PG&E Corp (PCG) 2016 Q2 法說會逐字稿

Good morning and welcome to the PG&E Corporation second-quarter 2016 earnings conference call.

(Operator Instructions)

At this time I'd like to introduce your hostess, Ms Janet Loduca. Thank you and enjoy your conference. You may proceed, Miss Loduca.

Thank you, Jackie, and thanks to those of you on the phone for joining us. Before I turn it over to Tony Earley, I want to remind you that our discussion today will include forward-looking statements about our outlooks for future financial results which are based on assumptions, forecasts, expectations and information currently available to management.

Some of the important factors that could affect the Company's actual financial results are described on the second page of today's slide deck. We also encourage you to review our quarterly report on form 10-Q that will be filed with the SEC later today and the discussion of risk factors that will -- appears there and in the 2015 annual report. With that I'll hand it over to Tony.

Well, thank you, Janet, and good morning, everyone. I appreciate you joining us this morning on what I know is a busy day for all of you. I'm going to start with some opening remarks and then turn it over to Jason to go through our financial results.

We continue to believe that the key focus area shown on slide three provide the foundation for operational and financial success. So I'll start with how we're thinking about the future in the context of California's clean energy policies. With the passage of AB350 last year California will be doubling its energy efficiency goals and increasing the renewable portfolio standard to 50% by 2030.

Over time these mandates will impact both our electric procurement needs and our investment opportunities. On the investment side California's policies will drive capital expenditures in both the electric distribution and transmission systems. We're going to have to continue to upgrade the distribution grid to sport increasing levels of distributor resources, and we'll need new and upgraded transmission lines to support the utility scale renewables required to meet the higher RPS standards.

On the procurement side we expect electric demand to decrease as customers continue to reduce the energy they need from PG&E through energy efficiency and distributed generation. We also expect that some cities will pursue community choice aggregation where they will purchase their own generation.

As we consider the changing energy landscape in California it became clear to us that we needed to take a hard look at the future of Diablo Canyon. Working with a diverse coalition of labor and environmental groups we crafted a joint proposal to retire Diablo Canyon at the end of its current license terms which are 2024 for one unit and 2025 for another and to replace it with a greenhouse gas free portfolio of renewable energy, energy efficiency and energy storage.

We've also voluntarily committed to a 55% RPS target beginning in 2031. I'm very pleased to report that the State lands commission recently extended the lease for Diablo Canyon's intake and outflow structures so that it now runs through the current NRC license terms, and that was an important first step in carrying out our plan. In August we'll be filing an application for CPUC approval of the joint proposal by the end of 2017.

We believe the joint proposal fully supports California's long-term clean energy goals while providing time for a thoughtful transition to new greenhouse gas free resources. Turning to customer expectations. We've made significant progress in all of our key rate cases during the quarter. As you know we received a final decision on the first phase of the 2015 gas transmission and storage rate case in June.

The decision acknowledged the need to continue investing in the safety of the system and authorized revenues for much of the work that we had requested. Given the significant delays in the case that also included revenues for an additional attrition year in 2018. In a separate phase of the case the commission will consider how to allocate the $850 million disallowance ordered last year as part of the San Bruno penalty decision.

We hope to get a final phase 2 decision sometime this fall. And Jason's going to take you through our expectations around the financial impacts of that decision which is quite complex. Moving on to our General Rate Case which covers most of our business. We've been engaged in settlement discussions with other parties over the last few months.

Last week we filed a notice of settlement conference which will take place on August 3. But given the confidentiality of settlement discussions we can't really comment further today, but we do consider this a positive development. We're also continuing to have settlement discussions in the TO 17 rate case. The rates are in place subject to refund while the case is pending. Tomorrow will be filing our next electric transmission rate case TO 18.

We'll be requesting an additional $100 million in capital expenditures which we've incorporated into our multi-year projections. Let me shift to the operational side of things. As we get into the driest part of the year, we've launched aggressive fire preparedness efforts focused on prevention, detection and response.

Although we have had more rain this year than last, California's experiencing significant tree mortality following several years of drought. To mitigate this increased fire risk we're supplementing our annual inspections by conducting daily aerial patrols and proactive foot patrols over fire prone parts of our service territory. And finally we continue to work towards resolving outstanding issues.

In June we received a presiding officer's decision in the gas distribution record keeping investigation. Overall we thought the decision was balanced recognizing the actions we've taken to improve our records and the safety of the system and finding that many of the violations were isolated rather than systemic issues.

The safety and enforcement division and the city of Carmel have appealed the decision seeking a higher fine, and we now are waiting for a commission to issue a final decision. The federal trial in the -- or the trial in the federal criminal case began in June.

And the case was submitted to the jury yesterday. Because we're in the sensitive part of the trial we're just not in a position to comment on any of the specific evidence or testimony. I can tell you that we continue to believe that no PG&E employee knowingly and willfully violated the law, but now it's in the hands of the jury.

So to sum things up, we are working to resolve all of our pending rate cases, and we continue to make steady progress on outstanding regulatory and legal issues. And we are well-positioned to help drive California's clean energy future through sustained investments. So with that let me hand it over to Jason to walk you through our financials. Jason?

Thank you, Tony, and good morning everyone. Before I get into the second quarter results I want to provide a brief overview of the phase 1 gas transmission rate case decision. I'll start by saying that this is one of the most complicated rate case decisions we've ever seen. Our financial results and projections reflect a number of key assumptions and new items from the decision. So I want to make sure that we're all grounded on those.

Turning to slide 4. The first thing I'll cover is revenue recognition. Because the decision came so late in the rate case period, we have not collected any incremental revenues for 2015 or for the first seven months of 2016.

Those incremental revenues make up our under collected amounts. There are two important points I'd like to cover regarding incremental revenues. First, while the phase 1 decision allows us to begin billing customers on August 1, we would not be able to recognize the full true up of the under collected revenues until after the phase 2 decision when we know the final revenue requirement.

Second, the phase 1 decision requires us to amortize these under collected amounts over 36 months. Utility accounting rules allow us to recognize revenues only if they will be collected within 24 months of the end of the year. As a result, assuming we get a final phase 2 decision by year-end, we will recognize 29 months out of the 36 month amortization period in 2016.

The 29 months includes the actual revenues we will collect in the remaining five months of 2016 plus the amounts we will collect over the subsequent 24 months. This means we'll recognize the remaining seven months of under collected amounts in the first quarter of 2017. These revenue recognition factors are important assumptions for the guidance I'll be covering today.

The decision also impacts our capital expenditure forecasts. First it permanently disallows a portion of the 2011 though 2014 capital spend that we sought to true up in this rate case and subjects the remaining portion to audit with potential for future recovery. The decision also includes a number of program specific cost caps in one way balancing accounts.

Since we are not in a position to adjust the spending we've already completed, we anticipate that some capital programs will exceed the authorized amounts over the rate case that will not be recoverable in the future. As I'll discuss in a minute, we've taken one-time charge for this during the quarter for those items.

And finally the phase 2 decision allocating the $850 million San Bruno penalty creates some additional uncertainty. Several parties have suggested that all of the $850 million should be allocated to expense. For purposes of today's presentation, we assume that we receive a final phase 2 decision this year and that the penalty will be allocated to roughly $690 million in capital and $160 million in expense consistent with the original San Bruno penalty decision.

We'll obviously need to make adjustments if the phase 2 decision changes that allocation. With that overview let's go through the financials. Slide 5 shows ours results for the second quarter.

Earnings from operations came in at $0.66. GAAP earnings including items impacting comparability are also shown here. Pipeline related expenses came in at $27 million pretax for the quarter. Our legal and regulatory related expenses were $14 million pretax, and fines and penalties were $172 million pretax. The fines and penalties items reflects two components this quarter.

The first component represents our estimate of the disallowed safety-related capital resulting from the San Bruno penalty decision which we are accruing as we complete the work. This item totaled $148 million pretax for the quarter. The second component is a fine of $24 million for the gas distribution record keeping investigation. For now we reflected the presiding officer's decision.

We'll make any necessary adjustments when the commission rules on the appeals. Butte fire related costs also reflect two components. First we booked $49 million pretax for additional cleanup, repair and legal costs associated with the Butte fire. We do not expect any additional cleanup and repair costs in the future.

This item is offset by a positive insurance receivable of $260 million which reflects the low end of the range for estimated insurance recoveries. The two components net to a positive $211 million pretax. One important note regarding the insurance receivable. While we have recorded the low end of the range at this time, we plan to seek full recovery of cost for insurance and believe that nearly all the third-party claims ultimately be recovered through insurance so the $250 million receivable should not be interpreted as a ceiling on insurance recovery.

The next line item GT&S capital disallowance is new this quarter. We booked a charge of $190 million pretax reflecting the two components of disallowed capital I discussed on slide 4 which are the $135 million for work performed in 2011 through 2014 plus $55 million for capital spending 2015 through 2018 that we expect will exceed authorized cost caps. The last line relates to the impact and the timing of the gas transmission rate case decision.

This is where we will reflect out of period GT&S revenues once we begin recognizing them. To ensure that our 2016 results are comparable year-over-year, we plan to reflect all of the revenues authorized for our 2016 cost of service and earnings from operations this year. And reflect the out of period revenues as an item impacting comparability.

Consistent with the revenue recognition factors on slide four, this item will continue into 2017 when we recognize the remaining seven months of the out of period revenues. Moving on, slide 6 shows our quarter-over-quarter comparison for earnings from operations of $0.91 in Q2 last year and $0.66 in Q2 this year. The timing of taxes during the quarter with $0.08 negative.

As a reminder this line is purely a timing item that in total will reverse by year-end. A number of smaller miscellaneous items totalled $0.08 negative for the quarter. And nuclear refueling outage during the quarter resulted in $0.06 negative, regulatory and legal matters totalled $0.05 negative for the quarter and issuing additionally shares resulted in $0.03 negative.

These negative drivers were partially offset by growth in rate-based earnings which was $0.05 positive for the quarter. This item reflects assets covered by our General Rate Case and our electric transmission TO rate case. It does not include the gas transmission rate case since we did not recognize any revenue increase in Q2.

Today we are reaffirming our guidance for earnings from operations of $3.65 to $3.85 per share, and that is shown on slide 7 along with the GAAP guidance. On slide 8, you can see the underlying a sentence for that guidance which we've updated to reflect the phase 1 gas transmission rate case decision. Starting at the top left, we assumed capital expenditures of roughly $5.6 billion for the year consistent with the last quarter.

The gas transmission CapEx is now $700 million consistent with the amounts authorized in the phase 1 decision. Last quarter we shared a range of $500 million to $700 million. We've also reduced the electric distribution CapEx by $50 million to reflect our current spending for projections.

Moving to the top right we've also adjusted our assumption for a weighted average authorized rate base to about $32.4 billion from our previous assumption of about $32.6 billion. Consistent with the phase 1 gas transmission rate case decision we've adjusted the gas transmission rate base to $2.8 billion down from $3 billion to $3.4 billion range we showed last quarter.

This reduction is driven primarily a removal of the roughly $700 million in 2011 through 2014 capital that we had expected to true up in rate base this year. As a reminder rate base incorporates depreciation and deferred taxes. So it's not a one-for-one relationship with capital expenditures particularly since this capital was spent several years ago.

As a result, the rate base impact of this spend is closer to $500 million. On the bottom right, I want to reiterate that our 2016 guidance assumes that we received a final phase 2 decision in the gas transmission rate case this year and that it allocates the disallowance of safety-related spend consistent with the San Bruno penalty decision.

The other bullets are consistent with what we've shown here before. The bottom line is that based on these assumptions we continue to target earning our authorized return on equity across the enterprise plus the net impact of the other earnings factors listed here. Turning to slide 9 the guidance for our 2016 items impacting comparability has been updated to include the phase 1 gas transmission rate case decision and our assumptions for phase 2.

I will walk through each of these items briefly. There's no change to the range for pipeline related costs which covers the work to reclaim our rights of way. Legal and regulatory related expenses also remain unchanged. The fines and penalties item has been adjusted for two items. First the guidance includes the $24 million accrual for the presiding officer's decision in the gas distribution record-keeping investigation.

And second, the disallowed expense charge for the San Bruno penalty has been reduced from $160 million, to $130 million due to the 36 month amortization. The remaining $30 million will shift to 2017. This item excludes any additional potential future fines or penalties beyond our current assumptions for the distribution record-keeping penalty and the San Bruno penalty.

When we have a final phase 2 decision in the gas transmission rate case we will also include the associated ex parte penalty in this item. The Butte fire related costs are shown next. At this time we remain unable to estimate the high end of the range for third-party damages associated with the fire. As a reminder, last quarter we booked $350 million to reflect our estimate of the low end of the range for property damage. This quarter we recorded an insurance receivable of $260 million reflecting the low end of the range for estimated insurance recoveries.

The remaining amounts reflect our recorded legal and operational costs associated with the Butte fire. Next we show the new item impact in comparability for the GT&S capital disallowance which is consistent with the assumptions shown on slide 4. The last item covers the impact of the timing of the GT&S decision. The $350 million shown here reflects the 29 months of out of period revenues we expect to recognize in 2016.

As I mentioned this item will continue into 2017 when we recognize the remaining seven months. Moving on to slide 10. We currently expect to issue right around $800 million in equity and 2016 so we've eliminated the range we've showed in Q1. The incremental equity required by the new charges to this quarter is roughly offset by the Butte fire insurance receivable.

In the first half of this year we issued about $300 million through our internal and Dribble programs. Turning to slide 11 we are updating the multi-year CapEx ranges. For gas and electric distribution and generation the high end of the range continues to reflect the requested amounts in the General Rate Case through 2019. For gas transmission the high end of the range through 2018 has been reduced to reflect the lower authorized CapEx in the phase 1 decision in the gas transmission rate case.

These expenditures are held flat in 2019. For electric transmission the high end of the range in 2017 now reflects the request in the TO 18 electric transmission rate case which we will file tomorrow. These expenditures are held flat in 2018 and 2019. Taken together these changes reduce the high end of the range to $6.4 billion compared to $6.5 billion shown last quarter.

The low end of the range remains consistent with our 2015 capital spending. Overall you can see that we continue to expect robust capital spending going forward. On slide 12 we've updated the rate based ranges consistent with the capital spending on the previous slide.

The high end of the range also assumes that the portion of the 2011 through 2014 capital spend that is subject to audit is added to rate base in 2017. These adjustments narrow the range of rate based to a compound annual growth rate of 5.5% to 6.5% between 2017 and 2019. Finally we've added a new slide 13 showing our dividend payout ratio targets. Consistent with our announcement during the quarter we increased the dividend this year by about 8% to $1.96 per share.

We are targeting a 55% to 65% payout ratio with a specific objective of reaching 60% by 2019. I know we've covered a lot this morning. Let me close by saying that we continue to reach important regulatory, financial and operational milestones, and we are confident in our ability to deliver on our plans as we position the Company for future success.

So with that let's open up the lines for questions.

(Operator Instructions)

Steve Fleishman, Wolfe Research.

So I think I got all the moving pieces here and appreciate you going through it. (multiple speakers) Just to clarify so on the GT&S rate base that's subject to the audit, that is excluded from the 2016 rate base but then it comes back in and 2017?

That is correct.

Okay.

At the high end for the 2017 rate base.

Okay. At the high end. Okay. Is there - - while in 2016 while it's kind of in this limbo, do you have any earnings on it like non-rate base earnings or only when it goes in to rate base? Does it get like AFDC or something or some kind of treatment?

No. It's not earnings rate base in 2016.

Okay. For example it's not in your 2016 guidance essentially range or earning money on that?

That's right. We pulled it out and that was really the key adjustment to the gas transmission and storage rate base reflected in our assumptions.

Okay. And then just the high end of the rate base ranges through 2019, the reason those came down is what then? A little bit?

We're tightening the ranges because we because of the gas transmission phase 1 decision. Historically they've reflected the high end of the range that we -- based on the amounts requested in the case. And now that we have a decision on that CapEx and rate base, we're adjusting the ranges to be consistent with that decision. That reduction - - (multiple speakers) I was just going to mention that reduction is offset by a small increase from electric transmission.

Got it. And you kind of narrowed brought the high end down brought the low end up? Kind of narrowed the rate.

Yes you know I think as we resolve some of these regulatory proceedings we're getting more certain on what the range is and that's what this narrowing reflects.

Okay. And then just on equity, you had the same amount of shares maybe this is just a rounding thing, but you had the same amount of shares outstanding at the end of Q1 and Q2 but you're saying you issued $300 million in equity, and I recall that are being lower for Q1?

I don't have the Q1 number in front of me, but we did issue through the second quarter of the year $300 million in additional equity for 2016.

Okay. Okay. I think that's all I had. Thank you

Anthony Crowdell, Jefferies.

There was a story in one of the industry papers that spoke about the trial and said the judge in the federal trial had maybe lowered the bar on proving a willingness I guess for a guilty verdict, and I know you can't speak about the trial, but I'm wondering is there a lower bar in the decision of an alternative fines act, or is there a higher standard there than in the criminal trial?

Let me ask Hyun Park our General Counsel to comment on it.

I don't think that relate to the alternative fines act portion. I have not seen the specific article that you're talking about. But I think what you may be referring to is a jury instruction that the judge gave with respect to willfulness in the context of a corporation as a defendant, and he said that you do have to find that a specific employee acted willfully even in the Corporation context. So that may be what you are referring to.

Yes. That's correct. And then lastly on related to the alternative fines act has there been any discussion on what the gross gain was realized by the Company?

So it's the number that appears in the indictment which is $281 million. That's what the government has alleged and under the alternative finds act if they can prove beyond a reasonable doubt, that the criminal violations led to the $281 million gain then under the act you can actually double that as the maximum fine.

Great (multiple speakers)

But there will be no discussion of that unless we get to a phase 2 in the trial.

Okay great. Thanks for taking my question.

Julien Dumoulin-Smith, UBS.

So just to think a little bit more strategically here, obviously developments with Diablo Canyon how are you thinking about the eligibility for utility owned assets to replace the $2 billion or so in rate base today for Diablo Canyon? And then separately I'd be curious, what is the impact to consumers from a bill inflation perspective for the Diablo Canyon early retirement? Or I suppose retirement without extensions?

Julien, hi, this is Geisha Williams. So regarding the Diablo Canyon issue utility ownership of replacement power our intention is to issue a number of trenches the first thing being energy efficiency the second one being non-GHG resources, and in both cases those will the open for a competitive solicitation and of course the utility could conceivably be a bidder in that regard. So it's possible. But that's to be determined in the future.

As far as replacement of the rate base that's beyond the -- I guess the guidance period for us or for the period for which we are looking at our rate based but I mean obviously if you look at the structure the regulatory structure here in California than really conducive because you need to add the modernize the infrastructure. We've had a very healthy capital program for many years and I don't see that changing but again, what that may look like beyond 2024, 2025 is to be determined.

Got it, okay. And then just turning back to the other side of the numbers if you will. Elaborating a little bit on Steve's question can you comment real quickly in your numbers what's reflected for if you were to get a decision in the near term on the CapEx versus expense how you would recognize that, would you immediately reflect if it was to be an expense in your numbers and that would be an uplift for the back half as soon as you got that outcome?

I think this GT&S rate case is a pretty complex one so, our guidance assumes that the phase 2 decision allocates the San Bruno penalty disallowance consistent with the original allocation so about 80% as a capital disallowance and about 20% as expense. As you know, we've been accruing the capital portion of the disallowance since we first originally received that decision, and so really what remains outstanding is the disallowance for expense. And what we've talked about in the past is that disallowance for that expense is really a disallowance of incremental revenues.

So I would say the one key change for the quarter is that given the 36 month amortization period which prevents us from recognizing all of the true up revenues essentially we only recognize about $130 million of that San Bruno expense disallowance here in 2016. The remaining $30 million which we had thought would be recognized in 2016 is now expected to be recognized in 2017 assuming that the allocation between capital and expense does not change in the phase 2 decision.

Got it. Just to be clear, as soon as the - - when you get the decision that's when the expense hits or the true up and then going forward the rate base would be adjusted correspondingly as [post the] next update provides?

That's correct. As soon as we get the final decision that's when we would take that $130 million disallowance for expense, but it is the final decision that we need before we record that.

Got it. All right. Thank you.

Greg Gordon, Evercore ISI.

When we think about earnings from operations and we go from 2016 to 2017, 2017 to 2018, 2018 to 2019 we should be thinking about the rate base slide you show us on page 12 and what we think the earnings power is of the business there net of other factors and what the other factors would be on page 8. So I guess the big question is what we're looking at 2018 in 2019 earnings, how many -- are we going to be through this period where there are these multiple bridge line items from operating basis earnings to GAAP basis earnings?

Once we're in 2018 in 2019 do you expect that all of the repercussions accounting differences from all this complex rate making and disallowances will be behind us and that they'll be a very tight band between your operating basis earnings in your GAAP basis earnings? If not what will be continuing on?

Thank you for the question. Assuming no new items, we do expect that we will resolve these lingering issues by 2017. So that in 2018 through 2019, our EPS growth will more closely align to the rate base growth that is presented on slide 12.

I will say though that we have a strong CapEx program, and if we spend at the higher end of that range we will be required to issue some additional equity to fund that. And so there will be a small amount of dilution from those -- from that additional equity, but our earnings profile should more closely match our rate based starting in 2018.

Greg this is Tony. I look at the left side I should point out that the Butte fire related costs that are listed there on slide 9, historically those sorts of issues not only with us but with other California go on for multiple years. But certainly the gap will, will narrow because a lot of the other regulatory stuff should drop off.

Great. That's -- investors just want to understand the real earnings power of the company is so that they can think out where your dividends going given what you've articulated as the policy so that they can put the right value on the shares which looks like it's a lot higher than where it is trading now, but I think we've got to get through some of these complex issues first. So thanks guys. I appreciate it.

Jonathan Arnold, Deutsche Bank.

Picking up on equity and a couple of the other themes, does the way in which you're going to recognize the GT&S with some of it rolling over into 2017, does have the effect of having pulled forward some equity pushing you into that higher end in 2016, but maybe tempering whatever you may or may not have to do in 2017?

The delay in terms of getting a final decision here that allows us to recognize this revenue has a small impact. This is really a timing related item that we're going to look to address appropriately with our financing, but it does have a small impact on our equity needs here in 2016.

And on 2017 how should we be thinking about whether you will or won't be an issuer in 2017? How much variability is there depending on some have these other pieces shake out?

Well, I think it's -- there are going to be a couple of items that in our items impacting comparability that transition into 2017. I still think the dominant item in our gas business that we're focused on is finishing our pipeline rights-of-way program where we're reclaiming our rights away. As we said that's a five year program not to exceed $500 million that we will completed 2017.

The rest of the - - there will be some small adjustments related to the GT&S revenue timing impact that I mentioned. Those will largely net out, and so I think it starts to look like a more normal equity pattern in 2018 but certainly substantially reduced from 2016.

So I mean I guess reduced, more normal, what is the new normal? How much of 2016 do you consider to be kind of outside of the normal?

We're not giving equity guidance for 2017 at 2018, but really the two main drivers continue to be our CapEx and our unrecovered costs. Those unrecovered costs will reduce significantly in 2017. And with the exception of Butte fire which as I've mentioned we plan to seek recovery through insurance. We'll get back to a level of acquisitions that are really driven largely by our CapEx program.

Thank you and just if may on the quarter, you have this $0.08 of miscellaneous inside it's quite a big number any insight as to how some of that is likely to continue through the rest of the year guidance assuming some of it is not going to happen again but what's in behind that?

Sure. Sure. As usual what I would say miscellaneous comes includes number of small items. Some of them are timing related, some are not. But I think what's really important to emphasize though is we're reaffirming our annual guidance from earnings from operations this year. So I think that is really our focus.

Okay. I'll leave it there. Thank you guys.

Michael Lapides, Goldman Sachs.

Jason, want to focus a little bit on cash. You're talking about the revenue recognition for the delayed GT&S rate case. But can you talk about when you get the cash them in your have a whole year of a revenue increase in 2015 and seven months of that revenue increase in 2016, where not only do you not recognized it from an earnings perspective you've not gotten -- you haven't gotten the cash.

Can you talk about when you'll get the cash for that, for that period. Do you collect it over a 12 month, 24 month, 36 month and can you put some numbers around that just to quantify how much cash that is that you've not collected to date but you anticipate collecting once everything gets finalized?

Sure. So we have not collected roughly 19 months worth of incremental revenues. So that's all of 2015. And then our 2016 revenues through July.

The phase 1 decision allows us to start billing customers in August 1 at that new revenue requirement so we'll start collecting those incremental revenues here in August, and there will be a 36 month amortization period starting in August, and so that will be the period of time in which we recover those incremental revenues.

So it really is just a timing item between when we recognize, when we're able to recognize these revenues and when we collect them the amortization period.

And how much is that from a cash perspective the amount that is being amortized over 36 months?

Roughly in a phase 1 decision, the annual revenue requirement increase was about $500 million, on a full year basis. So about $750 million in total. I will say though that that's the preliminary authorized revenue requirement, because it can be modified in the phase 2 decision as the commission looks at how to allocate the San Bruno penalty.

So you've got - - ex that phase 2 decision you got $750 million, or roughly $250 million year from the cash flow perspective, to help make up for - - to help recapture some of that revenue just due to the delay in the case.

That's correct. Yes.

That on the core California GRC and obviously lots of dockets in California not just yours but other utilities as well have faced delays as well. When that rate case gets implemented how should we think about the cash flow that you would get just due to the timing delay?

Yes. I guess one of the issues will depend upon what happens with the settlement discussions, and I will ask Steve Malnight to comment on that.

Yes, Michael, so I think in terms of the outcome for the case first it would say like Toby mentioned we've announced the settlement conference. We're hopeful that we can resolve that. The current schedule would call for decision in January. As you mentioned, there has been delays in many of the rate cases but at the same time the commission's already authorized retroactive revenue to be collected if the decision comes late, so we will collect it from January in a similar way to what Jason described.

I think that in this case we just had a pretty extreme example in the GT&S case which really was an unusual case. It was extremely complex, and I think we saw much longer delay from the commission. So will see how the GRC plays out.

Got it and if let's say new rates came into effect in January how much of a delay is that?

That's a mean the case is for revenues in 2017 so if we got a final decision in January, as soon as we get implemented in rate would just be a few months of delayed revenue.

Got it, okay. Last item just trying to think in this is obviously maybe a little bit more for Tony. How are you thinking about potential investment opportunities outside of the core Pacific Gas & Electric utility and when I say that I mean things like Midstream, things if possible like on the renewable side. We're just trying to think about once things get a bit more notable at PG&E how to think about what the investment opportunity is for the broader Corporation.

Michael, you're exactly right. This is the time really to start to think about that so as we start to get a number of these proceedings behind us. And we have actually started work on that let me ask Geisha to comment on that on what were doing in transmission, electric transmission and then I'll come back and comment a little further.

Hi, Michael, this is Geisha. On the electric transmission side, last quarter we announced an alliance with TransCanyon which will give us an opportunity to really compete for transmission projects not just within our own service area but within the broader CAL-ISO system.

We think there's a lot of opportunity associated with transmission projects as we go to a 50% and in our case a 55% RPS level by 2030. So we see a lot of opportunity both within our service area and now that we've got the[destrobe] partnership with TransCanyon actually an alliance with TransCanyon, we see some opportunity for growth there.

Of course this will be on the regulated side. If we start looking at the unregulated side I'm going to turn back to either Tony or Jason.

As you know California has some fairly stringent requirements around their affiliate rules. And so really want to make sure that their opportunities before you jump in because you have to keep it totally separate from the utility. And we're looking at that, but as Geisha said there are opportunities within the utility to partner particularly on new technologies. The reality is, that the work we've done starting with smart meters and then moving to our automation in the grid, really gives us an opportunity to partner with a lot of these new technology providers. And we think there's opportunity both in the utility and possibly outside the utility. We're starting to look at that.

Got it. Thank you, Tony, much appreciated.

Chris Turnure, JP Morgan.

Jason, I was wondering if you could just reiterate your comments or give us a little bit more clarity on what changed for the equity issuance this quarter versus last quarter. You mentioned I think that I guess you had not been accounting for the GT&S to fire proceeds and that was a positive and some of the phase 1 items negatively offset that?

That's right. Thank you for the question. On the first quarter call I'd indicated that we were trending towards the higher end of the range particularly because of the delay in the gas transmission rate case, but what I would say is what really changed between the first quarter and the second quarter is we recognized the Butte fire insurance receivable which reduced the equity needs, but that was offset by the GT&S capital disallowance that I talked about as well as the gas distribution record keeping fine. And so what we really saw a sort of narrowing of our expected equity issuances as to about $800 million and that's why we remove the range and just reiterated the $800 million target.

Okay. And then just to kind of follow up on an earlier question regarding the $850 million of San Bruno disallowance. Am I correct in kind of thinking about this in 2015 and probably all of 2016 as well that you had spent the cash for and written off around $500 million in capital last year and then again kind of done the same thing this year for about $300 million. But you've yet to write off that O&M expense amount or spend the cash for that amount this year, so it's if things were to change with how phase 2 is being recognized, most of that would already be reflected in your numbers and your cash flow?

Yes. From a cash standpoint we've spent most of the money on the underlying work. It was about $400 million last year in the capital disallowance, the balance expected this year. And then as I mention you know we've already spent the work on the expense programs while at the disallowance the expense we are waiting until we have the actual revenues and so there will be an offset of the incremental revenues that we ultimately recognize.

Okay that's very helpful thank you. And the only other thing I wanted to ask was a little bit more strategic. Maybe Tony you could comment on your thinking behind giving us payout guidance kind of out to 2019 and a specific number there. Why did you decide to do it now? Was it the GT&S or is it us getting closer to the remedies here with some of the criminal trial elements and the fines?

Yes. I think the driving force is we were getting to the point where we had better visibility on the outcome of the various San Bruno proceedings. We also see this strong investment profile going forward to be consistent with California's clean energy objectives. And so we felt good about that.

We also believe that just giving a one-time increase without saying more was not helpful to you as investors, so we thought A, we wanted to give a range and historically have talked about what I've done in the past is have a payout range. And we wanted to give you some idea of the trajectory over the next couple of years. This wasn't a one and done. We want to have increases to get to that 60% payout ratio in 2019.

Great. Thanks.

Praful Mehta, Citigroup work

Just sticking on the theme of looking past the recent events and more and more to longer-term growth, as you look into 2018, 2019, and you've kind of gone through these different changes, how do you see any challenges or constraints on that growth going forward? As in our rates going to be going to put pressure on that growth, or is there any other challenge, or do you see enough investment opportunity without too many constraints are challenges? How do you see that in terms of long-term growth?

Well, I'd never say there are no going never going to be no challenges. I think you put your finger on one of the issues. We see plenty of investment opportunity to deal with the clean energy future here in California. We are very focused on what does it do for rates.

We're very pleased that the current GRC that we're in negotiations around even with our ask and you never get everything you ask for, we were within the target that we set for ourselves as to keep rate increases around the rate of inflation. And that's going to be our long-term goal. It's lumpy so you don't hit it exactly.

But we will be focusing on that, and one of the challenges the whole trend of the lower projections for sales, due to energy efficiency, due to rooftop solar, due to the CCAs. So we're focusing on that trying to become more efficient, but I think it's all manageable, and we can drive that growth.

Got you. Just more specifically on the Butte fire insurance proceeds, you provide the range and you're saying you can't be at the low-end of the range just wanted to understand what are the push and pulls? What drives the range in the first place and what are the scenarios under which you end up at the low end of that range.

So I'll first start with the Butte fire costs themselves, because I think that's where we sort of anchor off of. And as you will recall we took a charge for $350 million in Q1 related to property damage and that represents the low-end of the range. It really represents our estimate of the cost for the structures that were destroyed in the fire.

As I mentioned we are trying to gather more information on the higher end of that range which would include the costs for damages for things such as trees, the loss in value of the trees in a fire and we still are working through that. That is really sort of the larger sort of determination of the range for the costs. On the receivable side of things, because I mention we intend to seek the entirety of our costs related to the third-party claims for the Butte fire through insurance.

We fully expect that we will seek full recovery of the third-party claims. From a County standpoint, though, we recognize will be considered to be sort of the low-end of that range for that receivable this quarter. And so I do want to emphasize is it really is just the low-end of the range where we are starting the negotiations with insurance carriers, but we fully expect to recover third-party costs through insurance.

Got you. Thanks guys.

Michael Weinstein, Credit Suisse.

To follow-up in the $850 million San Bruno penalty. If that was allocated 100% to expense, what would be the consequences especially considering the treatment of previously accrued capital write offs?

I think really the primary difference would be about an increase in rate base of $500 million. As I mentioned in the script, there is a difference between rate base and capital expenditures rate base includes depreciation and deferred taxes so the primary difference would be about an increase about a $500 million increase in rate base.

I would say the additional earnings from that rate base would offset the lower cash receipts that we would get by applying all of the disallowance to expense, so there would probably be minimal net impact on ongoing equity needs, and so the real primary difference would be a change in rate base.

Also, just to clarify, when in 2016 do you recognize the 24 months of under collection? Is that all at once when the phase 2 final decision comes out?

That's correct. As soon as we receive a final phase 2 decision we'll recognize the full 24 months of under collected revenues.

And also another question I had was the insurance recoveries I know you said that your going to be pursuing full recovery. At what point does what's the timing of that those negotiate just like. When do you think you'll know when that receipt can be increased?

I think this is going to be a lengthy process. Because it is going to be anchored more on the cost. So we've only work through really just a handful of claims at this point. It'll probably take a couple of years to work through the remainder of those claims. As we have better certainty on the claims, we will adjust the costs associated with this. At the same point we'll be seeking insurance recoveries from our insurers, and so that -- the cash receipt from that will come periodically over the next several years.

I see the costs are also uncertain so this would not - - I mean increasing that receivable potentially later does not affect the equity issuance at all?

No. Not going forward. It would have a very small impact on equity needs.

Got you. And just one final question. Do you have any update on status of efforts to reform the commission in California, just curious?

This is Steve Malnight. I think the governor and the legislature are in active discussions. They've put out a proposal that really focuses on increasing transparency and improving some of the governance issues within the commission. We're observing that and watching that and continue to see how that evolves, but I think it is an active discussion in fact in Sacramento, and it is ongoing.

Thanks a lot.

Operator, I think we have time for one final question.

Angie Storozynski, Macquarie Group.

Thank you. I wanted to go through again the 2018 and 2019 rate base projection. I know you are mentioned it earlier in the call, but could you remind me, so which portions of the asset base actually are kept basically stable from the most recent requests especially on the electric transmission side? I'm kind of to figure out if there was an upside where would it occur?

Okay. I think it's probably easier to start first with CapEx and those changes. Because the CapEx profile is what really drives rate base, and so the high end of the range for CapEx essentially we have adjusted down slightly the high end of the range in 2016, 2017, 2018 for the gas transmission and storage rate case, the phase 1 we just received. It now reflects what that decision provides.

Offsetting that though we increased the range by the transmission our electric transmission rate case that we expect to file tomorrow. That was a small increase in 2017 that we held flat then in 2018 and 2019. The high-end or the range and really then what provides probably the greatest sort of variability to that range relates to the General Rate Case which covers the period 2017 through 2019 that we're in the process of negotiating.

Given those assumptions on CapEx I would say the only other adjustment then in related to rate base was this $700 million in disallowance of the 2011 through 2014 capital spend. We -- in the high end of the range starting in 2014, we assume that we would start earning on the remaining $400 million in 2017.

Okay. That's fine. Thank you. The other question I'm a little bit confused here. So you mentioned that the you would recognize the penalty for San Bruno the final decision is rendered, that would be excluded from earnings from ongoing operations right? That would be in items impacting comparability?

That's correct. Yes. It would not be reflective of our ongoing, so we've included an estimate for that in our items impacting comparability.

Now I don't whine you provide any audience for beyond 2016, but would be fair to assume it's basically just a financial CapEx and dividend requirement?

Yes - - so the largest drivers are equity really continue to be in our CapEx program and the unrecovered costs. The unrecovered cost really start to resolve themselves in 2017 so I would say 2018 and 2019 really are more reflective of ongoing needs to fund CapEx in our dividend plan assuming no new unrecovered costs.

All right. I'd like to thank everyone for joining us today. And we wish you a safe and happy day. Thanks.