Good morning, and welcome to the PG&E Corporation Fourth Quarter Earnings Conference Call. At this time, I would like to introduce your host, Mr. Gabe Togneri. Thank you, and have a good conference, you may proceed, Mr. Togneri.

Thanks, Josh. Good morning, everyone, and thanks for joining us. Our discussion of the quarter today will be provided by Peter Darbee, our Chairman, CEO and President of PG&E Corporation; Chris Johns, President of Pacific Gas and Electric Company; and Kent Harvey, Senior Vice President and CFO of the corporation. Other members of our management team are here as well and they'll participate in the Q&A session to follow. I'm going to remind you that our remarks and the Q&A session will include forward-looking statements based on assumptions and expectations reflecting information that's currently available to management. Actual results may differ materially from those forward-looking statements. And important factors that can affect those results are described in the reports that we file with the SEC, including all the risk factors and other factors that are described in our annual report on Form 10-K for the year ended December 31, 2010, and all of our Form 10-Q reports. We'll be filing that 10-K report for the quarter later today. The earnings release that we issued this morning is available on our website along with the supplemental earnings tables and including the Regulation G reconciliations, all of which were sent out this morning. You'll probably want to have that supplemental information available to refer to as we go through the results for the quarter. And with that, I'd like to turn the call over to Peter Darbee.

Thanks, Gabe, and good morning, everyone. We want to take the opportunity today to bring everyone up to date since our earnings call in November. We'll be providing the status of a number of regulatory items and operational updates. We'll also discuss our continuing response to San Bruno, the accident and its financial impact on the company. As you saw in this morning's release, our GAAP financial results for the fourth quarter and the full year reflect the costs related to San Bruno. The fourth quarter costs primarily reflect the effort involved to complete the leak resurvey for the entire Gas Transmission System before year end. The accident recovery and the continued support for the information needs of regulators and investigators. Excluding items impacting comparabilities, earnings from operations for 2010 were in line with our guidance. Moving to 2011, our guidance for earnings from operations is unchanged. However, we're updating our IIC [ph] and our GAAP range for the year. Based on our latest assessment, we're estimating a substantial increase in the direct costs we'll incur to respond to issues raised in San Bruno. We want you to know that we don't take this lightly. However, we're committed to taking the necessary actions to ensure the safety and integrity of our gas system and the safety of the communities we serve. As the San Bruno investigation has continued, there have been additional findings and recommendations from the NTSB and directives from the CPUC. And the significant amount of work associated with these additional requirements is reflected in our higher estimated cost range for 2011. Chris will review the operational steps in more detail and Kent will cover the financial estimates. As context for our discussion of the issues, let me say a few words before turning it over to Chris.…

Thanks, Peter. I'm going to start this morning by reviewing some of the important San Bruno-related developments since our last call. And then I'll address our plans moving forward. And then finally, I'll provide updates on some regulatory items in our operational activities. As a reminder, our first focus has been on helping the families and the community of San Bruno. We have remained steadfastly committed to that focus and we will help with the healing and rebuilding process in that community. The second area of focus has been on ensuring the safety of our Natural Gas System. You may recall that at the time of our last quarterly call in November, we had completed 1/3 of a system wide leak resurvey of our transmission pipelines, including the lines on the San Francisco Peninsula. Subsequently, we completed the entire system resurvey by the end of the year and provided a report to the CPUC a few weeks ago. We took action to address the items found in the survey and noted the results in the report to the CPUC. The results show that our leak rate was in line with our Gas Transmission pipeline peers across the United States. In addition, we've reduced pressure in several of our pipelines to further ensure the safety of the system until record validation or further test work can be performed. The third area we've been focused on related to San Bruno has been our full cooperation with the various investigations and recommendations that are ongoing. With regard to this, at the time of our last call, the National Transportation Safety Board had issued a preliminary report on the San Bruno accident. Since then, the agency has issued two additional interim reports, along with several safety recommendations. The first of these reports came in…

Thanks, Chris. I plan to cover our financial results for the fourth quarter and for full year 2010, including an update on the costs related to the San Bruno accident. I'll also cover guidance and financing activity. Let me first refer you to Table 2 in the supplemental earnings package. Starting with the fourth quarter results, we reported $277 million or $0.70 per diluted common share in earnings from operations. This excludes costs related to the San Bruno accident, which totaled $45 million pretax or $0.07 during the quarter. On a GAAP basis, we reported $250 million or $0.63 per share for the fourth quarter. For the full year, we reported earnings from operations of $3.42 per share and GAAP earnings of $2.82 per share. GAAP results for the year reflect items impacting comparability, including costs associated with the San Bruno accident, which totaled $283 million pretax or $0.43 per share for the year. That includes a $220 million pretax provision we took in the third quarter for the estimated third-party liability and $63 million pretax of direct expenses incurred during the third and fourth quarters. Moving on to Table 4 for the Q-over-Q comparison. Our earnings from operations of $0.70 per share represent a $0.10 decrease compared to the fourth quarter of 2009. This decrease was the result of several factors which are summarized in the table. They include a $0.05 decrease associated with our SmartMeter program. We took a charge to reflect higher capital costs necessary to complete the program that we expect but won't be recovered through rates. Other factors in the Q, a $0.03 decrease due to our nuclear refueling outage in Q4, a $0.02 decrease due to the number of shares outstanding. A number of items resulted in decreases of around $0.01 each including higher…

Thanks, Kent. In closing, as we highlighted today, our team continues to manage and address the issues related to our pipeline operations. We're concentrating our attention on learning from the challenging experiences of 2010. We're determined to use these lessons to improve all of our operations so that we emerge from this a stronger company. And we're committed to the kind of long-term focus that meeting this goal will require. Thank you for your attention today and we look forward to answering your questions. Operator?

[Operator Instructions] Our first question comes from the line of Greg Gordon with Morgan Stanley.

Several questions. First, just to summarize and regurgitate what you said on the San Bruno costs so I understand it correctly. If I add up the costs incurred in both 2010 and your current projections for 2011, it looks like your high-end total cost is a little over $760 million, with roughly $360 million of that direct costs and the remainder costs that you would hope to recover through insurance claims. And so it would seem like the equity, the exposure to date for equity investors in the company is about $0.50 after tax, is that fair?

Greg, yes, I think you're using the right numbers. Your $760 million assumes that the third-party liability piece of the IIC goes all the way up to the $400 million estimate.

Yes, but that summary of the sort of current high-end cases is a fair summary?

Yes, you're essentially focusing on the non-third-party liability costs, most of which would be recovered by insurance.

And can you go into a little bit more detail about why the SmartMeter cost rollout has gone to a higher cost than expected?

Yes, we're pretty far through this program now. We're three quarters of the way, as Chris said, we've implemented about 7.5 million out of the 10 million meters. And late last year as our team has done periodically throughout this multi-year rollout, we did a reassessment of programs and a cost of completion. And as a result of that assessment, that's why we reserved $36 million pretax of capital costs that we expect to be necessary to complete the program that we don't expect to recover through rates. And the key drivers for us where we have experienced some higher systems costs and I think that does reflect the fact that we're a fairly early mover in this space given the magnitude of the implementation. So we definitely have dealt with some scaling issues related to technologies, which we've solved them but it's been no small feat. And we are dealing with more complex billing data than our predecessors have dealt with. And then the second thing is we have had higher costs for customer communications and outreach. And I would say prior industry experience before us indicated that minimal outreach was really required. But we have learned that that is insufficient for our customers and we've committed additional resources to that.

There's a procedural order being contemplated at the CPUC that deals with, or would address the benefits, the cash flow benefits that all utilities, including yours, California are receiving for bonus depreciation? I know there's been a lot of evolution of the way that looks like it's going to play out but can you tell us what the current status is of the proposal?

This is Kent again. The current status of that is there is a draft resolution from CPUC which could be voted out next week. And it's intended to ensure that customers benefit from the most recent tax law. And what it does really is it encourages us to make incremental investments when bonus depreciation is in effect because that's cost-effective for customers. And obviously, that is the intent of the original tax law. What it would do is it would establish a memorandum account and would keep track of the benefits from the December tax law from a revenue requirement perspective. And then it would also -- we could use those benefits essentially, those revenue requirement benefits to fund incremental capital expenditures.

So you weren't counting on that money to defer your equity needs? So it doesn't, in any way -- to put it another way, your expectation that the current $200 million you'd get through normal equity issuance through the 401(k) plan is sufficient if you haven't counted on that deferred tax dollars. And so the fact that you funneled them back into the business to upgrade your infrastructure is not sort of in any way negative to your financing plan?

Yes, I would say, the way I think about it is this month's recent bonus depreciation really isn't a big driver of our equity needs in 2011. And the reason for that is we didn't expect to make cash tax payments until quite late in the year anyway. So it's not actually a big factor for us in 2011.

Could it be a factor in 2012? Or had you not counted on bonus depreciation in '12 when you were working on that plan?

Yes, it will affect 2012 and we'd address that at our Investor Conference when we start talking about 2012. And we'll address how the commission proceeding, what implications that has as well.

Our next question comes from the line of Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG: Just following up on Greg's question a little bit more, it looks like 2010 CapEx came in a little bit lower than expectations from the range you guys last gave. What are your thoughts as far as maybe catch up on 2010 spending? And then how are you identifying projects where you could put this bonus depreciation cash to work, to put more money to work in '11 and '12?

Dan, we actually came in not that far off from where we expected. I remember saying, maybe I think it might have been on the Q2 call that we were running behind on CapEx because we had a lot of storms in the first part of the year. But by year end, I think our total CapEx ended up at about 3.9 which was pretty close to plan. There may be a little carryover into the beginning of 2011 but I don't expect it to be dramatic. In terms of the impact of bonus depreciation on future CapEx for the latter part of the year, we're still really actually trying to assess that. It's tricky because as I mentioned before, they're really -- I don't know that there's going to be a whole lot of revenue requirement benefit in 2011 because we don't really have deferred taxes that we would have otherwise paid until quite late in the year. And there are some negative impacts of the 2011 -- of the most recent tax laws as well such as the loss of the manufacturer's deduction. For us, that's not as big as it is for other utilities because only a third of our generation is owned and therefore results in a manufacturer tax deduction for us, but it is an impact that actually goes in the other direction. And so this memo account would encompass all the revenue requirement impact. We may not see a lot of benefits this year. We would see more in 2012. Dan Eggers - Crédit Suisse AG: And so then just mechanically to help understand this. The account for 2012, would you guys have a reverse cost of capital payment back to the customer on the balance before it is used or would it just sit there at zero cost until you guys are able to find places to deploy the capital?

I think the way it's contemplated is there's a memo account. So for the next three years basically, we'll keep track of the revenue requirement benefits from bonus depreciation and then how we use that to actually benefit customers through incremental capital expenditures. And we'll keep track of the net of that. And then the way it would work is if we didn't utilize the benefits in the account during the General Rate Case period, the commission could consider that in our next General Rate Case.

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

Just trying to think out a few years with Manzana, obviously off the table now with the solar project underway. How do we think about next couple of years in terms of what potentiable (sic) $200 million, $300 million-plus kind of major projects may be in the pipeline for you going forward?

This is Chris, Michael. And we did get approval late last year for another gas facility that is going to be part of our future generation. And then we continue to look at the landscape. You know that we have a rule that requires that we get 33% of our portfolio to come from renewables, and so we will continue to look at the renewable side of the business and really focus on what makes sense for our customers in terms of costs and in terms of diversity of that portfolio. And so that continues to be some area that we will focus on looking at whatever opportunities there may be out there.

When do you think spending on Oakley ramps up? When do you likely begin to earn on it? And where are you in terms of progress on the solar rollout?

Yes, on the Oakley one, I think it's around 2016 timeframe. On the PV, we have got three sites that we're going to get done this year and we're in the process of identifying other sites. And so the PV program seems to be pretty much on track for what we expect. And that kind of rolls out throughout the year because we'll turn them on in probably one-megawatt increments, hopefully starting here in mid to late second quarter.

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

Have you had yet a chance to meet with the new appointees at the PUC and sort of any initial thoughts or color that you might be able to give there?

Yes, this is Tom Bottorff, I'm Senior Vice President of Regulatory Relations. We've had a chance to meet with both Commissioner Florio and Commissioner Sandoval, and I would say at this point, we have great confidence in their abilities and look forward to their assessments in our decisions going forward. So we think they'll approach them fairly and consistently as they have in prior proceedings that they participated in.

Any particular proceedings that they have participated in the past that you think are notable for us to think about?

Well, Commissioner Florio has certainly been an active participant in our General Rate Case. I would expect him to recuse himself on any decision that comes about here in the next month or two. That's probably been his primary participation but he was also a participant in our GT&S proceeding as well so he may in fact recuse himself on that one as well.

Brian, this is Kent. The only other thing I would add is we have worked extensively with Mike Florio as part of the procurement review group that looks over and is involved with a lot of our strategies for procuring gas and electricity and associated hedging. And we've had a very constructive working relationship with Mike and know that he's very knowledgeable about our industry.

The next question comes from the line of Lasan Johong with RBC Capital Markets.

Just following up on Brian's question, are there particular sensitivities that these two commissioners have in terms of what they are looking at or what they want to focus on going forward?

This is Tom Bottorff again. They both said in their opening comments that they're very much concerned about the incident surrounding San Bruno so they'll be focusing a lot on pipeline safety going forward. I think we'll see that in response to the rulemaking that's expected to come out next week.

Any focus on how you think they might look at evolving the regulatory framework in California? If there any kind of incremental tweaks that they might look for?

I wouldn't expect any major revisiting of the regulatory framework. I think they'll just look at and consider each of the proceedings that's coming forward and assess the merits of each one. I don't see any fundamental change in the regulatory framework.

Peter, can you give us a general sense of how you intend to meet the 33% standard? Can you kind of give us a breakdown of A, how much you want to do -- I know it's roughly 50-50, but give us a sense of where you want to spend the money in terms of solar, wind, geothermal, other, and how much you want to buy versus build?

Let me provide a couple of comments by way of introduction and then see if Chris Johns wants to add anything. The first thought that we have is there is a need for some wind in California, but I do want to point out the fact that when it gets hottest in our territory, it usually gets hot because the wind isn't blowing. So while I think there's a need for some wind, that very phenomenon that I just described creates sort of a limit in our thinking on how much wind we would want in the system. Wind, of course, has historically been less expensive than solar. Turning to solar, you have the sort of converse situation, and that is that solar is available when we most need it. It's most available when we most need it. And so we have been moving on solar in a more significant way in recent years. And so I think that will continue. The other thing I would emphasize is that the cost of solar is coming down year-by-year and that's making solar more cost-effective. And so that again would sort of push one in the direction of solar. I think geothermal is a limited portion of the mix and will continue. We don't see a big surge in geothermal right now. The other thing that you addressed is the question of the mix between owned versus contracted for. And let me just say that the commission as well as the solar industry is very committed to the robustness of that industry as it has been in the past, I think it will be in the future. And so we'll continue to see a fair number of independent providers provide renewable power to us in the future. We, of course, have our $1.5 billion solar program. And we're moving, as Chris mentioned, almost megawatt-by-megawatt, bringing that on and we will continue to do so. But I think you're going to see a lot of contracted-for renewable power in the future. Chris, anything you'd add?

No, Peter. I think you covered it.

So can we assume like a 50-50 mix on contract versus owned?

I don't think you can make an assumption one way or the other on that. We'll just have to see as things develop. There is no commission policy on 50-50.

The next question comes from Lauren Duke with Deutsche Bank.

I was hoping you guys could have remind us kind of what you've said before about the recoverability of the direct San Bruno costs, whether through insurance or regulatory proceedings, just kind of what your current thinking is now that you've bumped up that number?

Yes, so there's a lot of sort of pieces to that question. This is Kent. Let me try to take them in order. First, in terms of the third-party liability costs, which is part of the San Bruno cost. Those we do expect that most of those will be recovered through the insurance policies that I described before. In terms of the direct costs associated with San Bruno, there's a number of different parts and pieces to that. So we talked about the additional inspections and tests of our pipeline, we talked about the record validation project that we have underway, and then there's a number of legal and professional costs associated both with the investigations but also with third-party claims in terms of legal costs. So we view many of these as one-time in nature and we generally wouldn't seek recovery through the regulatory process, but some costs are different. For example, the magnitude of the type of the pipeline tests and inspections that we may undertake could be very different from what we thought only a few months back, and therefore, more costly than existing standards in the industry. In that case we would work with our regulators to address funding. And the other thing I'd say is in terms of the legal costs associated with third-party claims, those we didn't accrue as part of the liability. They are part of our direct costs and we do intend to seek recovery of those from our insurance carriers.

So I guess we should think about somewhere in that scale, I guess the percentage of what you expect to be able to try to recover with range depending on where you fall on that scale?

That's correct.

I also just wanted to ask about the 33% renewables legislation that's been proposed. And if you guys had any sense on timing, kind of given the budget focus in the state, and some of the key factors in that legislation that have played out over time in terms of transmission siting and also in-state versus out-of-state, how do you see that playing out this year versus the past few years?

This is Tom Bottorff. On the timing, the legislature has an ambitious schedule to try to get legislation out by March 6. That's in the urgency session that's underway right now. It may or may not succeed with that. If not, then it probably will be addressed later in the year, but they're at least on a timeline now to try to get a bill approved by early March. With respect to the in-state, out-of-state issue, that is a key issue in the legislation. The current legislation, the current draft that's been out of the Senate committee would allow for some purchase of imports from out-of-state. The way it's currently drafted, it would allow the utilities to acquire about 25% of the incremental amounts acquired each year. That contrasts with what the PUC approved here a couple months ago that allows utilities to, I guess get 25% of their total portfolio from these out-of-state imports. So there's a little bit difference in approach. I would say that the current program is a little bit more lenient in allowing the use of imports and racks [ph] to meet the utilities' 33% requirement. The current legislation is a little bit more restrictive, but it still has a ways to go so we'll have to see how it ultimately comes out.

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

Apart from the GRC and the Gas Accord, what do you think are some major decisions where we can get an idea of how the new commissioners are tending to lean, say in the second half or even in early 2012?

This is Tom Bottorff again. I think you've highlighted some of the key issues and our key cases certainly for us it's the GRC and GT&S. We'll see how they respond to the other utilities' requests for General Rate Case increases that are pending. Those are the ones I'd probably watch more carefully. We'll see how they respond to the issues raised in the rulemaking to look at pipeline safety not just for our company but for all utilities in the state. I think we'll have some indication of what kinds of programs and mandates they feel are appropriate for cost recovery going forward. You also have the issue around dynamic pricing, what kinds of pricing structures are going to be appropriate and the timing of those. And then finally, just some, probably some policy decisions on energy efficiency incentives going forward. So those are some of the major proceedings I would watch.

Just following up on that energy efficiency real quick, what kind of timeframe do you guys consider appropriate for that setting of the next round of energy efficiency programs?

Well, the commission approved an extension of the old mechanism for purposes of determining a reward this year. So there will be a filing utilities we'll probably make within the next month or two or a claim for this year's performance, and then the commission has a pending decision with respect to the kinds of incentives that would be appropriate for the 2010 to 2012 programs that are currently being implemented. So we'll have to wait and see but I think they'll come in two steps like that.

Our next question comes from the line of Paul Patterson with Glenrock Associates.

Just in terms of these costs associated with the pipeline safety through the new standards that might show up, and just in general what sort of inspection stuff might be going on, do we have any sense as to how much of those costs not related specifically to San Bruno but just sort of, I guess coming, resulting from in terms of new standards and what have you, how much those new costs might be?

What I indicated before in terms of our direct costs is the overall cost in the $200 million to $300 million range of which that is a component. I think the tricky part here is that the investigation is still underway and we're still having requests coming in. It's hard for us to know the exact scope and nature of inspections that we will be doing. So to me, it's best to think about the direct costs as kind of a portfolio of work, and depending on how events unfold, some components could be greater and some could be less within that overall total. But it's really hard to pinpoint a specific cost at this point. Paul Fremont - Jefferies & Company, Inc.: So I guess in terms of just sort of what might be sort of ongoing after San Bruno, after all the costs associated with that, will we have a better idea with this pipeline safety protocol coming up to next week, or is there any way we get sort of any feelings for this because there's so many sort of proposals going on, or...?

Yes, Paul, this is Chris Johns. I think and I can understand the frustration of wanting to look out and see what kind of certainty you can gain from a cost basis, but there's several things that are in play right now. So first of all, you have the NTSB which still has not issued its final report and doesn't know the root cause. So obviously, when we know the root cause, there will be ramifications for what we and everybody else in the industry need to do going forward to make sure it doesn't happen again. On top of that, you've got the -- not the investigation but the rulemaking that the CPUC is entering into, and that is just beginning. And so it's really hard to predict what additional rules that they are going to put in place upon again all the utilities in the state. And then obviously, you've got both at the state and federal level, different policymakers putting forth proposed new legislation that will additionally put in different rules and requirements than what we have in place today. And then finally, you have our own proposal that you'll see the first glimpse of in the second quarter around Pipeline 2020 that will have some implications in, not just from a modernization but also in looking at some of our best practices. So I think that's what the difficulty is, is that you have a lot of those different things in play right now and it's really hard to predict what ultimately the outcome will be.

The next question comes from the line of Ashar Kahn with Visium Asset Management.

I might have missed it. Could you tell us what the rate base ended up for 2010 and what the rate base is projected for 2011? It might have be in the slide. I might have missed it or something.

This is Kent. I do have the 2010 recorded for you. I think 2010 ended up, I believe at $21.1 billion for the weighted average rate base for last year.

And what is it expected this year?

I don't have an updated forecast for that. That'd be something we'd probably address on our Investor Conference.

You have a follow-up question from the line of Michael Lapides with Goldman Sachs.

Kent, on that rate base question, is that California and transmission? Is California electric and gas as well as transmission all blended together?

Yes, it is.

[Operator Instructions] There are currently no further questions coming from the phone lines.