PG&E Corp (PCG) 2003 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the PG&E Corporation second quarter 2003 earnings call. (OPERATOR INSTRUCTIONS).

At this time, I would like to pass the conference over to your host, Mr. Gabe Togneri.

Thank you.

Have a great conference and go ahead, Mr. Togneri.

Thank you.

I would like to thank everyone for joining us this morning.

A simultaneous listen only webcast is supplementing this call for the financial community.

And as usual, a replay of the webcast will be available on the PG&E Corporation homepage afterwards.

This morning in accordance with SEC rules we issued an 8-K containing our earnings press release.

We also plan to file the Corporation 10-Q later today.

Speaking will be Bob Glenn, Chairman and CEO of PG&E Corporation, and Peter Darbee, Senior Vice President and CFO.

Gordon Smith, the President and CEO of Pacific Gas and Electric Company and other members of our team are also participating.

And now I will turn the call over to Bob Glenn.

Good morning.

Our second quarter highlights include first that the quarter's earnings from operations are consistent with our previous guidance for 2003, which we reconfirmed today.

This guidance assumes that the 2003 Utility General Rate case is decided by the California Public Utilities Commission on its current schedule and will be included included in 2003 financial results.

Second, the proceedings to address Pacific Gas and Electric's settlement plan are scheduled and are progressing as expected towards resolution by year end in both the California PUC and the federal bankruptcy court.

These schedules are consistent with our planned exit from Chapter 11 during the first quarter of 2004.

And third, we recently filed with the court the financial projections for Pacific Gas and Electric Company for 2004 and beyond.

These show expected financial performance resulting from the proposed settlement and the associated stable regulatory environment.

Since the second quarter began, several significant events have occurred.

These include the Utility's proposed settlement agreement with the staff of the CPUC, the Corporation's loan refinancing, and implementation of the Corporation's strategic separation from PG&E National Energy Group and its challenges.

As a result, there is now a clearer path for greater stability in our outlook.

And we expect the value of our business will more fully reflect the solid, underlying performance at Pacific Gas and Electric Company, and the prospect of timely implementation of the settlement plan.

Now, Peter Darbee will review the financial results for the quarter.

Thank you, Bob.

Before we begin our discussion of second quarter earnings, I would like to acknowledge that the NEG and their auditors have completed the accounting review for the second quarter referred to in this release.

The issue entailed the presentation methodology for recording certain transactions on either a net or gross revenue basis.

And you'll say in our form 10-Q, we have adopted the net method of accounting for our trading and hedging activities.

As anticipated, the NEG's review resulted in offsetting changes to NEG's revenues and expenses, primarily related to hedging activities.

The NEG continues to review the presentation of its trading and hedging revenues and expenses for prior periods, which generally results from changes made in the prior year presentation related to the netting of certain trading activities, and reclassification of discontinued operations.

However, we do not expect the results of this continued review to have any material impact on the previously recorded consolidated net income, operating income, the balance sheet or cash flow.

Now let's turn to the second quarter results.

On a GAAP basis, PG&E Corporation reported earnings of $227 million, or 56 cents per share for the quarter.

This compares to total reported earnings of $218 million, or 59 cents per share for the second quarter of 2002.

On an earnings from operations, or a non-GAAP basis, the Utility and the Holding Company reported $127 million, or 31 cents per share, for the second quarter without headroom.

This compares to $207 million, or 56 cents per share, for these two segments for the quarter last year.

By segment, earnings from operations for Pacific Gas and Electric Company were 32 cents per share.

And this compares to 54 cents reported for the year ago quarter.

Although the year-over-year change in results is large, results are in line with our expectations and previous earnings guidance, given the pending 2003 General Rate case.

More than half of the quarter over quarter difference is attributable to additional expenses due to rate based growth, inflation, benefits and other costs.

These should be addressed with a 2003 GRC revenue increase.

As we previously discussed, we anticipate receiving a final 2003 GRC decision in early 2004.

Assuming the decision is received on time, the entire full year effect of the additional revenues to cover these costs will be reflected in the fourth quarter results of 2003.

As some of you may recall, we experienced the same timing issue during the last General Rate case back in 1999.

The remaining difference is attributable to the increase in shares outstanding, and lower gas transmission revenues, driven primarily by lower demand from gas fired generators during the quarter.

These two factors accounted for approximately a nickel each.

For the Holding Company earnings from operations were a loss of $2 million, or 1 cent per share for the quarter, compared to income of $6 million, or 2 cents per share last year.

The difference is primarily explained by a reduction in unitary tax credit.

With regard to headroom for the quarter, we recorded a positive $321 million after-tax, or 78 cents per share.

This compares to $366 million, or 99 cents per share for the quarter last year.

And the primary reason for the difference is higher revenue pass-through to the DWR.

As we mentioned last quarter, revenues passed through to DWR are higher this year due to a higher remittance rate, changes in the methodology for calculating revenues passed through to the DWR, and the introduction of DWR bond charges that were implemented late last year.

Year-to-date, headroom is $140 million after-tax, which is on track with our expectations.

You'll recall recall that in the first quarter this year, headroom was a negative $181 million after-tax.

Now looking ahead, we expect third quarter headroom also to be strong, reflecting higher electric usage and higher seasonal rates.

Excluded from the results I described for the Utility and Holding Company are items impacting comparability.

As in prior periods, these generally consist of higher interest costs resulting from the California energy crisis and costs associated with the Utility's and now the NEG's Chapter 11 filings.

Further details on these items and a reconciliation of our non-GAAP and GAAP results can be found in our earnings release.

Turning to the NEG, this segment is being reported on a GAAP basis only.

Consistent with the last quarter, we are not providing earnings from operations for the NEG.

In the second quarter the NEG incurred a loss of $103 million after intercompany eliminations, or 25 cents per share.

For the quarter last year, the NEG lost $241 million, or 65 cents per share.

The major items driving the quarterly results are net losses on disposal of certain assets held for sale, lower gross margins relating to the winding down of trading operations, increased interest expense, and costs related to debt restructuring.

In discussing NEG results, it is important to recognize that the PG&E Corporation officers have resigned from the boards of the NEG entities, and have been replaced by independent directors.

As a result of this change, and the NEG's Chapter 11 filing, PG&E Corporation no longer retains significant influence over the ongoing operations of the NEG.

The Corporation's investment in the NEG will be recorded at cost on the balance sheet as of July 8th, the date of the NEG's Chapter 11 filing.

Once the shift is made to the cost method of accounting, PG&E Corporation consolidated results will no longer reflect the revenues, expenses or losses of the NEG.

Excluding payments for corporate services, PG&E Corporation will only be impacted by the NEG in two ways.

The first would be any further corporate investment in, or dividends from, the NEG, which we do not expect.

The second would be related to the any IRS disallowances or credits related to consolidated tax payments made in prior years.

In summary, we do not believe that the NEG Chapter 11 filings will have an adverse material impact on the Corporation.

Before we discuss guidance, I would like to cover the recent corporate refinancing.

On July 2nd, we announced the closing of a $600 million private placement of 6 7/8 percent senior secured notes.

These notes are due in 2008.

The net proceeds and the cash on hand were used to pay $811 million in principal and accrued interest to retire the existing corporate loan.

The resultant cost savings would be approximately $40 million on an after-tax basis per year.

Now let's turn to guidance.

We are affirming our 2003 guidance of $1.90 to $2.00 per share in earnings from operations for the Utility and Holding Company combined, without headroom.

As previously indicated, this guidance is subject to regulatory decisions, most notably the GRC, which could significantly impact our earnings.

It also assumes the GRC decision is received in time to be reflected on our books for 2003, which is the current CPUC schedule.

With respect to headroom, the estimated range is 200 to $500 million on an after-tax basis.

This takes into account a number of considerations, including the stipulation on headroom that is part of the proposed settlement agreement.

As we have stated before, headroom is calculated residually and therefore it is difficult to forecast.

Recorded headroom will depend on a number of factors that may change over the remainder of the year, including sales, any changes to DWR remittances, natural gas prices, the size and cost of the remaining net open position, and any changes to other rate components.

As a result, we may need to adjust our outlook as the year progresses ahead.

We're also using this opportunity today to provide guidance for 2004 earnings from operations in the range of $2.00 to $2.10 per share.

To derive expected 2004 operating earnings, we begin with Utility performance as presented in detail in Exhibit C to the July 10th disclosure statement that is on file with the court and was issued in a Form 8-K.

We next assume $420 million of fully diluted shares for 2004.

So for example, taking the projected utility net income of 2004 of about $888 million, included in Exhibit C, and dividing that by 420 million diluted shares, results in Utility earnings from operations of $2.12 per share.

Then we consider the effect of the Holding Company.

Going forward, the annual impact of the Holding Company operations is expected to be approximately 5 cents per share.

This is primarily due to the interest expense on the senior secured notes.

Our overall guidance of $2.00 to $2.10 considers a range of potential earnings results around these point estimates.

Many key assumptions behind our guidance with respect to the utility are included in the disclosure statement.

Among these assumptions are that base revenues reflected in a 2003 GRC decision and subsequent attrition decisions that enabled the Utility to recover increased costs due to inflation, customer growth, and rate base growth.

Note that in 2004, upon the Utility's emergence from Chapter 11, and consistent with the proposed settlement, the concept of headroom will no longer be applicable.

Under the settlement, electric rates will be set to reflect the sum of the various rate components, as opposed to being frozen at a set level.

As such, they will no longer be this residual concept known as headroom.

In addition, upon the effective date of the settlement, we will include all of the interest expense for the Utility and the Holding Company in earnings from operations.

This will be the case because interest expense will return to lower and more normal levels.

Previously, the portion of the Holding Company's and Utility's higher interest expense that was attributable to the energy crisis, was considered an item impacting comparability.

Consequently, items impacting comparability after the effective date in 2004, should primarily consist of any remaining Chapter 11 related costs.

And with that, I'd now like to turn it back to Bob.

Thank you.

Looking ahead through the end of the year, our objectives are to continue to operate the Pacific Gas and Electric Company business well, to deliver the expected earnings per share from operations, and to keep the proposed settlement agreement on schedule.

The proposed settlement agreement reflects a resolution that is fair and equitable to all the parties.

And viewed as the integrated whole that it is, in the words of U.S.

Bankruptcy Court Judge Randall Knuson (ph) when he announced it, it is very much in the public interest.

At the CPUC, we have submitted testimony on the settlement plan.

And the commission's schedule calls for hearings in September, and a proposed decision from an Administrative Law Judge on November 18th, followed by a vote of the full Commission on December 18th.

On the parallel track of the bankruptcy court, a hearing was held on the revised disclosure statement already.

The revised disclosure statement and voting motion have been approved and were mailed on August 15.

Holding will end on September 29th, and the confirmation trial will begin on November 3rd.

The target remains that Pacific Gas and Electric Company will emerge from Chapter 11 in the first quarter of 2004.

So in addition to being on schedule for the settlement agreement, we have reconfirmed our prior guidance from earnings from operations with the second quarter's financial performance being consistent with that guidance.

And in establishing our 2004 guidance, the financial projections for Pacific Gas and Electric Company that we recently filed with the court show the expected financial performance consistent with the proposed settlement agreement.

PG&E Corporation is on track and on schedule to achieve these objectives.

Thank you.

Before we begin our Q&A, let me just remind you that the call contains a number of forward-looking statements, based on the expectations and assumptions reflecting information currently available to management.

Actual results may differ materially from those statements.

And as always, we encourage you to review our SEC filings to obtain additional information, and to better understand the many factors that can influence future results.

We going to follow our usual Q&A protocol now of having everyone limit themselves to one question during the Q&A.

And of course, if you have additional questions, you're welcome to get back in the queue.

And, Stephanie, with that, we are ready for your instructions.

(OPERATOR INSTRUCTIONS) Paul Fremont of Jeffries.

Thank you very much.

Can you please provide an update of the level of cash, both at the corporate level and at the Utility?

And can you also discuss the priorities use of cash at the Holding Company?

Sure.

I'll handle that.

This is Peter Darbee.

The current Holding Company cash level is approximately $800 million.

And you will note that that was an increase from the last quarter.

Since that time we have received a tax refund which was approximately $533 million.

And of that amount, approximately $361 million relates to the NEG, and $33 million relates to the Utility.

The amount that relates to the Utility we have passed down to the Utility.

The cash at the Utility is currently about $3.7 billion at this time.

Now with respect to the preference at the Holding Company, basically we are incurring expenses, day in and day out and quarterly and the like.

And our first preference is we pay those expenses.

And similarly we have revenues come in from the Utility.

More limited revenues come in from the NEG related to services that we provide both.

Right now there are not significant expenses on the horizon.

We do have debt outstanding of about $600 million at the parent company that is senior, and about 280 million that is junior.

But those are principally the sources and uses of cash at the Holding Company.

Our next question comes from Neil Choi at Goldman Sachs.

Go ahead, please.

You mentioned a base case estimate of headroom around 200 million, which I guess on a pre-tax basis implies around 300 to 350.

Can you just review what the pieces are that would influence where you end up at the end of the day?

And my understanding is that under the settlement you are sort of guaranteed at least 775 for this year?

And I'm just wondering if that is something you would really push for, or if that could be a potential negotiating point?

This is Kent Harvey at the Utility.

As Peter indicated, our current guidance for headroom on an after-tax basis for calendar year '03 is between $200 million and $500 million.

And you raised the question about how that relates to the provisions in the settlement agreement.

And the provisions there are that there is a range of headroom that is on a pre-tax basis in the settlement agreement.

It is a minimum of 775 million and a maximum of 875 million.

The upper end of the range that Peter referred to, that $500 million after tax, basically corresponds to that settlement provisions related to headroom.

There is a number of factors that can influence where we end up on headroom during the year, and as Peter said, it is really difficult to forecast.

But the biggies really are DWR remittance and sales.

That has been a widely fluctuating phenomenon for us over the last couple of years.

Also, just what our sales levels are, and then changes to either rate components as well including the outcome to other rate statement as well, including the outcome of the General Rate case.

Those, as well as other factors all kind of contribute to where we end up there.

Our next question comes from Jason West with Deutsche Bank.

I was wondering if you guys could go over -- just remind us what the process is if you were to have a delay or a rejection of the settlement agreement at the CPUC?

This is Bob Glynn.

Well, a precedent to the effectiveness of the agreement is that we obtain CPUC approval by December 31st of this year.

And CPUC's current schedule allows sufficient time to meet that date.

Under the terms of the proposed settlement agreement, it basically ends on December 31st of 2003, and so the primary alternative for us is to continue to pursue the original plan of reorganization through the bankruptcy process.

Our next question is from Theresa Ho with Banc of America.

Go-ahead please.

Yes, can you hear me?

Just fine, Theresa.

Great.

I was wondering if you could share with us any kind of information or conversation you may have had with the rating agencies since your last call, and perhaps indicate to us your level of confidence in getting the requisite credit ratings?

This is Kent Harvey again.

We have briefed the rating agencies on the settlement.

And we're in periodic contact with both S&P's and Moody's.

I would really say our level of confidence centers around the fact that the proposed settlement was structured in order to achieve investment-grade ratings.

And it is our assessment that we will be assigned a low investment-grade rating for the Utility's corporate ratings, as well as for the securities.

And I would say that that assessment is based on both the quantitative and the qualitative factors that the agencies consider.

And it reflects a lot of experience that we've had with the agencies over the last year or so, as well as the insights of our financial advisers.

And I guess I would finally add that there has been expert testimony submitted as part of the PUC approval process that is consistent with that low investment-grade rating.

Our next question is from Doug Fischer with A.G. Edwards.

Go-ahead please.

Hi.

This is actually Mike Doyle.

Doug had to jump off the call for a minute.

The question is could PG&E pay a dividend earlier then late '05, which I believe was your goal?

And under what circumstances could you see that happening?

Sure.

This is Peter Darbee.

The answer to the question is, it is possible.

Our aspiration is to pay a dividend in the second half of '05, and that is based on a production as to when we would reach with the 52 percent level with respect to equity.

And it is our belief that at that point, around mid year '05, that we would reach that point and then have funds available to pay out in dividends.

As we have mentioned before, the effect of a FERC refund would be to, in effect, pay off the regulatory asset in part.

And that would accelerate our movement towards the 52 percent equity ratio, with the result that we would, I think, be in a position to evaluate at that time whether we could pay a dividend.

And that would be then of the late '05 timeframe that we had contemplated.

Our next question is from [Ollie Olga] with [Barnum Securities].

Go-ahead please.

Thank you.

Could you remind us, what is the revenue requirement that is in your 2003 General Rate case?

And have you assumed in your guidance that you received the entire amount for '03?

This is Kent Harvey again.

The total revenue requirement in the General Rate case is the combination of both the distribution business, as well as the generation component of our business.

So it excludes the California gas transmission, our transmission pipeline, as well as excluding electric transmission, which is FERC regulated.

The total number is about $700 million, and the distribution business is approximately 550 of that it, with about 150 related to the generation business.

Our guidance essentially assumes that we receive sufficient revenues through the General Rate case to earn our authorized return on equity of 11.22.

And that really means we have to have sufficient revenues to cover inflation, customer growth, and the rate base growth that we've experienced.

Our next question is from [David Bullock] with [Sander Asset Management].

Go ahead please.

Hi.

One of the items which you mentioned in the 8-K which can materially affect results is whether PG&E Corporation is determined to be liable for any claims asserted by NEG, or its creditors in NEG's bankruptcy proceeding against PG&E Corporation, and the amount of any claims for which PG&E Corporation is determined to be liable.

And my question is what is your strategy to deal with this issue?

And how are your conversations with NEG proceeding?

This is Bruce Worthington, General Counsel of PG&E.

The forum to deal with the claims will be in the NEG bankruptcy forum.

We believe that there is not a basis for them to make a claim.

Their assertions relate to whether we have an implied tax sharing agreement.

And as we have previously stated, we do not have, and never had, a tax sharing agreement.

And we believe we will prevail if this issue is litigated.

Our next question is from Zach Schreiber with the Duquesne Capital.

Go-ahead please.

Hi Bob.

Hi Peter.

Just have a follow-up on that question.

I think you had said that you have taken -- you have a $500 million influx of cash at the Holding Company level, $361 million of which was tax benefit benefits which the Holding Company received in the second quarter from taxable losses and charges at the National Energy Group level.

Is that correct?

That's correct.

Can you say what the cumulative taxed cash benefit for the Holding Company has been from taxable losses that occurred historically at the National Energy Group level?

I don't have that precise number in hand right now, Zach.

What I recall is that the amount that they incurred and the amount that has been paid down from the parent were about equal prior to the incurrence of this latest tax return.

So if one were to look at it on a net basis, the 361 million would be really the number that people would look to as to I would expect the claim they might raise.

Our next question is [Sirus Saditti] with J&B Capital.

Go ahead please.

Good morning.

How are you?

A quick question.

I'm trying to reconcile your guidance of 2 to 210 for '04.

The incremental interest expense is between 12 and 10 cents.

Does that represent the incremental interest expense between the first of the year and when you emerge from bankruptcy?

Yes, it does.

So basically, that is just whatever penalty interest you continue to pay until emergence?

Yes.

Our next question is from Vic Tietan with Deutsche.

Go ahead, please.

Thank you.

I guess many of the questions have already been answered, but what about this governor recall in California, how does that affect in any way either ongoing business or the settlement process?

You know, Vic, overall the way we look at that is that we don't receive any state budget allocation, and we don't see any linkage on that side.

On the other side, regardless of the outcome of the recall, we believe that a governor's attention is going to be focused on the state's fiscal situation and resolving.

So we don't see a lot of linkage between the recall issue as an issue and our business prospects going forward.

Our next question is from [Michael Lucas] with Appaloosa Management.

Go-ahead, please.

How is it going guys?

Why does the tax rate on part of the plan look so high?

It it looks about to be somewhere around 43 percent?

You're talking about the Exhibit C forecast going forward, Michael?

I am trying to triangulate on where you are finding that to help us answer sense you.

His line is no longer open.

Okay.

Well then I'll just continue that response.

And we will have to get Michael when he comes back on the queue.

But I think it is fair to say that there wasn't a clear understanding of what time period the question referred to.

So, operator, please have him in the queue, and we will go on to the next question.

He has just rejoined us.

The queue line is now open.

Good.

Hello?

Did you hear us ask for your clarification?

Yes, I did.

In the plan for the Exhibit it has income taxes for '04, '05, '06.

And it looks to be running at a 42.5 percent rate consistently.

This is Chris Johns, the Controller.

I think for the most part it is just the impact of the combined federal and state tax rates that we have here.

And our state taxes are relatively on the high side, and so that is really where the effective rate comes from.

At this time we have another question from Paul Fremont of Jeffries.

Go ahead please.

Looking at the utility CapEx in the plan, it looks to be between 1.6b and 1.8b.

That looks a little high relative to historical levels in the late '90s.

And I'm wondering is that that just maintenance CapEx, or are you including some assumed upgrade or increase in your asset base?

Paul, this is Kent Harvey.

The range of approximately 1.7 billion, going forward for a few years, is fairly consistent with the recent performance, with one exception, and that is really only quite recently have we been experiencing the level of expenditures in the electric transmission business that we expect for a few more years now.

And as you know, that part of our business, you tend to have capital expenditures that are very lumpy projects.

They are large dollar volume.

We have been doing them for several years, as we have been upgrading the system to accommodate all the additional load growths under this strong economy in California during the '90s.

And we have a few more of those large projects that typically are focused on either local load areas that need new significant upgrades, or the longer-term transmission.

Our next question is from Tom O'Neil with Lehman Brothers.

Go ahead please.

Yes, good morning.

I had a question on the common dividend, not on Utility dividends.

Just curious, is there anything preventing the use of the cash raised from the additional shares that you're contemplating issuing, as well as the tax refund, to start a common dividend earlier?

We're getting an answer for that question for you right now, Tom.

I would have to confirm this with our General Counsel, but my recollection is that we're only permitted to pay dividends out of the parent to the extent that we have received dividends from the Utility.

Our controller is confirming that that is his recollection.

Our next question is from Greg Gordon with Smith Barney.

Go-ahead please.

Thanks.

My question relates to some of the assumptions you're making with regard to the projections for the rest of '03 and '04.

You say that the earnings guidance is predicated on getting the rate relief that you filed for.

But, I guess, my question is, given the underlying framework of the settlement agreement that it provides for movement towards a stable and high investment grade credit rating, shouldn't we think about the probability of that rate treatment as being fairly high?

Sort of, they can't honor the settlement unless they give you the rate treatment that gives you revenues that allows you to move back towards the credit ratings articulated in the settlement?

Is that the right way to think about this?

Go-ahead, Kent.

This is Kent Harvey.

The settlement agreement does have provisions to insure that PG&E is treated fairly, just as other utilities.

And we think that we made a very strong case and have a very strong record.

Rate case hearings have now been concluded.

So we are going to continue to pursue all of these revenues, because they reflect the level of expenditures that we are experiencing.

And Greg, this is Gordon Smith of Pacific Gas and Electric.

I look upon them as two separate paths.

One is the proposed settlement agreement with the staff of the Commission to emerge from bankruptcy with investment grade ratings.

The other is what is the cost of doing business in 2003, which is that 2003 tester rate case.

To the extent the Commission gives us revenues that are less than what we have requested in that proceeding, we well take measures to adjust our spending levels to coincide with the levels deemed appropriate by the Commission.

Our goal every year is to earn our authorized rate of return.

Our next question is from William Matthew with Canyon Capital.

Go ahead please.

Can you just give us a little clarification on the CapEx number that is used in the projections in the disclosure statement, in terms of it is well in excess of depreciation rate.

If we're trying to figure out what the rate, the PP&E correct rate base is going forward that you are going to earn 11.22 on?

How much of that CapEx is going to be allowed to increase that actual PP&E base, and how much would not be allowed by the CPUC in terms of where you are allowed to earn your return on equity?

The capital expenditure forecasts approximate 1.7 billion going forward.

That is for all components of the Utility, including electric transmission for example, which is FERC regulated.

So we have no reason not to expect that those costs would not be recovered from FERC.

But it is actually not a CPUC decision per se.

Our depreciation, I believe, for the Utility is very roughly annual depreciation is in the $1 billion range.

So you can see the kind of growth that we anticipate over the next few years.

And our recorded rate base overall for the Utility in 2002, on an average year basis, was approximately $14 billion.

And this is Gordon Smith of the Utility again.

And I would save we expect every dollar that we invest in capital expenditures, one, to be prudently incurred, and two, to go under rate base.

We do not anticipate any of our capital expenditures going forward to be disallowed or not included in rate base.

At this time, we have another question from David Bullock with Sander Asset Management.

Go ahead please.

Hey, I just want to understand the merits of your arguments in connection with the NEG tax sharing situation.

They're claiming it sounds like they have a tax sharing agreement; you are claiming they don't.

Do they have a tax sharing agreement?

Have they produced something?

What is the basis of their claim?

This is Bruce Worthington again.

As I stated before, we do not have, and have never had, a tax sharing agreement with the NEG.

Their argument would be that there's an implied one based on past performance.

And we will have to see what they can use to demonstrate that in court.

Our next question is from Zach Schreiber with Duquesne Capital.

Go ahead please.

Hi.

Just as a follow-up on that, on the tax sharing agreement.

It was my understanding that there was never an expressed tax sharing agreement, but that there more of an ad hoc tax sharing agreement in which you kind of dealt with it on a year by year basis.

Is that correct, number one?

And number two, if you have an ad hoc tax sharing agreement in place for a certain number of years, do the courts apply some sort of common law marriage concept to it that it is ad hoc for seven years, such that it effectively moves from an ad hoc deal to an implied or expressed deal?

And are there any court precedents that you could refers us to that sort of support your arguments here, recent ones?

Thank you.

The treatment of tax benefits is as you described.

It was decided each year based on whether or not we were going to make a capital infusion in the NEG.

In some years we decided to do that, and in some years we did not do that.

With respect to the legal arguments, we will wait to present those in court.

(OPERATOR INSTRUCTIONS).

At this time I have no further questions waiting.

Alright.

Well, in that case, I would like to thank everyone again for joining the call.

And have a great day.