the roughly $0.43 of dilution mainly from the share count of $0.38, but also $0.05 from the convert securities.

We were right on top of mid-point, or maybe just slightly north of mid-point prior to the outage.

We would be roughly $0.05 shy right now of mid-point for 2010.

Okay.

And then I forgot to follow up on this.

The transportation costs that you mentioned on the fuel side, how much should we think about that adding?

It sounds like you guys are seeing increased pressure on that for 2011 and 2012.

Sure.

If I look at 2010, and I'll start there for a second, what we are seeing consistent with the fuel contracts at the mine mouth that we have, about $49 a ton.

The transportation costs are about -- projected now to be about $22 a ton so that would net result in about a $71 a ton delivered to the stations.

That transportation charge of $22 per ton is really comprised of three components.

It is a base price that we've negotiated in contracts, predominantly with NS where most of our Northern App coal originates and that has built into its own -- some escalators.

Plus we have the quarterly rail cost adjustment factors which include things like fuel, timber, labor.

Then on top of that is a fuel surcharge, which is based on a $24 roughly west Texas intermediate crew price.

The combination of all three of those components gets us to about a $22 per ton transport.

As we look at 2011, we see that probably rising maybe into about the $24 range for next year.

We won't know exactly because some of these are based on the variables that I mentioned.

And if you look at our slides in today's presentation and assume, say, a $51 a ton base price for the commodity itself, the coal itself at the mine mouth, plus the $24, you'd be looking at coal prices moving up delivered from about $71 to $74, $75 per ton in 2011.

That's obviously for the PPL units, the 7.5 million tons that we require for our units.

In addition to that, you have the Keystone Conemaugh which is about 1.4 tons, but I would see their delivered prices being a similar range.

Just generally, obviously, oil prices and everything impact us to a certain degree; 2012, is that still climbing upwards?

Yet to be seen.

We have hedged some of this with fuel hedges -- oil hedges to try to mitigate some of it.

I think we have probably more transparency for 2011 than we would for 2012 at this point, Paul.

Okay.

Finally, the $35 million in trading, what's trading year-to-date so to speak, and do we have any outlook for 2011?

I would say year-to-date we're tracking favorably to the $35 million.

On 2011, I would expect that we're going to be in a similar range for 2011.

Okay, excellent.

Thanks a lot, guys.

Sure.

Your next question comes from the line of Greg Gordon with Morgan Stanley.

Thank you.

Good morning.

Good morning, Greg.

Looking at the mid-point of your guidance for the US utility business, I know that that includes some FERC transmission.

If you back out the FERC transmission and you look at the net income you expect to earn this year, what is the ROE in the Pennsylvania jurisdiction that you expect to earn?

And obviously you're hoping to get a rate hike that would drive that higher.

I'd like to know where we are tracking this year.

Tracking for the year on the distribution side of the business would be in the 4% to 5% range.

Can you roughly -- how much of the earnings is on a per-share basis would you say is coming from FERC transmission?

At an 11% on 130 rate base, probably around 25% of the earnings to 30% of the earnings.

And the change, you did reduce your CapEx budget for the 2010 to 2012 time frame.

I'm presuming that a big chunk of that is the delay in the transmission line, but are there other factors?

No.

That was the primary factor.

We did advance a few other transmission projects.

I think it was about a $140 million move for next year for moving the line and we moved about $20 million forward.

So I think was like net $120 million-ish, something like that.

It's just basically all pushed out a year?

A year to two years actually.

It went from 2012 to 2014 in terms of -- we expect by close to year end 2014 that we have our portion of line available based on current schedule with Park Service.

And the $0.05 to $0.06 at Susquehanna, that's just a couple pennies higher than I had guesstimated, but I assumed you would capitalize the O&M expenses.

Did you just choose to expense them?

Or did the accounting not allow to you expense?

The accounting wouldn't have allowed it.

As I look at the numbers, it was just around $0.05 for the margin impact and $0.01 for O&M.

And then final question on the guidance, the earnings in the UK business, I know they were down year-over-year, but they were better than I had thought they would be and they would be.

The segment guidance for the year, should we assume that given the regulatory mechanisms that were put in place that the earnings per share guidance you've given -- you're going to be able to show some meaningful growth off that over the next couple years given the rate design in that decision?

My guess is with some -- we're down in terms of some of our tax planning and tax evaluations from prior years and this year.

I think it really depends upon what happens with interest rates.

In the near term as it effects -- because we're fully hedged for 2010.

We're fully open for 2011.

The hedging that we've done for 2010 versus where forward prices are for 2011, would say that there's improvement FX.

There is improvement revenues.

It really depends upon what happens with interest rates that affects the index linked bonds and what happens to -- as late in the year now we start calculating the amounts that the inflation impact would hit revenues by for rate base in O&M.

That gets calculated from July through December.

It depends what happens with interest rates -- or inflation rates, I should say, sorry.

You think revenues should be up?

You have a handle on operating costs?

Absolutely.

FX will be favorable.

So it's interest rates that we have to worry about?

Yes.

Net-net, I would see next year -- knowing where we are from a tax perspective this year, we'll have a little bit of work to do next year on that front.

After that, is where you would see much more of the compounded growth start kicking in for international.

Okay.

Thank you.

Sure.

Your next question comes from the line of Ashar Khan with [Fizion] Asset Management.

Good morning.

Just wanted to go back -- with the offering now done and everything, you had mentioned that on a pro forma basis the transaction would only be dilutive by a nominal amount.

Is that still the factor as we go into next year?

Yes.

Okay.

And if I -- could you just go over with us what are now the expected time lines for the merger approval process as we go over the second half of the year?

Yes.

We have the change of control filings in each of the jurisdictions in.

There's a refinancing filing in in the state of Kentucky as well to basically refinance all of the existing intercompany debt from the operating companies back to Germany.

That will be refinanced with first mortgage bonds.

That filing is in.

Both the change of control and refinancing filing, we would expect determinations by the Kentucky PSC in late -- probably near the end of the month of September, right around the end of the month.

We would expect Virginia's change of control approval and the refinancing approvals to come very shortly thereafter, within a couple of weeks hopefully thereafter.

Tennessee the same thing.

The real gating approval that we need is coming from FERC, which as we've said in the past, don't expect any issues on that front.

But we expect, I believe, it's a November -- the date of the FERC hearing or the normal filing date or the announcement date on issues is November 18.

Thank so you much.

Sure.

Your next question comes from the line of Yiktat Fung with Zimmer Lucas Partners.

I was wondering about the sale of those load following contracts.

You said there was basically no impact on the gross margin in 2010.

Can you comment on whether there was an impact on the expected gross margin in 2011 and 2012 in the marketing and trading business?

Sure.

There would be a net positive effect in 2011 and 2012.

Because the net impact is really over 2010, 2011 and 2012, when you spread that out, it's really not material across the period in any one of those years.

As we look at it, yes, it is a net positive going forward, but not enough to be very material.

Okay.

Basically, you have got cash without really impacting gross margin at all?

Correct.

It's a net positive, but it's not significant.

Okay.

Can you just clarify for me the change in your basis differential assumptions again?

I have got them confused.

We basically communicated that on an unhedged basis for 2010, we'd expect to experience across the year, a negative $1 basis versus west hub.

With the hedges that we had on for the year, that will put us at a net positive $1, but for 2011 and 2012, the assumption is that our generation at the bus price is at west hub.

So, there's no premium in the numbers that you look at in the hedge table that reflect the value of the energy plus capacity plus ancillary and basis.

The basis number in those numbers is now zero for 2011 and 2012.

And what were they before from the last quarter?

There was still, I believe, $1 left in 2011 and 2012.

We had taken those down from what we had been experiencing earlier in the year, but now took that down to just flat.

The prior?

(multiple speakers)

The prior assumption for 2010 would have been $2 (multiple speakers) instead of $1.

Okay.

Thank you very much.

Sure.

Your next question comes from the line of Edward Hayne with Catapult.

Good morning.

Sorry to belabor the basis question, but just a quick follow up to Yiktat's question.

It seems like on an unhedged basis, you see actually a negative $1 spread to the bus bar this year and then you're assuming flat in 2011 and 2012.

What's driving the assumption that the basis will actually return to flat versus negative?

Yes, a couple things there.

One is we do have positions on hedges that will carryover into next year.

That's one element.

The other is there was significant transmission work this year that impacted our region.

There's still a lot next year, but we think it's going to be a little bit less than it was this year.

We've literally had hundreds of transmission projects.

In fact, I think it hit 1,000 different changes were submitted to PJM this year on transmission work.

It would be the combination of those two things.

Okay, got you.

Just a clarification on the Susquehanna Roseland line.

The CapEx reduction versus the first quarter, it looks like $350 million if I aggregate 2010, 2011 and 2012 changes.

Could you remind me how much that line is?

How much of your share that line is?

And when should we actually throw that CapEx into the forecast?

How does it flow through if the new schedule is kind of the way it comes in?

The total project estimate for our portion of the line was $500 million to $550 million, in that ballpark.

I would basically slip the schedule two years.

As you see, the year-by-year changes, I would put the CapEx if you will, back in more in the 2013, 2014 -- or 2012, 2013, 2014 from -- there was some in 2010.

But mainly 2011 and 2012, I would slip that two years to 2013, 2014.

(multiple speakers) Sorry, go ahead.

I was saying, the other clarification was I think you said to Greg, there was $20 million offsetting in 2010 so the $19 million reduction was [$40 million] of Susquehanna Roseland?

Correct.

That $40 million should start in like 2012 now and the $150 million, $185 million should then follow in the balance?

That's correct.

Thank you for clarifying that.

Sure.

Your next question comes from the line of Brian Chin with Citigroup.

Hi.

On the load following contracts, just a point of clarification, were those contracts sold that were pre-existing contracts that were in the money?

Or was that the selling of power contracts for unhedged capacity that included an up-front cash payment?

Those were legacy contracts that we had in predominantly New Jersey and Connecticut, low flying contracts, BGS-type contracts.

Those contracts, many of them were low to negative mark-to-market margins as we looked at those.

The special charge that we took in the quarter really reflects the transfer of the risks to another counter party in this case.

Obviously, they're going to discount the mark-to-market some anyway.

Then it reflects the low to negative mark-to-market margins associated with those legacy contracts and then to a lesser extent just the time value of money.

Those three things really combine to create the special charge.

The contracts themselves, because they were signed earlier when prices were higher, were of significant value and therefore, salable in the marketplace.

The other side of that, the hedges that we entered into to hedge that load were underwater significantly that -- the net of those two is really what results in the charge.

Okay, great.

Then by getting rid of those contracts -- I think you had answered an earlier question saying that your gross margin outlook hadn't changed.

Is that correct?

Not significantly in any one year given that, as Bill said, as we and others have done that have reduced or because they sold generation or whatever, exited from some legacy load-following deals.

It's different to go out in the market -- or go out to an auction and win a load deal at zero cost and then hedge it.

But with parties that pay us $250 million in cash to buy those rates, those were at somewhat of a negative mark.

I think we cleared somewhere in the 80%, 85% of -- our internal value on those deals, when you factor in that discount and then some of the negatives that were sitting out there from the hedge side of the transactions.

As you look across the 2010, 2011 and 2012 scenario, it's not a huge number in any one of the years.

It is a net positive.

Last question on this, you had done this in order to help facilitate the acquisition of E.ON assets, not because of a change in a particular market view or anything like that.

Right?

That's absolutely right.

We've raised the amount of equity financing that we needed.

We still have on the order of $200 million to $250 million of transaction expenses for the bridge facility, the cost to issue those securities, our financial advisory, the integration costs.

This really helped us close that hole, as it relates to a funding need.

We didn't -- we don't feel compelled to sell generation, as Bill said.

Selectively, we would still look at that as an opportunity.

At this point in the market as we evaluated what we did have available that could be sold, it made more strategic sense to us to move contracts like this, eliminating some future volatility risk as well.

If somebody came up with a right number for some noncore gen, we would clearly still evaluate it, but this really covers for us the remaining gap that we had from a cash perspective.

Thank you.

Your next question comes from the line of [Julian Endimullen Smith] with UBS.

Good morning.

Good morning, Julian.

Just a few quick follow ups from a few other questions here.

The first is -- we've talked about WPD and the interest rate exposure, but you mentioned earlier in your comments the inflation factor.

How is that tracking year-to-date?

What kind of year-on-year benefit can you provide?

Initial sense can you provide, if you will?

The inflation impact that we've experienced to date is negative versus what we experienced in Q1, as well as in late 2009 when inflation was tracking lower.

It will negatively impact the current year if it continues at current levels.

However, it would then positively impact the April 1, 2011 through March 31, 2012 because the rate base in our O&M costs are inflation adjusted and we get a positive revenue benefit through an automatic adjustment that happens in revenues throughout the five-year cycle.

I don't know how to call it a net positive or net negative.

But the inflation index bonds that we use to hedge a portion of the inflation exposure that we've got gets negatively impacted this year.

It was positive last year and positive in the first quarter.

It just depends upon what happens from now through the balance of the year in terms of what benefit we could see potentially -- or negative impact in 2011 and beyond.

Somewhat of a drag in 2010, but 2011 beyond potential or at least an 2011 positive here.

Correct.

Great.

Second question here.

I saw in a recent news article that you were potentially evaluating expanding your retail footprint?

I think (inaudible) ran that article recently.

Do you mind commenting on that briefly, just giving a sense of where and how you are thinking about that?

Just giving your peers' comments of late?

No problem.

I think as -- the footprint that we're talking about expanding is really in adjacent service territories to the PPL Electric Utilities territories.

We are talking about the PECO territories, the First Energy territories for example and potentially New Jersey.

On the retail front there, we're looking to do is acquire large C&I customers in markets that are opening up, namely PECO in the short term and First Energy.

We have participated in our own territory in acquiring retail large C&I customers.

The strategy around that is really to provide another hedging tool that we would hope that over a longer period of time would help mitigate some of the basis risks that we talked about earlier on the call, as well as provide some more certainty around the capacity ancillary revenues that we could get from retail contracts.

We also have some positive benefit from a margin call standpoint as well.

Credit facilities could be lowered in that event.

We don't have, what I would say, huge aspirations to be a big retail player.

I think it's just part of our hedging strategy versus wanting to be a large national retail player.

Hopefully, that helps.

Definitely.

It actually hit on the last question, sorry to bring it up once more.

Again, just going back to the basis differentials.

I'm curious, how does this guidance contrast against what you saw perhaps and what was the structurally different commodity market, call it the '08-'09 period?

What kind of basis were you seeing then on an apples-to-apples basis?

Sure.

If you look back when gas prices were very high and of course that drove a lot of the basis east to west positive.

You were seeing in some periods about $5 premiums at some of our sites to west hub.

That, as gas prices have come down, has collapsed.

I think in the forward markets back in those periods, with you are seeing anywhere from $3 to $5 premiums for the limited basis market that existed at the time.

That's how it's changed.

I think the more recent change is really around the transmission work in preparation for a lot of these projects in the region.

That's obviously a temporary couple-year event.

We would expect some improvement, particularly once our Susquehanna to Roseland line goes in.

That will allow us to access the higher value East coast markets.

Great.

Thanks.

Sure.

Your next question comes from the line of Jonathan Arnold with Deutsche Bank.

Good morning.

My question is on your assumptions for base load generation output.

They seem to have come down by best part of a terawatt hour and then you had a slight increase in intermediate peaking.

And then at the same time, all your pricing assumptions -- or the market pricing in the deck is higher.

Just talk about what's driving some of those shifts and what you expect out of the portfolio.

Without having looked at all of the detail, I would suspect that a couple of drivers there would be probably less output from the coal plants with offpeak prices being off in the forward markets.

I suspect that we are probably cycling down the min loads on the coal fleet in some of those periods.

Depending on what your starting point was, it could be related to the delay in our Susquehanna unit upgrade on unit number two, which we pushed off a year.

And that's probably the bulk of it.

There may be some timing differences on unit outages from year to year that probably impact that as well.

Thank you.

On another topic, you had -- it looked like the coal hedges you added in the fixed base price piece didn't really change the average price very much.

That seems to imply the new hedges were a good $10 or so below where the current market price, to the extent that that's meaningful, is on the NYMEX.

Can you talk to us a little about what the conditions are for signing additional contracts in coal and just the outlook as you look towards the rest of that position?

Sure.

Generally, you're correct that the contracts and our weighted average price of the contracts is still well below the forward market for coal.

I would agree that it's probably in and around about that $10 range.

I think the -- every mine is unique and every contract because of the quality of the coal and the rail differences.

It's hard to generalize a lot, but I think I would also keep in mind that these contracts take a long time to negotiate sometimes.

Some of these could have been in process for a year or certainly at six months.

It probably reflects a number of those factors.

Some element of being able to contract below the market and then an element of these things being in the works for a while.

That kind of gets you there.

Yes, and recognizing it's not a very liquid market as markets go.

Yes.

Okay, thank you.

Sure.

Your next question comes from the line of Daniele Seitz with Dudack Research.

Thank you, my question has been answered.

Thank you.

You have a follow-up question from the line of Greg Gordon with Morgan Stanley.

Thanks.

Just circling back to the question I'd asked earlier, a question I had asked earlier on the utility side.

Just going back to your Q1 slide deck.

You had given projections for rate base going out through 2014, and you had FERC rate base growing from about $847 million to [$1 billion, $1.17 billion] in 2011, $1.58 billion in 2012.

I know this has been asked twice already, but should we now assume that the 2011 FERC rate base is -- you said $20 million lower because of the deferral?

And the 2012 rate base is a couple hundred million lower and that all just gets pushed to the right?

I don't think I was talking, Greg, in terms of the rate base.

What I had said was we'd slipped net from 2011, $120 million out and then that would grow over time to reach the total of -- I think our prior forecast was right around $510 million, $520 million for the line.

That total $520 million, which would have come out of 2012 would now show up in end of 2014 type of time frame.

Got you.

But the impact on 2011 is a negative $120 million.

That's correct.

It was $140 million minus $20 million of additional other projects we put in.

But otherwise, the CapEx changes, have they impacted demonstrably what the rate base forecast would have been on the core distribution business?

No.

Okay, thank you.

Sure.

Your next question comes from the line of Edward Hayne with Catapult.

Hi, guys.

Sorry to belabor this again.

I had a follow-up question on the basis again.

In 2012, I am looking at expected average realized price in the East in the second quarter is $66.

And I think in the first quarter, it was $69.

And I know, Paul, you said that you've taken out about $1 of basis from 2012.

What makes up the other $2 of that hedging because it doesn't look like the percentages of hedges have changed.

In 2012, we had $2, not $1.

Okay.

It was $2 and the $3 may just be rounding of kind of getting the whole numbers?

Correct.

Cool.

Thank you.

You're welcome.

(Operator Instructions) You have no further questions at this time.

All right.

Thank you, operator.

Thanks to everyone on the call.

We'll continue to keep everyone updated at our next call on the progress to close the E.ON US acquisition.

We feel good about the progress we've made to date and the time line that we've described to you today to close this acquisition.

And also at the same time, we'll continue to keep you updated on our progress with this deal.

Thank you for all dialing in and talk to you at the next quarter.

Ladies and gentlemen, this concludes today's PPL Corporation second quarter conference call.

You may now disconnect.