PG&E Corporation (PCG) Q2 2014 Earnings Report, Transcript and Summary

Sara A. Cherry - Vice President of Investor Relations Anthony F. Earley - Chairman, Chief Executive Officer, President and Chairman of Executive Committee Christopher P. Johns - Former President and Director Kent M. Harvey - Chief Financial Officer and Senior Vice President Thomas E. Bottorff - Senior Vice President of Regulatory Affairs Hyun Park - Senior Vice President and General Counsel Dinyar B. Mistry - Vice President and Controller

Greg Gordon - ISI Group Inc., Research Division Julien Dumoulin-Smith - UBS Investment Bank, Research Division Steven I. Fleishman - Wolfe Research, LLC Jonathan P. Arnold - Deutsche Bank AG, Research Division Travis Miller - Morningstar Inc., Research Division Michael J. Lapides - Goldman Sachs Group Inc., Research Division Daniel L. Eggers - Crédit Suisse AG, Research Division Kit Konolige - BGC Partners, Inc., Research Division Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division James D. von Riesemann - CRT Capital Group LLC, Research Division Anthony C. Crowdell - Jefferies LLC, Research Division Shahriar Pourreza - Citigroup Inc, Research Division Rajeev Lalwani - Morgan Stanley, Research Division Ashar Khan

Good morning, and welcome to the PG&E Corporation Second Quarter Earnings Conference Call. [Operator Instructions] At this time, I would like to introduce your hostess, Ms. Sara Cherry. Thank you, and have a good conference, You may proceed, Ms. Cherry

Thank you, Josh. Good morning, everyone, and thanks for joining us. Before you hear from Tony Earley, Chris Johns and Kent Harvey, I'll remind you that our discussion will include forward-looking statements about our outlook for future financial results 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 the Form 10-Q that will be filed with the SEC later today and the discussion of risk factors that appears there and in the 2013 Annual Report. And with that, I'll hand it over to Tony.

Well, thanks, Sara; and good morning, everyone. I'll start off my remarks today by touching on a few items of importance, and then Chris is going to cover the status of our operations and regulatory matters and Kent will conclude with the financials. So I'll start with Slide 3. We remain focused on our mission of operating a safe, reliable and affordable utility for our customers. Our objectives are to resolve the gas issues, position the company for long-term success and partner effectively with others to shape policy and create value for our customers. Let me start with the gas issues. Unfortunately, we still haven't received the presiding officer's decision in the pending gas investigations. Although the record was complete last October, the proceeding continues to take a long time to be resolved. In fact just this week you probably saw that the city of San Bruno filed some motions raising questions about the propriety of communications between PG&E and the CPUC. I want to be clear that we are absolutely committed to conduct ourselves in an ethical manner and in compliance with CPUC rules at all times, and we take seriously any questions about the conduct of PG&E employees. As any regulated utility does, we communicate with the CPUC almost constantly on a wide range of issues. To ascertain whether our communications were appropriate, we will carefully review the documents in question and will take appropriate actions. Looking at the big picture as we approach the fourth anniversary of the San Bruno accident, we look to the commission to bring these proceedings to a close and to do so in a way that acknowledges PG&E's unprecedented response since the accident. Moving on to the federal arena. As you know, we expected the U.S. Attorney to file additional charges against the company. And on Wednesday, they issued a superseding indictment. Essentially, there are 3 primary changes in the indictment. It added 15 additional charges under the Pipeline Safety Act and referenced an additional code section. They have also alleged that the utility obstructed the NTSB's investigation of the accident based on a letter we submitted to the NTSB, which is on the NTSB's website and which we still stand by. And finally, for purposes of determining the maximum fine, they have alleged, with no details, that the utility derived $281 million in gains and that there were $565 million in losses. Let me just state that based on all the evidence that we have seen we still do not believe any of these criminal charges or fines are warranted. Moving on from the gas issues. In a key step forward for the company, we did receive the proposed decision on our 2014 General Rate Case. You'll recall that the GRC sets base revenues through 2016 for 3 key parts of our company: electric distribution, gas distribution and electric generation. The proposed decision would provide revenue requirement increases well below those we requested to fund important progress in safety and reliability and, obviously, we like to see some improvement in. For instance, the proposed decision would deny funding to accelerate our gas distribution leak survey cycle to every 3 years compared with the current 5-year cycle. It would also deny our request to treat every gas odor call as requiring immediate response instead of screening some out for later action. We also believe that we should have received a larger increase in depreciation rates. We've raised these and other concerns in the comments that we filed with the commission. Having said that, as a percentage of the request, the proposed decision is within the range of other recent GRC decisions made by the commission. And the proposed attrition adjustments for 2015 and 2016 do reflect the magnitude of our capital program, which is critical to us. As I've explained in the past, we spent the last few years improving our company-wide planning process and developing our continuous improvement skills. Thus, although it will be challenging, we intend to manage our costs consistent with the final authorized revenue requirement in order to earn our authorized return this year, except for the gas transmission business. The commission should be able to vote on the proposed decision as soon as August, and we look forward to their reaching a reasonable and timely final decision in this important case. So now I'll turn it over to Chris to talk about the progress we're making in our operations. Chris?

Thanks, Tony; and good morning, everyone. I'll begin my remarks with an update on our operations and then touch on some additional regulatory developments from the quarter. Starting with gas operations. On Slide 4, you can see that we continued to execute unparalleled levels of work on our gas pipelines as we enhance the safety and integrity of our system. In May, our gas business received 2 international certifications: Publicly Available Specification or PAS-55 and International Organization for Standardization ISO-55001 for best-in-class operations standards. We're the only gas company in the United States and 1 of a very few worldwide to hold both of these prestigious certifications from Lloyd's Register, who is an independent auditor. These certifications provide important external validation of the safety culture and the asset management strategy and standards that our gas team has been working so hard to implement. Now this doesn't mean that we do everything perfectly, but it shows we've made tremendous strides and are focused on the right work. Another item I want to mention is our program to remediate encroachments in our gas pipeline rights-of-way. We had previously intended to provide an updated cost estimate for the program around midyear. However, earlier this year, we encountered concerns in some of the Bay Area communities about our planned vegetation management remediation activities. We've taken some extra time to work through these issues, and we have reached several agreements with the affected communities that will allow us to resume our work in ways that address community concerns and enable us to ensure the safety of our pipelines. As a result of this effort, we've remediated fewer encroachments than we had planned at this point in the year and are not yet in a position to refine our overall cost estimate. However, we continue to believe that we will not exceed our original $500 million estimate and that we'll still complete this program by the end of 2017. One more operational item worthy of note. Our Energy Supply Team recently received external validation of the work they've been doing to keep our nuclear plant operating safely. Last year, inspectors from the Nuclear Regulatory Commission spent more than 7,500 hours conducting detailed inspections on our Diablo Canyon nuclear power plant. And at a meeting in May, the NRC announced the results of its assessment, which found Diablo Canyon to be among the highest performing plants in the nation in 2013. We're obviously proud of this result. It's a great achievement. Shifting to regulatory matters. During the quarter, we received approval that the revenue requirement in our Gas Transmission & Storage Rate Case will be retroactive to January 1, 2015, even though the final decision will come later, and it's currently scheduled for March. Given the significance of this case, retroactive treatment was a very important issue in the proceeding. Next. Just this month, we announced that we reached a settlement on our Pipeline Safety Enhancement Plan update filing. You'll recall that we filed the PSEP update application in the fall of 2013 after we finished validating the maximum allowable operating pressure of all 6,700 miles of our gas transmission pipelines. Other parties to the proceeding proposed significant disallowances to that update. The PSEP update settlement resulted in a $23 million reduction in the amounts we may recover from our customers. Although this represents an increase in the shareholder funding to complete the PSEP work, we still expect the item impacting comparability for natural gas matters to fall within the range of $250 million to $450 million that we provided for this year. And by settling the case, we eliminate the uncertainty and can focus our full efforts on the gas transmission and storage rate case. Finally, in electric transmission, on July 15, we filed a settlement with FERC for our Transmission Owner 15 Rate Case. This is a black-box settlement without a specific finding regarding authorized ROE. The settlement resulted in an increase in the revenue requirement of about $22 million above the previous rates. And we continue to target earning a return on our electric transmission business that's comparable to the amounts authorized by the CPUC for other parts of our business. And yesterday, we filed our next electric transmission rate case, TO16, with FERC. We're requesting an ROE of 11.26%, along with an increased revenue requirement in that case. And with that, I'll turn it over to Kent.

Thanks, Chris, and good morning. Q2 was a pretty straightforward quarter in terms of our financials. So I'll briefly walk you through that and then cover some implications of the proposed decision in our general rate case. Slide 5 summarizes the results for the second quarter. Earnings from operations were $0.69, and GAAP results were $0.57. The item impacting comparability for natural gas matters totaled $0.12 negative, and you can see our Q2 pipeline-related expenses of $97 million pretax in the table at the bottom. We expect higher pipeline-related expenses in the second half of the year when the majority of the work is planned. You can also see that we didn't report any insurance recoveries in Q2. However, we have been in discussions with insurers about recovery of our remaining claims. Slide 6 shows the quarter-over-quarter comparison for earnings from operations and the key differences from Q2 results last year. About $0.04 negative is due to the fact that without a final decision in our pending general rate case, we're not booking sufficient revenues to cover our capital-related expenses for much of the business. You'll remember we had a similar impact in Q1. After the commission issues a final decision in the general rate case, which will be retroactive to January 1, we'd expect to recover the revenues associated with these costs, plus earn a return on a larger authorized rate base in 2014. Another $0.04 negative is due to the increase in shares outstanding. And $0.03 is due to miscellaneous items, including the absence of some regulatory pickups we had in Q2 last year. We've actually included within the miscellaneous total a gain from the disposition of some shares in SolarCity, which we obtained in connection with tax equity investments we made at the corporation a few years back. So that's the summary of quarterly results. As you know, pending resolution of the general rate case and the gas investigations of the PUC, we've not provided guidance for earnings from operations; but we have given you some key inputs, such as ranges for CapEx and rate base. I want to spend a few minutes talking about what the implications for those ranges would be if the proposed decision in the general rate case were approved as is. If you turn to Slide 7, I'll start with CapEx. Our guidance range for our 2014 CapEx has been $5 billion to $6 billion. The upper end of that range reflects the CapEx level requested in our various regulatory filings, and the lower end of the range reflects our 2013 spend with a few adjustments for things like the conclusion of our Cornerstone Program and our utility-owned photovoltaic program. Compared to that range, the General Rate Case proposed decision would imply total CapEx of about $5.3 billion for this year. To the right, you see the same information for authorized rate base. Compared to an original range of $28 billion to $28.5 billion, the proposed decision would imply a 2014 rate base at the lower end of that range, right about $28 billion. The main reason for this is that the proposed decision assumes a lower level of 2013 CapEx than we forecasted, resulting in a lower starting point for rate base in 2014. If the proposed decision is approved as is, we wouldn't expect to true-up this difference until our next General Rate Case. A heads-up because it's confused some people. If you actually look at the proposed decision, the rate base numbers for electric distribution and electric generation will not match this table here since we've included some items that are not -- that are recovered outside of the General Rate Case, such as the remaining rate base on the conventional meters that we have replaced with SmartMeters and our utility-owned photovoltaic installation. Finally, at the bottom right, we've previously highlighted the underearning on our gas transmission business, which when netted against other factors, such as incentive revenues for energy efficiency programs, was expected to negatively affect 2014 operating earnings by roughly $0.10. We now hope to fully offset this impact in 2014 and eliminate this negative $0.10. The drivers for this change include higher gas transmission revenues resulting from increased gas-fired generation given our dry hydro conditions in the state and the disposition of SolarCity shares I mentioned before. Turning to Slide 8. You'll see the estimated range for our item impacting comparability for natural gas matters in 2014, which we're maintaining at $350 million to $450 million pretax. The settlement we reached in connection with the Pipeline Safety Enhancement Plan update filing, which Chris mentioned, by itself would increase our unrecovered expenses by about $23 million this year. However, we continue to believe that total unrecovered expenses, including the PSEP settlement, will fall within our guidance range of $350 million to $450 million. At the bottom of the slide is a reminder that these figures exclude future insurance recoveries, which, of course, we would net against these costs, and any additional fines or penalties resulting from the gas investigations that we've not yet accrued. Moving on to Slide 9. We continue to target between $800 million and $1 billion of equity issuance this year. This range excludes any additional fines or penalties resulting from the gas investigations which would be incremental to the range. During Q2, we issued just under $300 million of common stock. That brings to about $600 million through the first half of the year, so we're well along on our financing plan for the year. Finally, on Slides 10 and 11, we've shown our guidance ranges for CapEx and rate base through 2016 and what the implications for those ranges would be if the proposed decision in the General Rate Case were approved as is. In all cases, the ranges implied by the proposed decision would fall within the ranges we've previously provided. For example, on Slide 11, the proposed decision would result in a range for 2016 authorized rate base of $34 billion -- $33 billion to $34 billion, which compares to our existing range of $32 billion to $35 billion. We would very much like to receive a final decision in the General Rate Case next month. In the meantime, we hope that this information is helpful to you in understanding the potential impact of the proposed decision. I'm going to stop there, and we can now open it up for your questions.

[Operator Instructions] The first question comes from the line of Greg Gordon with ISI Group.

How many shares of SolarCity do you own and at what price?

Greg, this is Kent. I'm going to answer that question as follows. The disposition that we did in this past quarter represents roughly 1/3 of our total holdings, so we will have additional dispositions in future periods.

Okay. So you're not at liberty to disclose your holdings or the value?

We've chosen not to do so.

Okay, fair enough. Can you restate -- I was distracted a little bit, 7 companies reporting today -- what you said about there's a $0.10 expense this year that you're -- be able to offset? Can you restate that, please?

Yes, Greg, if you go back to Slide 7, this is really where I talked about this, and it's the lower right-hand part of this slide, and it was these other factors that affect our earnings from operations. And previously we had provided the indication that when you look at all these other factors, the underearning in our gas transmission and storage business but also other factors like energy efficiency revenues that we expect to receive, when you look at all of that, we've said it -- we expected it for this year to have roughly a negative $0.10 impact on earnings from operations in 2014. And what I said earlier today is that in light of the fact that we are experiencing higher gas transmission revenues just given the really dry hydro conditions in the state and the fact that a lot of the gas-fired generators are being -- are experiencing higher demand than was previously expected and the fact that we're monetizing some shares in SolarCity, those are a few of the factors that we hope will allow us to offset that negative $0.10 for 2014.

Okay. But should -- and I know you haven't given guidance for this year or for future years, but should we assume in a base case that you're unable to offset that negative $0.10 in future years and that this is sort of an anomaly?

Well, Greg, our objective next year is when we hope to resolve the Gas Transmission & Storage Rate Case and -- therefore, our objective is to earn our authorized return next year at the gas transmission business going forward on an operating basis. So that's what we expect will be different in future periods.

Okay. So that could mitigate or eliminate the drag?

That's correct.

Okay, great. Can you comment on what the legal path is for resolving the accusations made by the City of San Bruno with regard to the emails, whether that has to go through the ALJs writing the PODs or some other venue and what impact it might have on the timing of a final decision?

Greg, this is Chris. Right now, what the next steps in the timeline are is that barring any kind of ruling otherwise from the ALJs the parties will all file responses within about 15 days or by August 12. And then following that, it's really up to the ALJs or the commission, and they could rule or issue a schedule for briefings and hearings if necessary. So there's not a firm schedule until they decide what that would look like. Right now, nobody's asked for -- obviously a delay in the PODs, and so it's hard to speculate as to what impact it might or might not have. But we still believe that the commission will move forward with the proposed decisions as quickly as possible.

So the issuance of the proposed decisions is independent from what's going on with this issue? Or are they linked? I'm a little confused.

Well, there's not necessarily an absolute link other than they are part -- they were filed as part of this process, and the ALJs and the Commission have some discretion as to they could rule on this before they do the proposed decisions; they could include them in the proposed decisions, and they potentially could keep them separate.

Okay. So the next step is within the next 15 days, people will file a response?

Yes, that's the only thing that we know for sure.

The next question comes from the line of Julien Dumoulin-Smith with UBS.

I want to first just get a little clarity here. So you have range of equity, and in light of the PD, how are you thinking about that? Just if you could comment specifically with regards to depreciation and accelerated depreciation. Is there any kind of thinking within that range you could provide perhaps? I'll leave it broad.

Julien, this is Kent. A couple of hundred million dollars range for our equity needs we think is kind of a reasonable range to have even halfway through the year. So the fact that we got the proposed decision in the General Rate Case, it provided some additional improvement in depreciation rate but certainly not our full request, and our original range assumed no increase in the depreciation rate. So there's a slight positive from that. But another underlying assumption behind our original range of $800 million to $1 billion for equity needs was also that we get a timely resolution of the General Rate Case, and, obviously, it's dragged on longer than we had anticipated. And so it actually has not been reflected in our rates yet. So as a result, from a cash flow perspective, that's been a slight negative. And so those, I would say, are somewhat offsetting, and that's one of the reasons why we're very comfortable still with our $800 million to $1 billion range.

Excellent. And then if you could elaborate for a second. On transmission, obviously, you have TO15 in the bag. You're looking at the TO16. If you could -- as you're thinking about the resolution of that case and looking forward in the context of the latest decision in New England, has that changed your thinking at all? And how do you think about the median versus midpoint methodology that I suppose nominally is still out there?

Well, we do believe that the policy at the FERC is in transition. And I think in the New England case, the decision indicates that mechanically applying the DCF model has some shortcomings and that you do need to consider, for example, anomalies in the market and that the ultimate result should be reasonable. So based on that, we're hopeful that we can expect a little bit more flexibility than we've seen in the past. But it's still early on.

Excellent. And then lastly, in your comments, you've mentioned a couple times the impact of hydro. Are you seeing much in terms of your own portfolio? And then specifically, as you think about customer inflation, et cetera, I mean, how much of an impact could -- does this have this year and, more importantly, could this have in subsequent years as you're seeing it?

Yes, Julien, this is Chris. In the last -- this last year has been third driest hydro season in the last 119 years. And so what we've seen is an increase in the need to use the marketplace to obtain power for our customers during parts of the season. We still have enough hydro to really hit at the extreme parts and use that to offset costs. But what that has resulted in, in conjunction also with some of the rising gas prices is, is that we're seeing higher costs for electricity here. And so, obviously, that will have an upward pressure on our rates with our customers either later this year or into next year. Depending on timing, we may just put it in as part of our next year annual true-up if it doesn't get too high.

Got you. But I don't sense any over-worry about what that might do to end user rates. It's probably...

We're, obviously, always concerned about our customers' rates and any impact on it, but we have this in the General Rate Case. And all of that we're trying to consider together, what that looks like to our customers.

The next question comes from the line of Steven Fleishman with Wolfe Research.

On the $0.10 that you have now offset with the transmission revenues and the SolarCity monetization, can you split that out between the 2?

I'd just say in terms of the SolarCity monetization it was worth a few cents during the quarter, and I think -- the gas transmission revenue is more of a gradual thing during the year.

Okay. And I guess on the SolarCity thing, it -- that's -- whatever your stake is, it's not enough to meaningfully kind of impact on the cash side your financing needs?

No, it's not a huge driver from a cash perspective.

Okay. And then maybe just on the San Bruno proposed decision, I assume you've gotten no indication of when the ALJs may issue a proposed decision?

Yes, that's correct, Steve. Anything we'd say will be speculation. But as I said, the record has been closed now for 10 months, and we certainly are hoping to get a decision sometime in the near future.

Okay. And just -- could you maybe just talk a bit little more operationally how you're doing on your kind of overall electric gas reliability this year, also on your pressure testing and all your other work?

Yes, this is Chris. On the electric side, we are in the midst of a sixth straight year of record-setting reliability for PG&E. We continue to make the appropriate investments, and we're seeing great results in terms of reducing the number of outages and then the duration of those outages. And then on the gas side, we continue to do unparalleled work. We're testing more pipes, replacing more pipe, putting in more valves, validating the maximum allowable operating procedure than anybody in the country right now, and that continues to move along very well. We do our periodic updates of our PSEP program, and we're on schedule. There's a couple of projects, smaller ones, that may still slip into 2015. But otherwise, we're comfortable that we're on track.

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

Curious. So the SolarCity shares, you said you acquired through a tax equity structure. Do you have any other similar investments that have -- maybe might be comparable that you could also monetize?

Jonathan, this is Kent. I mentioned that the disposition we did in this past quarter was roughly about 1/3 of our overall holdings. And so in terms of -- there are additional shares SolarCity stock. But other than that, no, I don't see anything comparable in terms of our holdings at the corporation.

Okay, so it's a non -- SolarCity is a sort of a one-off thing actually?

That's correct.

The next question comes from the line of Travis Miller with Morningstar.

If we look out kind of 3 to 5 years, I wonder if you can give us the landscape for renewable energy development right now on the electric side, in your service territory. And then second to that, with the other opportunities, whether it's transmission, distribution, even owning some renewable generation, what that outlook looks like and growth opportunities there.

Well, I'll start off and then maybe Chris can follow up on some of the details. But we are very optimistic and have said repeatedly we will hit the State goal of 33% renewables by 2020. We're in the high 20% range now, and we've done a lot of hard work to figure out how to integrate those renewables into the system. Many of you have seen the famous or infamous duck curve that's out there, and our folks have done a lot of work on figuring how to manage the system where we have renewables coming in that we don't control that depend upon whether the wind is blowing or the sun is out. And I'm really pleased with operationally how we are managing this, and I see the ability to get to that 33% number. Chris, you want to comment on opportunities we see in transmission and other things?

Yes, as we move forward, we don't see ourselves investing in any renewables in any time in the future. But they will still come online, and we'll do most of that through contracting. I think as you look down the road and you look where the industry is headed, obviously, we need to continue to modernize our infrastructure both on the transmission side and on the distributor side for electric and making sure that we're able to accommodate all the new rooftop solar panels, the storage that's going to come online at some point, electric vehicles. And all of those things continue to provide us with opportunities to upgrade and modernize the system. And so although we have not given any guidance as to what our CapEx looks like beyond this year and what you've seen in the proposals for our GT&S case and our GRC, we know that we're got an older infrastructure and it needs upgraded, and we'll continue to do that so that we can make sure our customers can handle their energy needs in the way they'd like.

Okay, great. And you piqued my interest. What are some of the ways that you guys are managing that duck curve?

Well, it's a whole range of strategies. One is more accurate forecasting. So we've been developing models that give us a better idea of what to expect day-to-day. We're also working with a number of the suppliers. We conduct a periodic bidding process to get new renewables as we gradually work our way up to 33%. And more and more, we are trying to incorporate in those contracts the ability to curtail production when we don't need it so we can manage the matching of the demand with the available electricity.

The next question comes from the line of Michael Lapides with Goldman Sachs.

Just I want to touch base on things that when we get past this General Rate Case and past the GT&S case won't necessarily be recovered in the rate structure until kind of the next round of either GRC or GT&S rate cases. Can you just kind of refresh us on what those items are expected to be?

Michael, this is Kent. In terms of the General Rate Case, Tony indicated based on the proposed decision we are -- assuming it is approved in the final form, we do intend to earn our authorized return overall for those lines of business. So I don't think there's anything significant in the General Rate Case portion of our business where there's any significant unrecovery. I mentioned there's a small piece of our capital true-up for 2013. It's probably a couple of hundred million dollars that isn't reflected in the proposed decision rate base for 2014, so that's capital from before this year. But we did have a significant true-up request in that case, and the large majority of it is reflected in the proposed decision. In terms of the Gas Transmission & Storage Case, there's really just a few items that going in we did not seek recovery. Of course, the most significant one is our rights-of-way program that Chris talked about earlier on the call, and we expect that to continue through 2017, so we have a few more years of that. There's only 2 other smaller items that we didn't seek recovery of, much smaller in scale. And we said together, they're roughly $50 million a year for the 3-year GT&S rate case period. One has to do with pressure testing on newer pipe, and the other one has to do with a portion of our corrosion work, which we believe was more remedial in nature. So those are really the items I think that address your question.

And the pressure -- is it the combination of the rights-of-way and the pressure testing and corrosion? Is all of that $50 million or just the pressure testing and the corrosion? And then, therefore, how much is the rights-of-way on top of that?

It's the latter. In other words, roughly $50 million a year on average during the 3-year period is the pressure testing and the corrosion work. The rights-of-way work, as you know, is a 5-year program, and we believe that it will come in at or less than $500 million. So I would say really simplistically you could assume on average roughly $100 million a year.

And all of that is pretax?

That's correct.

Got it. Last question. Can you talk a little bit about what you're seeing in overall demand trends in Northern California relative to what your expectations for weather-normalized demand trends? What's differing? How -- and what are your kind of views on what happens to electricity demand going forward over the next couple of years, like what you think the new normal for weather-normal demand is in Northern California?

This is Tom Bottorff. The forecasts that we filed recently in regulatory proceedings suggest an increase of about 0.3% per year going forward for several years. That could, obviously, change in future years as we learn more about the deployment of DICHI [ph] and other technologies, but that's the weather-normalized forecast for foreseeable future.

The next question comes from the line of Dan Eggers with Crédit Suisse. Daniel L. Eggers - Crédit Suisse AG, Research Division: Kent, when it relates to the pipeline-related expenses, how much insurance claim do you guys have in backlog that is prospectively available for recovery still?

Well, I'll give you a kind of all the kind of insurance numbers across the board so you can kind of understand it. In terms of our accrual, we've accrued $565 million. In terms of the actual cash outlay we've made, it's a little over $530 million, so the vast majority has actually been paid out in cash. We have incurred legal expenses related to third-party claims, which is also recoverable from insurance, which totals $88 million. And our recoveries to date on insurance are $354 million, I think, is the number. So there's still a couple hundred million dollars just in terms of getting up to our accrual, and then there's also $88 million in legal expenses incurred to date. Daniel L. Eggers - Crédit Suisse AG, Research Division: And from an effective perspective, you guys have been funding that shortfall with equity just to keep your capital structure balanced, correct?

That's correct. The after tax amount with equity, yes. Daniel L. Eggers - Crédit Suisse AG, Research Division: Okay. And then, can you guys just maybe give a couple of thoughts -- I know it's early -- but on 111 (d) and how that could, a, integrate with AB 32; and then, b, assuming there's a bit of a penalty for people who've done a lot of work in advance, which you guys have, how does that affect maybe how you guys comment or make future planning decisions?

Yes, let me start. I think we are in good shape under 111(d). We are still though trying to sort out how it will impact the California Cap and Trade regime. It's been working successfully. And that's an issue we've been talking to the California Air Resources Board, working with EPA. But by and large, our take on that is that PG&E is in very good shape given our current mix of generation. Not only do we have over half of our generation now is -- on nonemitting sources, when you include Diablo Canyon and our large hydro plants plus the renewables that qualify under the California program, that's going to go to 65% by 2020. And our own utility-owned generation are almost brand-new combined-cycle plants that have been built in the last 4 or 5 years, so they're pretty much state-of-the-art, so we feel like we're in good shape. But, obviously, we've got to get understandings of how all these things are going to integrate, and it's really too early to tell. Daniel L. Eggers - Crédit Suisse AG, Research Division: Okay. And is there anything update-wise on kind of the process for looking at some of these net metering changes and how you guys are coming along with recalibrating rate structures and demand charges?

Yes, this is Tom Bottorff. The commission did issue a proceeding this month that would launch a new rule-making to look at how the net metering tier should be revised, and they have a timeline for resolving that by the end of 2015, so -- and it would become effective in the middle of 2017. So that proceeding has been launched. They have opportunities to comment that are due in the middle of August, but there really isn't a decision anticipated until probably the latter part of 2015.

The next question comes of the line of Kit Konolige with BGC.

Just -- most of my questions have been asked and answered. Just on the superseding indictment. Do you have any sense of how long that process is going to take to play out? And is there any possibility of a settlement? I guess I'm starting from the assumption that if you didn't settle before the indictment that settling after the indictment may not be in the cards. But I'd like any sense you can give us of where we stand, how long it'll take and what ultimately might occur.

So this is Hyun Park, General Counsel. The timeframe, I think, is it could take 1 or 2 or more years, but the schedule just has not been set yet. And in terms of settlement possibilities, I would say at this point there have been no settlement discussions. But, obviously, as Chris mentioned earlier, we're always open to receive [ph] offers.

Right. And just -- not that it probably matters a whole lot at this point, but why does the U.S. Attorney issue a superseding indictment like that? I mean, what -- was there something that came out in -- during year 4 that had an impact on what the indictments look like? What -- did they know anything later that they didn't know before? Or was it just a matter of they discovered some new law books? Or how does that work?

Yes, so I don't think it's completely uncommon for prosecutors to commend and occasionally file a superseding indictment. But as we see the superseding indictment, we don't think that any new facts have emerged. I mean it looks like it's more or less pretty much the same types of issues. There are 28 counts that are now in the indictment, and one relates to the obstruction charge that Tony described earlier. And there are 27 other counts, and they all relate to the same type of issues that were in the original indictment. There's a new code section that's referenced that relates to pressure testing records, but it looks like it's more of the same type of issues.

Okay, fine. I have one last unrelated question. And that is with the -- on the gas transmission retroactive decision by the commission is -- how much of a change -- is that a change in policy? Or was that something you expected? Does that apply to future filings in gas transmission or other areas?

Yes, this is Tom Bottorff. This practice is generally fairly common in these kinds of proceedings, but you do have to initiate a request with each proceeding, so it's not automatic, but we've gotten similar treatment in our General Rate Cases. We requested it in this TTF [ph] case and received it. So my expectation -- should it be our expectation that decisions will be delayed in the future, we will make a request to continue to ensure that they're retroactive to the date that we requested.

And would you take this as an indication that the commission would be of a mind to go along with your request to -- for retroactive treatment?

Yes.

The next question comes from the line of Hugh Wynne with Sanford Bernstein. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: I just wanted to follow up on some of the questions regarding the superseding indictment. You mentioned that there had been no effort to enter into settlement discussions. I would like to know what are the consequences of a conviction? Are there consequences for your ability to recover under your insurance policies? Are there consequences for your ability to continue to provide services under some of your franchise agreements? Can you explore the possible negative consequences of a conviction?

Sure. So I think with respect to the 2 specific questions that you mentioned with respect to insurance, our ability to serve our customers, I think the answer is we don't think a negative consequence in the criminal indictment will have a negative impact on those 2 issues. And I can't remember, what was the third question that you asked? Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: Well, if there are no serious commercial implications of a conviction, what was the thinking that got you to engage in settlement discussions? It seems to me that this is a potentially very large penalty, which will create uncertainty for a period of years. It almost replicates the environment that we've been in for the last 2 years on the San Bruno CPUC penalty. Would there not be a strong incentive to try to put this behind you as well earlier rather than later?

Yes, let me comment on it. This is Tony. Of course, we've only seen the superseding indictment here a day or so. If you'll recall the original indictment, the 12 counts amounted to $6 million, so we've just got this larger amount that we have to look at. We still believe, as Hyun said, the new indictment doesn't really allege any new facts. And in the past, he said we've looked at this, and we've admitted in other proceedings that the company may have been negligent, and in fact, that's how we settled all of the civil cases. But there's no evidence that we've seen that somebody willfully and knowingly violated the Pipeline Safety Act. So first of all, it's difficult to admit to something you just have no evidence that would support that. Second, there's a difference between how a conviction -- so a conviction in federal court has a different standard. And if we admitted that we have willfully and knowingly violated that Pipeline Safety Act, and that could have had consequences in the ongoing proceedings that we have. So given those facts, we've decided that we just can't see that we should admit to violations of those proceedings -- of those acts.

The next question comes from the line of Jim von Reisemann with CRT Capital.

I could use a bit of a math tutorial, if you don't mind. So do you have any general understanding directionally as to how the U.S. Attorney calculated this $281 million gain they allege you made from the San Bruno incident even though you said you haven't seen any sort of specifics? And the second question is in the event there is a guilty verdict, is there a potential for insurance recovery clawbacks? And what I'm getting at there in the second question is, how does the math actually work here, meaning is the investment community possibly double-counting, meaning that you might get credit for settlements already reached? Or for lack of a better word, could there actually be some sort of double jeopardy, meaning that if you've already paid out the third-party settlements for this $565 million, exclusive of these insurance recoveries, would you still be obligated to pay, say, 2 times the $565 million so the dollar amount is actually significantly higher than what the U.S. Attorney is saying?

Well, Jim, I'll start off here. We don't know how they were calculated because all of this is one line at the end of the indictment that these are the numbers for the gain and here's the number for the losses caused. So we'd be just speculating on how those numbers were calculated. Hyun, in terms of mechanically how this works?

So as I said in --at I think, the last earnings call, to get to the alternative fine, there are a number of hurdles that the prosecutors have to overcome. They have to prove the criminal act beyond a reasonable doubt, and then they have to prove beyond a reasonable doubt that, that criminal conduct caused the loss or the gain; and then, they also have to prove the amount of the loss or the gain beyond a reasonable doubt. They also have to try to prove that the alternative fine would not unduly complicate or prolong the sentencing process. And we're just not aware of any situation where an alternative fine was based on the amounts paid to settle personal injury fees. So I think it just remains to be seen how the prosecutors are going to try to demonstrate the link of the $281 million in gain or the $565 million that they have referenced in their indictment. And the $281 million, I just don't know where they came up with that.

The next question comes the line of Anthony Crowdell with Jefferies.

Just want to know if you could provide sort of a range in the amount of deferred taxes you think you'd book in 2015 and maybe '16. I know previously you said you don't expect to be a cash taxpayer in '14 and I guess for most of, I believe, '15. And I guess you go back to paying taxes in '16. I wonder if you could give a range? And also, lastly, do your rate base assumptions include deferred taxes and bonus depreciation in there?

This is Dinyar Mistry, the Controller. Previously, we had said that we are in an NOL position, so we don't expect to pay cash taxes in 2014, possibly going into 2015. We have looked at our range of deferred taxes, and they're embedded in the rate base forecasts that are in the slides that we've given you. So all of those numbers are already implied in the rate base and in the equity numbers that we have provided for 2014.

The next question comes from the line of Shahriar Pourreza from Citigroup.

A little bit more of an obscure question. Most of my other questions were answered. When you -- there's some chatter and headlines that we've seen where Mexico may join CAISO's imbalanced market. Kind of wondering if whether you've done any work on what the potential impact could be for reliability as well as any opportunities that you can come about from additional transmission build?

Well, I think that's a new one for -- we've not heard that Mexico's going to join that imbalanced market. So I can't answer the question about impacts.

Okay. I'll follow up offline on that. And just one last question. Is there still any chatter or any kind of a push to increase the RPS standard above what it is currently by 2020?

Well, there have been questions of so what do we do next after we get to 2020. It also gets wrapped up in what happens with the 111 (d) things that EPA is working on. And here in California, I mean, we've had some discussions among the utilities and some of the State folks around clean energy standards rather than renewable energy standards, but it's all still in a formative status of discussion right now.

Okay, got it. And currently, as far as the net metering cap, can you just remind us what the cap is and whether you can potentially surpass that at a new point?

Yes. They give the cap as currently at 5%. We don't anticipate it being surpassed before 2016. There's some uncertainty about when it could occur, but our guess is 2016 to 2017.

The next question comes of the line of Rajeev Lalwani with Morgan Stanley.

My questions have been asked and answered.

Is there one more question?

Yes, the next question comes from the line of Ashar Khan with Visium.

Yes, I just -- Kent, just a small question. What would be the share count at the end of the year based on your current share issuance program?

That one's going to depend on the price and stuff like that. So I'll just tell you the average shares in Q2 were 469 million.

The average. And what were they at the end of the year, end of the quarter? Do you have that?

Well, I only have the Q1 average, which was 460 million in Q1. That was the average share count. I don't have the end of the quarter.

Okay, great. Thanks, Josh. Thanks, everyone. I think we'll wrap it up. Thanks for participating today, and please don't hesitate to call us if you have any follow-up questions. And have a wonderful day. Thank you.

Thank you, ladies and gentlemen, for attending the PG&E Corporation Second Quarter Earnings Conference Call. This now concludes the conference. Please enjoy the rest of your day.