PG&E Corp (PCG) 2010 Q4 法說會逐字稿

Good morning and welcome to the PG&E Corporation's 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 & 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 will 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 is 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 will 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 will probably want to have that supplemental information available to refer to as we go through the results for the quarter.

And with that, I would 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 will be providing the status of a number of regulatory items and operational updates.

We will 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 are updating our IIC and our GAAP range for the year.

Based on our latest assessment, we are estimating a substantial increase in the direct costs we will incur to respond to issues raised in San Bruno.

We want you to know that we don't take this lightly.

However, we are 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.

Investigations into the San Bruno accident are not yet complete.

We still don't know what will ultimately be identified as the root cause.

What we do know is that any company that experiences a tragedy like the explosion in San Bruno has an obligation to learn everything it can from what occurred.

We have a responsibility to apply those lessons, first to ensure something like this doesn't happen again and second, to emerge as a better and stronger organization.

This is what our customers, shareholders and regulators and other stakeholders expect from PG&E and let there be no doubt that we will hold ourselves to these high standards.

We are approaching this effort determined to be methodical and thorough.

At the same time, everyone on our team understands the importance of taking responsible and timely action.

We know there continues to be a very strong desire to get answers and information quickly and want our customers and others to know that we hear their concerns.

Some of the steps that Chris will discuss are aimed to helping meet this need.

In the end, we want our customers to have confidence in the safety in knowing the reliability of our Company's operations.

We know we have to work to re-earn the confidence of our customers and this focus will drive us going forward.

And with that, I would like to turn it over to Chris.

Thanks, Peter.

I am going to start this morning by reviewing some of the important San Bruno-related developments since our last call and then I will address our plans moving forward.

And then, finally, I will provide updates on some regulatory items and 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 one-third of a systemwide 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 showed that our leak rate was in line with our gas transmission pipeline peers across the United States.

In addition, we have 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 have 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 mid-December.

Among other things, it rolled out certain potential causes, such as external corrosion or excavation-related damage to the pipe.

That report also noted a discrepancy in PG&E's historical records regarding the physical characteristics of the pipe that ruptured.

The NTSB stated at that time that it didn't know whether records played any part in the accident.

In January, they issued a set of recommendations urging PG&E and other pipeline operators across the industry to validate and verify their pipeline records and we have been working aggressively on that as we speak.

We are in the process now of collecting, scanning and indexing more than one million individual hardcopy records into a comprehensive electronic database.

This will provide high-quality electronic documentation to verify the determination of the maximum operating pressures on our pipelines.

We have hired KPMG to ensure that we have a sound process that will generate dependable results in this effort.

And we have also brought in other outside help to assist us with the actual work of collecting and converting pipeline records that date all the way back into the 1940s.

We're scheduled to report on the results of this effort to the California Public Utilities Commission on March 15.

Any gaps and inconsistency in our records and the challenges that these have created in getting quick accurate answers to questions are unacceptable and we are committed to getting it right.

The CPUC is focused, as we are, on ensuring that sound information validates the operating pressures for gas pipelines in California.

When we complete the records work, we will be discussing with the CPUC the best way to approach any areas where additional pipeline testing may be appropriate.

The NTSB issued its second interim report on January 21st, and this report summarized the metallurgical analysis on the pipe segment involved in the explosion.

That report commented on the physical makeup of the pipe segment and the quality of the welds.

There' has been a great deal of commentary and speculation from others on that report.

However, the NTSB didn't provide any conclusions with that report.

They have also told us very clearly that they don't want us speculating or commenting based on the information currently available.

Obviously we will continue to comply with that request and we will continue to cooperate fully with the NTSB and the CPUC.

We also recognize that we need to improve our overall operations and maintenance of our gas system.

So we are taking additional steps to develop and implement the highest industry standards for pipeline assessment and testing practices.

We are drawing on the expertise of respected industry professionals to advise us on hydrostatic testing, pipeline integrity and prioritization and risk assessment.

In order to further strengthen our in-house capabilities, we have initiated a global search to identify and recruit a top-flight gas operations executive for our senior team.

From all the work we are doing related to our current gas transmission system, we expect to develop plans for modernizing our pipeline system over the next decade.

As you will recall, our announcement of a longer-term multifaceted pipeline modernization program called Pipeline 2020 was introduced last year in concept.

We're well on our way into developing the first part of that program, which will focus on items such as pipeline replacement and adding automated or remote shutoff valves in key locations around our system.

We are targeting the second quarter of this year to file that proposal with the CPUC.

However, this timeline could be impacted by an order instituting rulemaking or an OIR that the CPUC is launching to address California's gas pipelines.

We'll keep you informed as this progresses.

Now before I close on San Bruno, I want to once again reiterate what Peter said.

This has been a terrible tragedy and it would be an even greater tragedy if we don't do what we can to prevent it from happening again.

And that is just what we will do.

Now I am going to shift gears and provide you with an update on a couple of regulatory items and some of our operational developments.

First, in the last several weeks, Governor Jerry Brown has appointed two new Commissioners to fill vacancies at the CPUC.

We look forward to working with the new Commissioners, Mike Florio and Catherine Sandoval.

Moving to the General Rate Case, we're awaiting a proposed decision from the administrative law judge.

You will recall that we reached an uncontested settlement in our General Rate Case on all issues except for the return on the undepreciated value of older meters that are replaced by SmartMeters.

When we do receive a final decision in the GRC, it will be retroactive to January 1st.

And the impact on overall rates will be minimal compared to what is in place currently.

In the Gas Transportation and Storage Case, we also reached an all-party settlement last year and that is known as the Gas Accord.

We are awaiting a proposed decision on the Gas Accord and would expect to see that proposed decision anytime now.

As with the GRC, the CPUC has ruled that the final decision will be retroactive to January 1.

The CPUC has also indicated that it will take up any new issues with respect to gas pipeline operations in California through an OIR, the one that I have just recently mentioned.

The CPUC also has an Order Instituting Investigation for Rancho Cordova, which is where our gas distribution leak led to a single residence explosion in 2008.

Our response to that OII is being filed today and does not dispute the NTSB's findings that the root cause was a faulty repair to a line.

The next step is for the ALJ to set a schedule for that proceeding.

In December, we received a CPUC decision approving approximately $29 million as a "true-up payment" for our 2006 to 2008 customer energy efficiency achievements.

This decision and the corresponding revenues are in recognition of PG&E's result in helping customers be more energy-efficient.

Also in December, the CPUC issued a proposed decision that would deny the Manzana wind project as a utility investment, primarily on economic grounds.

Following this proposed decision, the developer, Iberdrola, exercised its right to terminate the contract.

And as a result, we do not expect Manzana to move forward as a utility-owned project.

PG&E continues to be involved in utility-owned renewable generation through our solar photovoltaic or PV program.

As you know, we received approval to build 250 megawatts of PV over five years and purchase an additional 250 megawatts through power purchase agreements.

In October, the CPUC approved PG&E's procurement process and land selection criteria for this program.

And so for year 1, we have acquired three sites in Fresno County.

We have completed site work on two of those and begun work on the third.

We expect to break ground on those this spring and the three projects combined total about 50 megawatts.

They should become operational in 1-megawatt increments starting in the second quarter and be fully operational by the end of the year.

We are currently working through development activities like interconnection studies, permitting and assessing land acquisition for the program years 2 through 5.

I am also pleased to report that our 657-megawatt Colusa generating station achieved commercial operation in December.

This natural gas powered plant was built with a strong safety record and provides efficient and clean generation for our customers.

Finally, I'd would like to touch on our SmartMeter program.

You will recall that an independent review of these meters last year found that they are accurate and working properly.

In addition, some members of the California assembly requested a study on whether the radiofrequency emitted by SmartMeters causes health impacts.

So the California Council on Science and Technology released a report last month finding that radiofrequency exposure with SmartMeters is much less than cell phones and other household devices and has no known ill health effects.

We continue to work proactively on outreach to our communities addressing their questions and concerns of the customers in those communities as we deploy SmartMeters throughout our service territory.

To date, we have deployed 7.5 million new gas and electric meters and we remain on track to complete the rollout of a total of 10 million meters through 2012 as planned.

The total cost of the conversion is coming in modestly above our original estimates and we took a charge in the fourth quarter that Kent is going to discuss when he is reviewing the financial results.

And so that concludes my discussion and I'll turn it over to Kent.

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 will 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 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 storm expenses and a lower energy efficiency incentive than we received in 2009.

Miscellaneous items totaled a negative $0.04, including, as I mentioned on our last call, more of our operating expenses tilted towards Q4 than in the prior year.

These items were partially offset by a $0.06 increase from higher authorized rate base adjustments.

I will now move on to guidance and I will direct you to Table 8.

Our 2011 guidance for earnings from operations remains at $3.65 to $3.80 per share.

As always, our guidance is based on a number of assumptions, including approval of the settlement reached in the 2011 General Rate Case, capital spending consistent with the GRC settlement and other regulatory proceedings, and our ability to earn our authorized return of 11.35%.

As Peter mentioned, we are updating our overall GAAP range for 2011 to reflect our latest thinking about the item impacting comparability related to the San Bruno accident.

The new GAAP range is $2.94 to $3.50 per share.

Let me remind you that the item impacting comparability for the San Bruno accident consists of two components.

First is the third-party liability, which we estimated in Q3 to be $220 million to $400 million pretax.

That estimate has not changed.

You will recall that we booked the low end of that range, $220 million, in the third quarter.

So the remaining range for the third-party liability equates to $0 to $180 million, or up to $0.27 per share.

The second component of the IIC is the estimated direct expenses that we incur in connection with the accident.

This has been very difficult to estimate since we haven't known all the work that would be required as a result of the accident and the investigation.

In early November, we provided a range of $100 to $150 million pretax covering the period beginning in Q4 of last year through the end of this year.

Given the subsequent NTSB reports and resulting CPUC directives, along with the substantial work we have underway, we believe that range is no longer adequate.

We have increased our estimates of 2011 direct expenses to be $200 million to $300 million pretax.

This equates to $0.30 to $0.44 per share.

The higher cost estimates primarily results from the work that Chris described.

First, the huge effort we have initiated to collect and verify our pipeline records going back decades.

This is a significant undertaking and the work is expected to continue through the year.

We also expect that in addition to the records work, significant testing may be required in the field to ensure that sound information forms the basis for operating pressures on our pipeline.

To support these efforts, we are utilizing a variety of industry experts and outside resources.

We also expect to incur substantial legal costs related to the investigation, third-party claims and so forth.

At this point, without a root cause determination and with additional requests ongoing, the scope and nature of the work we will undertake is not clearly known.

But we do know that it is work that must get done.

Therefore, we think it is appropriate to use a broader range for the estimate of direct costs.

If you combine the two components,the third-party liability and the direct costs, the sum ranges from $200 million to $480 million pretax or, $0.30 to $0.71 per share.

As I said on our last call, we have not included in the item impacting comparability the benefit of any expected insurance recoveries for third-party liability costs.

That is mainly a timing issue.

We are not going to book such an asset until a future period when the insurance recovery process has progressed sufficiently.

And that could still be a ways off.

I will remind you we have third-party liability coverage of $992 million and we continue to believe most of the costs associated with third-party claims will ultimately be recoverable under our policy.

Before I leave guidance, a number of you have asked about 2012 and I anticipate that after we receive our GRC decision, we will be able to provide 2012 guidance and discuss the various factors and assumptions associated with that guidance.

We intend to do that at our Investor Conference, which we plan to schedule later in the spring once the timing is clearer.

Now I'll turn to financing, dividends and related activities and let me start with the dividend.

As you know, we have an uncontested settlement in our 2011 General Rate Case, but we are still awaiting a proposed decision.

And has been our practice in prior GRC years, our Board is going to consider the annual dividend change after we receive a final GRC decision.

So we intend to maintain our current dividend level for the first quarter and we would expect to address the dividend in the second quarter.

Next is equity issuance.

In 2010, our equity issuance, under the 401k and DRIPP program totaled about $200 million, which was in line with our expectations for the year.

In addition, we established an equity dribble program in November and we used it to issue a little over $100 million of equity before year-end.

So total equity issuance last year was a little more than $300 million.

As we look at 2011, we'd expect our internal equity programs, the 401k and the DRIPP, to again be able to generate about $200 million of equity during the year.

Based on our current capital plans, we expect that will be sufficient to meet our equity needs for 2011 without relying on the dribble program for additional equity.

Our current capital plans reflect, among other things, our settlements in the General Rate Case and the GT&S case and the fact that the Manzana wind project will not move forward as a utility investment.

We'll continue to manage our capital structure consistent with our authorized levels and we will keep you posted as the year progresses.

And I will now turn it back over to Peter.

Thanks, Kent.

In closing, as we have highlighted today, our team continues to manage and address the issues related to our pipeline operations.

We are concentrating our attention on learning from the challenging experiences of 2010.

We are determined to use these lessons to improve all of our operations so that we emerge from this a stronger company.

And we are 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.

Please proceed.

Thank you.

Good morning, gentlemen.

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 and 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 are essentially focusing on the non-third-party liability costs, most of which will be recovered by insurance.

Great.

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

Greg, we are pretty far through this program now with three quarters of the way.

As Chris said, we have implemented about 7.5 million out of the 10 million meters.

And late last year, as our team has done periodically throughout this multiyear rollout, we did a reassessment of the program and cost of completion.

And as a result of that assessment, that is 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 a fairly early mover in this space given the magnitude of the implementation.

So we definitely have dealt with some scaling issues related to the technologies, which we have solved them, but it has 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 our 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 have committed additional resources to do that.

Thanks.

Final question.

There is 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, in California are receiving for bonus depreciation.

I know there has been a lot of evolution of the way that looks like it is going to play out.

But can you tell us what the current status is of the proposal?

Yes, this is Kent again.

The current status of that is there is a draft resolution from the PUC, which could be voted out next week.

And it is 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 with bonus depreciation that is in effect because that is 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.

Okay, so you weren't counting on that money to defray your equity needs, so this doesn't in any way -- to put it another way, your expectation that the current $200 million you would get through normal equity issuance through the 401k plan is sufficient.

You hadn't counted on that deferred tax dollars and so the fact that you've 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 most 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 is not actually a big factor for us in 2011.

Okay, 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 will address how the Commission proceeding -- what implications that has as well.

Okay, thank you.

Josh, do we have another question?

The next question comes from the line of Dan Eggers with Credit Suisse.

Hey, good morning.

Justfollowing 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've 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 billion, 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 are still really actually trying to assess that.

It is tricky because, as I mentioned before, I don't know that there is 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 manufacturers' deduction.

For us, that is 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 and we may not see a lot of benefits this year.

We would see more in 2012.

Okay, and so then just mechanically and 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 will it just sit there at zero cost until you guys are able to find places to deploy the capital?

I think the way it is contemplated is there is a memo account and so for the next three years basically, we will keep track of the revenue requirement benefits from bonus depreciation and then how we use that to actually benefit customers through incremental capital expenditures.

We will 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.

Okay, got it.

Thank you.

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

Please proceed.

Yes, 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 the next couple of years in terms of what potentialable $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?

On the Oakley one, I think it is around 2016 timeframe.

On the PV, we have got three sites that we are going to get done this year and we are 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 will turn them on in probably 1-megawatt increments hopefully starting here in mid to late second quarter.

Got it, ok, thank you, guys.

Much appreciated.

Brian Chin, Citigroup.

Hi, good morning.

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?

This is Tom Bottorff.

I am Senior Vice President of Regulatory Relations.

We have 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 of our decisions going forward.

We think they will approach them fairly and consistently as they have in prior proceedings that they have participated in.

Any particular proceedings that they have participated in, 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.

So I would expect him to recuse himself on any decision that comes about here in the next month or two.

So that has 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 in 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 strategy for procuring gas and electricity and associated hedging.

And we have had a very constructive working relationship with Mike and know that he is very knowledgeable about our industry.

Great, thank you.

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

Please proceed.

Thank you.

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 are very much concerned about the incidents surrounding San Bruno, so they will be focusing a lot on pipeline safety going forward.

I think we will see that in response to the rulemaking that is expected to come out next week.

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

I wouldn't expect any major revisiting of the regulatory framework.

I think they will just look at and consider each of the proceedings that is coming forward and assess the merits of each one.

I don't see any fundamental change in the regulatory framework.

Fantastic.

And just, 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 -- I know it is roughly 50/50, but give 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.

A 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 is a need for some wind, that very phenomenon that I've 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 is 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 is making solar more cost effective and so that, again, would 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 will 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 are 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 would 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.

No, I understand that.

Thank you very much.

I appreciate it.

The next question comes from the line of Lauren Duke with Deutsche Bank.

Please proceed.

Hi, good morning.

I was hoping you guys could remind us kind of what you have 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 is 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 costs, 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 is a number of different parts and pieces to that.

So there is -- we talked about the additional inspections and tests of our pipeline.

We talked about the records validation project we have underway and then there is 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 test 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 would 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.

Okay.

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

That's correct.

Okay.

And then my second question, I also just wanted to ask about the 33% renewables legislation that has 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 citing and also in-state versus out-of-state, how you see that playing out this year versus the past few years?

This is Tom Bottorff again.

On the timing, the legislature has an ambitious schedule to try to get legislation out by March 6th.

That is in the urgency session that is 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 are 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 has been out at the Senate committee would allow for some purchase of imports from out-of-state.

The way it is 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 the utilities to I guess get 25% of their total portfolio from these out-of-state imports.

So there is a little bit difference in approach.

I would say the current program is a little bit more lenient in allowing the use of imports and RECs to meet the utility's 33% requirement.

The current legislation is a little bit more restrictive, but it still has a ways to go.

So we will have to see how it will ultimately come out.

Great, thank you so much, guys.

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

Please proceed.

Good morning.

You have addressed some of this already, but 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 early 2012?

This is Tom Bottorff again.

I think you have highlighted some of the key issues or key cases.

Certainly for us, it is the GRC and GT&S.

We will see how they respond to the other utilities' requests for General Rate Case increases that are pending.

Those are the ones I would probably watch more carefully.

We will 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 will 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, 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 will probably make within the next month or two for a claim for this year's performance.

And then the Commission has a pending decision with respect to the kinds of incentives that will be appropriate for the 2010 to 2012 programs that are currently being implemented.

So we will have to wait and see, but I think they will come in two steps like that.

Okay, great.

Thanks.

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

Please proceed.

Good morning.

Most of my questions have been answered, but just in terms of these costs associated with the pipeline safety, sort of 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 I guess coming -- resulting from it 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 are still having requests coming in.

It is hard for us to know the exact scope and nature of inspections that we will be doing.

So to me, it is best to think about the direct cost 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 is really hard to pinpoint a specific cost at this point.

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, we don't -- do you have -- I mean we will we have a better idea with this pipeline safety protocol coming up next week?

Is there any way we get sort of any feeling for this because there are so many sort of proposals going on?

Paul, this is Chris Johns.

I think that the -- 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 are 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 needs to do going forward to make sure it doesn't happen again.

On top of that, you have got the -- not the investigation, but the rulemaking that the CPUC is entering into and that is just beginning.

And so it is 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 have 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 will 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 is what the difficulty is, is you have a lot of those different things in play right now and it is really hard to predict what ultimately the outcome will be.

Okay, thanks a lot.

The next question comes from Ashar Khan with Visium Asset Management.

Please proceed.

Good morning.

Just wondering, 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 be in a 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.

Okay.

And what is it expected this year?

I don't have an updated forecast for that.

That would be something we would probably address at our investor conference.

Okay.

Thank you.

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

Please proceed.

Hey, guys.

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

Yes, it is.

Okay, thank you.

(Operator Instructions).

There are currently no further questions coming from the phone lines.

All right, in that event, we would like to thank you all for joining us and wish you a great day.