Morning, and welcome to the PG and E Corporation Second Quarter 2016 Earnings Conference Call. All lines will be muted during the presentation portions of the call with an opportunity for questions and answers at the end. At this time, I would like to introduce your hostess, Ms. Janet Laduca. Thank you, and enjoy your conference.
You may proceed, Ms. Laduca.
Thank you, Jackie, and thanks to those of you on the phone for joining us. Before I turn it over to Tony early, I want to remind you that our discussion today will include forward looking statements about our outlook 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 2nd 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 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. So 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 areas shown on slide 3 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 2,030. 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 support increasing levels of distributed 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 and 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 20.24 for 1 unit, 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 2,031. I'm very pleased to report that the State Lands Commission recently extended the lease for Diablo Canyon 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 a 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 in 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, it 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 $850,000,000 disallowance ordered last year as part of the San Bruno penalty decision. And we hope to get a final Phase 2 decision sometime this fall. And Jason is 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-seventeen rate case.
The rates are in place subject to refund while the case is pending. And tomorrow, we'll be filing our next electric transmission rate case, TO-eighteen. We'll be requesting an additional 100,000,000 dollars in capital expenditures, which we've incorporated into our multiyear 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 is 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're now 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 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 and 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 investment. 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 Q2 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 1st 7 months of 2016. Those incremental revenues make up our under collected amounts. There are 2 important points I'd like to cover regarding incremental revenues.
1st, while the Phase 1 decision allows us to begin billing customers on August 1, we will 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. 2nd, the Phase 1 decision requires us to amortize these undercollected amounts over 36 months. Utility accounting rules allow us to recognize revenues only if they'll 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 5 months of 2016, plus the amounts we will collect over the subsequent 24 months.
This means we'll recognize the remaining 7 months of under collected amounts in the Q1 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. 1st, it permanently disallows a portion of the 2011 through 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 and 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 period and will not be recoverable in the future. As I'll discuss in a minute, we've taken a one time charge for this during the quarter for those items. And finally, the Phase 2 decision allocating the $850,000,000 San Bruno penalty creates some additional uncertainty. Several parties have suggested that all of the $850,000,000 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 $690,000,000 in capital $160,000,000 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. So with that overview, let's go through the financials. Slide 5 shows our results for the Q2. Earnings from operations came in at $0.66 GAAP earnings including the items impacting comparability are also shown here. Pipeline related expenses came in at $27,000,000 pre tax for the quarter.
Our legal and regulatory related expenses were $14,000,000 pretax. And fines and penalties were $172,000,000 pretax. The fines and penalties item reflects 2 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 $148,000,000 pretax for the quarter.
The second component is a fine of $24,000,000 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. Dubuque fire related costs also reflect 2 components. First, we booked $49,000,000 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 $260,000,000 which reflects the low end of the range for estimated insurance recoveries. The 2 components net to a positive $211,000,000 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 costs through insurance and believe that nearly all of the 3rd party claims will ultimately be recovered through insurance.
So the $260,000,000 receivable should not be interpreted as a ceiling on insurance recovery. The next line item, GT and S capital disallowance is new this quarter. We booked a charge of $190,000,000 pretax, reflecting the 2 components of disallowed capital I discussed on Slide 4, which are the $135,000,000 for work performed in 2011 through 2014, plus $55,000,000 for capital spend in 2015 through 2018 that we expect will exceed authorized cost caps. The last line relates to the impact of the timing of the gas transmission rate case decision. This is where we will reflect out of period GT and 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 4, this item will continue into 2017 when we recognize the remaining 7 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 was $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 totaled $0.08 negative for the quarter. A nuclear refueling outage during the quarter resulted in $0.06 negative. Regulatory and legal matters totaled $0.05 negative for the quarter and issuing additional shares resulted in $0.03 negative. These negative drivers were partially offset by growth in rate base 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 assumptions for that guidance, which we've updated to reflect the Phase 1 gas transmission rate case decision. Starting at the top left, we assume capital expenditures of roughly $5,600,000,000 for the year, consistent with the last quarter. The gas transmission CapEx is now 700,000,000 dollars consistent with the amounts authorized in the Phase 1 decision.
Last quarter, we showed a range of $500,000,000 to 700,000,000 We've also reduced the electric distribution CapEx by $50,000,000 to reflect our current spending projections. Moving to the top right. We've also adjusted our assumption for a weighted average authorized rate base to about $32,400,000,000 from our previous assumption of about $32,600,000,000 Consistent with the Phase 1 gas transmission rate case decision, we've adjusted the gas transmission rate base to $2,800,000,000 down from $3,000,000,000 to $3,400,000,000 range we showed last quarter. This reduction is driven primarily by removal of the roughly $700,000,000 in 20 11 through 2014 capital spend 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 500,000,000 On the bottom right, I want to reiterate that our 2016 guidance assumes that we receive 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'll 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 2 items. First, the guidance includes the $24,000,000 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 $160,000,000 to 130,000,000 dollars due to the 36 month amortization period.
The remaining $30,000,000 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 $350,000,000 to reflect our estimate of the low end of the range for property damage. This quarter we recorded an insurance receivable of $260,000,000 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 impacting comparability for the GT and 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 and S decision.
The $350,000,000 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 7 months. Moving on to Slide 10. We currently expect to issue right around $800,000,000 in equity in 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 $300,000,000 through our internal and dribble programs. Turning to Slide 11. We are updating the multiyear 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-eighteen electric transmission rate case, which we will file tomorrow. These expenditures are held flat in 2018 2019. Taken together, these changes reduced the high end of the range to $6,400,000,000 compared to $6,500,000,000 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 base 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 base to a compound annual growth rate of 5.5% to 6.5% between 2017 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.
Our first question comes from Steve Fleishman with Wolfe Research. Please proceed.
Yes. Hi. Hi, everyone. Good morning.
Good morning, Steve. Good morning.
Can you
hear me? We can. So I think I got all the moving pieces here and I appreciate you going through it. Here are 1 or 2. Just to clarify, so on the GT and S rate base that's subject to the audit, that has been excluded from the 2016 rate base, but then it comes back in, in 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 based earnings or only when it goes into rate base? Does it get like AFDC or something or some kind of treatment?
No, it's not earnings rate based in 2016.
Okay. So 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 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? That's right.
Yes.
Okay.
I think as we resolve some of these regulatory proceedings, we're getting more certainty on what that range is, and that's what this narrowing reflects.
Okay. And then just on equity, you had the same amount of shares, maybe there's just a rounding thing. You had the same amount of shares outstanding at the end of Q1, end of Q2, but you're saying you issued $300,000,000 in equity and I recall that number being lower through Q1?
I don't have the Q1 number in front of me, but we did issue through the Q2 of the year $300,000,000 in additional equity for 2016.
Okay. Okay. I think that's all I had. Thank you.
Thank you, Mr. Fleishman. Our next question comes from Anthony Craddell with Jefferies. Please proceed.
Good morning. 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 Yoon Park, our General Counsel, comment.
Yes. So I don't think that relates to the alternative fines act portion. And 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're 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 has was realized by the company?
So it's the number that appears in the indictment, which is $281,000,000 That's what the government has alleged. And under the Alternative Fines Act, if they can prove beyond the reasonable doubt that the criminal violations led to the $281,000,000 gain, then under the act you can actually double that as the maximum fine.
Great. Thank you. I'm sorry.
Yes. There'll be no discussion of that unless we get to a Phase II in the trial.
Okay, great. Thanks for taking my question.
Thank you, Mr. Craddell. Our next question comes from Julien Dumoulin Smith with UBS. Please proceed.
[SPEAKER JULIEN DUMOULIN SMITH:] Hi,
good morning.
Good morning. 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 $2,000,000,000 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 extension?
Julian, hi, this is Geisha Williams. So regarding the Diablo Canyon issue and utility ownership of replacement power, our intention is to issue a number of tranches, the first one being energy efficiency, the second one being non GHG resources. And in both cases, those will be 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 the period for which we're looking at our rate base. But I mean, obviously, if you look at the structure, the regulatory structure here in California, it's been really conducive to continue to add to modernize the infrastructure. We've had a very healthy capital program for many years and I don't see that changing. But it's 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, just 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 kind of immediately reflect it if it was to be of expense in your numbers and that would be an uplift for the back half as soon as you got that outcome?
Yes. I think this GT and 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 will only recognize about $130,000,000 of that San Bruno expense disallowance here in 2016. The remaining $30,000,000 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. But just to be clear, as soon as the when you get the decision, that's when the expense gets hits or at least the true up. And then going forward, the rate base would be adjusted correspondingly, I suppose, the next update you provide?
That's correct. As soon as we get the final decision, that's when we would take that $130,000,000 disallowance for expense. But it is the final decision that we need before we record that.
Got it. All right. Thank you.
Thank you, Mr. Smith. Our next question comes from the line of Greg Gordon with Evercore ISI. Please proceed.
Thanks. Good morning.
Good morning, Greg.
So 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 showed us on Page 12 and what we think the earnings power is of the business there net of other factors, what the other factors would be on Page 8. So I guess the big question is when we're looking at 2018 2019 earnings, how many are we going to be through this period where there these multiple bridge line items from operating basis earnings to GAAP basis earnings? I mean once we're in 2018 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 there'll be a very tight band between your operating basis earnings and your GAAP basis earnings or if not what will be continuing on?
Yes. 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 base growth starting in 2018.
Greg, this is Tony. As I look at the list, 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 companies go on for multiple years. But certainly, the gap will narrow because a lot of the other regulatory stuff should drop off.
Great. That's because investors just want to understand what the real earnings power of the company is and so that they can figure out where your dividend is 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 it's trading now. But I think we've got to get through some of these complex issues first. So thanks guys. Appreciate it.
Thank you, Mr. Gordon. Our next question comes from Jonathan Arnold with Deutsche Bank. Please proceed.
Hi, good morning.
Good morning, Jonathan.
Picking up on equity and a couple of the other themes. Does the way in which you're going to recognize the GT and S with some of it rolling over into 2017, does that have the effect of sort of having pulled forward some equity pushing you to that higher end in 'sixteen, but maybe tempering whatever you may or may not have to do in 'seventeen?
The delay in terms of getting a final decision here that allows us to recognize the strip revenues 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, any kind of how should we
be thinking
about whether or you will or won't be an issuer in 2017? How much variability is there depending on how some of these other pieces shake out?
Well, I think it's there are going to be a couple of items that from our items impacting comparability that transition into 2017. I still think the dominant item on our gas business that we're focused on is finishing our pipeline rights of way program where we're reclaiming our rights of way. As we said, that's a 5 year program not to exceed 500,000,000
dollars that will complete in 2017.
The rest of the there will be some small adjustments related to the GT and 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? And how much of 'sixteen do you consider to have been kind of outside of the normal?
We're not giving equity guidance for 2017 2018, but really the 2 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 equity issuances that are really driven largely by our CapEx program.
Great. Thank you. And just if I may on the quarter, you have this $0.08 of miscellaneous. Any insight into I mean, it's quite a big number. Any insight into if some of that's likely to continue through the rest of the year, you held your guidance, so assuming some of it is not going to happen again, but what's in behind that?
Sure, sure. As usual, what I would say is miscellaneous includes a number of small items. Some of them are timing related, some are not. But I think what's really important to emphasize though is that 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.
Thank you, Mr. Arnold. Our next question comes from Michael Lapides with Goldman Sachs. Please proceed.
Hey, guys. Jason, I want to focus a little bit on cash. You're talking about the revenue recognition for the delayed GT and NAS rate case. But can you talk about when you get the cash? I mean, you have a whole year of a revenue increase in 2015 and 7 months of that revenue increase in 2016 where not only have you not recognized it from an earnings perspective, you haven't gotten the cash.
Can you talk about when you'll get the cash for that period? Do you collect it over a 12 month, 24 month, 36 month? And can you put some numbers around that just 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 1st at that new revenue requirement. So we'll start collecting those incremental revenues here in August and it will be a 30 6 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 over this amortization period.
And how much is the fact from a cash perspective, the amount that's being amortized over 36 months?
Roughly in a Phase 1 decision, the annual revenue requirement increase was about $500,000,000 on a full year basis. So about $750,000,000 in total. I will say though 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've got $750,000,000 or roughly $250,000,000 a year coming in from the cash flow perspective, to help make up for the to help recapture some of that revenue just due to the delay in the case?
That's correct.
Yes. Okay. Then on
the core California GRC and obviously lots of dockets in California and 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 I mentioned. I'll ask Steve Malnite to comment on those.
Yes, Michael. So I think in terms of the outcome for the case, first, I say, we're like I said, like Tony mentioned, we have announced the settlement conference. We're hopeful that we can resolve that. The current schedule would call for a decision in January. As you mentioned, there has been delays in many of rate cases.
But at the same time, the commission has 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 and S case, which really was an unusual case. It was extremely complex. And I think we saw a much longer delay from the commission.
So we'll 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 I mean, the case is for revenues in 2017. So if we got a final decision in January, as soon as we get implemented in rates, it would just be a few months of delayed revenue.
Got it. Okay. Last item, just trying to think and this is obviously maybe a little more for Tony. How are you thinking about potential investment opportunities outside of the core Pacific Gas and 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 normal at PG and E, how you think about what the investment opportunity is for the broader corporation?
Well, Michael, you're exactly right. This is the time really to start to think about this 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 what we're doing in transmission electric transmission, and then I'll come back and just comment a little further.
Hi, Michael. This is Geisha. So on the electric transmission side, I think last quarter we announced an alliance with Trans Canyon, 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. And we think that 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 2,030. So we see a lot of opportunity both within our service area and now that we've got such a strong partnership with Trans Canyon, actually an alliance with Trans Canyon, we see some opportunity for growth there.
Of course, this would be on the regulated side. If we start looking at the unregulated side, I'm going to turn it back to either Tony or Jason.
Yes. As you know, California has some fairly stringent requirements around their affiliate rules. And so you really want to make sure that there are opportunities before you jump in because you have to keep it totally separate from the utility. And we're looking at that, but as Geshu 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 opportunities both in the utility and possibly outside the utility. We're starting to look at that.
Got it. Thank you, Tony. Much appreciated.
Thank you, Mr. Lapides. Our next question comes from the line of Chris Turner with JPMorgan. Please proceed.
Good morning. 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 Butte Fire insurance proceeds in that, so that was a positive and then some of the Phase 1 items negatively offset that?
That's right. Yes. Good morning, Chris. Yes, thank you for the question. On the Q1 call, I had 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 Q1 and the Q2 is we recognized the Butte Fire Insurance Receivable, which reduced the equity needs. But that was offset by the GT and S capital disallowance that I talked about as well as the gas distribution record keeping fine. And so what we really saw was sort of narrowing of our expected equity issuances to right about $800,000,000 and that's why we removed the range and just reiterated the $800,000,000 target.
Okay. And then just to kind of follow-up on an earlier probably all of 2016 as well that you had spent the cash for and written off around $500,000,000 in capital last year And then again, kind of done the same thing this year for about $300,000,000 but you've yet to write off that O and M expense amount or spend the cash for that amount this year. So 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 $400,000,000 last year and the capital disallowance, the balance expected this year. And then as I mentioned, we've already spent the work on the expense programs. While it's a disallowance expense, we are waiting until we have the actual revenues until it 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 and S or is it us getting closer to the remedies here with some of the criminal trial elements and the fines?
Yes. I mean, 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 getting 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 I've 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.
Thank you, Mr. Turner. Our next question comes from the line of Raefal Mehta with Citigroup. Please proceed.
Thank you. Hey, guys.
Good morning.
Good morning. Good morning. Just sticking on the theme of looking past the recent events and moving more to longer term growth. As you look into 2018, 2019 and you've kind of gone through all these different changes, how do you see any challenges or constraints on that growth going forward? As in, are rates going to be are going to put pressure on that growth?
Or is there any other challenge? Or do you see enough investment opportunity without too many constraints or challenges? How do you see that in terms of long term growth?
I never say there are going to be no challenges. No, 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're 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 is 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 is that the whole trend of the lower projections for sales due to energy efficiency, due to rooftop solar, due to the CCAs. So I mean, 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. And just more specifically on the Boot Fire insurance proceeds, you provide a range and you're saying you're currently at the low end of the range. Just wanted to understand what are the push and pulls as in what drives the range in the 1st place? And are there 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 cost themselves because I think that's what we sort of anchor off of. And as you'll recall, we took a charge for $350,000,000 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, there is we are trying to gather more information on the higher end of that range, which would include the cost for damages for things such as trees, the loss in value of the trees in the fire, and we still are working through that. That is really sort of the largest sort of determination of the range for the costs.
On the receivable side of things, as I mentioned, we intend to seek the entirety of our costs related to the 3rd party claims for the Butte fire through insurance. And so we fully expect that we will seek full recovery of the 3rd party claims. From an accounting standpoint though, we recognize what we consider to be sort of the low end of that range for that receivable this quarter. And so what I 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.
Our next question comes from the line of Michael Weinstein with Credit Suisse. Please proceed.
Hi there. Good
morning. To follow-up on the $850,000,000 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 $500,000,000 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 $500,000,000 increase in rate base. I would say the those additional earnings from those 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're you've said that you're going to be pursuing full recovery. At what point what's the timing of that those negotiations? Like when do you think you'll know whether that receivable 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 worked through, really just a handful of claims at this point. It will 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 cost associated with this. At the same point, we'll be seeking insurance recoveries from our insurers.
And so that the cash received from that will come periodically over the next several years.
I see. The costs are also uncertain. So this, Doug, 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.
Yes. This is Steve Mennonite. 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 Sacramento, and it's ongoing.
All right. Thanks a lot.
All right. Operator, I think I have time for one final question.
Yes, ma'am. Thank you, Mr. Weinstein. Our next question comes from Andy Storlinski with Macquarie Group. Please proceed.
Thank you. So I wanted to go through again the 2018 2019 rate base projections. I know you 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, etcetera. I'm trying to basically figure out if there were to be 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 decision we just received. It now reflects what that decision provides. Offsetting that though, we increased the range by the transmission or electric transmission rate case that we expect to file tomorrow.
That was a small increase in 2017 that we held flat then in 2018 2019. The high end of the range and really then what provides probably the greatest sort of variability in that range relates to the general rate case, which covers the period 2017 through 2019 that we're in the process of negotiating. Kind of given those assumptions on CapEx, I would say the only other adjustment then in related to rate base was this $700,000,000 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 400,000,000 dollars in 2017.
Okay, that's fine. Thank you. The other question, I'm a little bit confused here. So you mentioned that you would recognize the penalty for San Bruno the moment the final decision is rendered, that would be excluded from earnings from ongoing operations, right? That would be in the items impacting comparability?
That's correct. Yes. It would not be reflective of our ongoing earnings. And so we've included an estimate for that in our items impacting comparability.
Now I know you don't want to provide any equity guidance for beyond 16, but would it be fair to assume that it's basically just to finance your CapEx and the dividend requirements?
Yes. So the largest drivers of our equity really continue to be our CapEx program and an unrecovered cost. Cost really start to resolve themselves in 2017. So I would say 2018 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.