Morning, and welcome to the PT and E Corporation 4th Quarter Earnings Conference Call. At this time, I would like to introduce your host, Mr. Gabe Togneri. Thank you now. 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 Darby, our Chairman, CEO and President of PG and E Corporation Chris Johns, President of Pacific Gas and Electric Company and Kent Harvey, Senior Vice President and CFO I'm going to remind you that our remarks and the Q and 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 ks for the year ended December 31, 2010, and all of our Form 10 Q reports. We'll filing that 10 ks 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 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 Darby.
Thanks, Gabe, and good morning, be 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 for the Q4 and the full year reflect the costs related to San Bruno. The 4th quarter costs primarily reflect the effort involved to complete the leak resurvey for the entire gas transmission and investigators. Excluding items impacting and investigators.
Excluding items impacting comparabilities, earnings from operations for 2010 were in line with our guidance. Moving to 20 11, our guidance for earnings from operations is unchanged. However, we're updating our IIC 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
the
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 our are not yet complete and 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.
1st, to ensure something like this is what our customers, shareholders and regulators and other stakeholders expect from PG and E and let there be no doubt that we will hold ourselves to these high standards. We're approaching this effort determined to be methodical and thorough. 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 and 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'd like to turn it over to Chris. Thanks, Peter. We're 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 action to address the items found in the survey and noted the results in the report to the CPUC.
The results showed that our 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 3rd 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 2 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 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 and E and other pipeline operators across the industry to validate and verify their pipeline records. And we've been working aggressively on that as we speak.
We're in the process now of collecting, scanning and indexing more than 1,000,000 individual hard copy 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've hired KPMG to ensure that we have a sound process that will generate dependable results in this effort. And we've 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 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'll be discussing with the CPUC the best way to approach any areas where additional pipeline testing may be appropriate. The NTSB issued its 2nd interim report on January 21 and this report summarized the metallurgical analysis on the pipe segment involved in the explosion. Great deal of commentary and speculation from others on that report. 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've also told us very clearly that they don't want us speculating or commenting based on the information currently available. Obviously, we'll continue to comply with that request and we'll continue to cooperate fully with the NTSB and the CPUC. Recognize that we need to improve our overall operations and maintenance of our gas system. So we're taking additional steps to develop and implement the highest industry standards for pipeline assessment and testing practices.
We're drawing on the expertise of respected industry professionals to advise us on hydro static testing, pipeline integrity and prioritization and risk assessment. In order to further strengthen our in house capabilities, team.
From all
the work we're doing related to our current gas transmission system, we expect to develop plans for modernizing our pipeline system over the next decade. As you'll 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 or remote shutoff valves in key locations around our system. We're targeting the Q2 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's just what we will do. Now I'm going to shift gears and provide you with an update on a couple of regulatory items in some of our operational developments.
First, in the last several weeks, Jerry Brown has appointed 2 new commissioners to fill vacancies at the CPUC. We look forward to working with the new commissioners, Mike Florio and judge. Impact on overall rates will be minimal compared to what's in place currently. In the gas transportation and storage case, we also reached an all party settlement last year and that's known as the gas accord. We're 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 response to that OII is being filed today in response to that OII is being filed today and does not dispute the NTSB's findings that the root cause was a fault a repair to align. The next step is for the ALJ to set a schedule for that proceeding. In December, we received approving approximately $29,000,000 as a true up payment for our 2006 to 2,008 customer energy efficiency achievements. This decision and the corresponding revenues are in recognition of PG and 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 Manzanita to move forward as a utility owned project. PG and 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 2 50 megawatts of PV over 5 years and purchase an additional 2 50 megawatts through power purchase agreements.
In October, the CPSC approved PG
and E's procurement process
and land selection criteria for this program. CPSC approved PG and E's procurement process and land selection criteria for this program. And so for year 1, we've acquired 3 sites in Fresno County. We've completed site work on 2 of those and begun work on the 3rd. We expect to break ground on those this spring and the 3 projects combined be fully operational by the end of the year.
We're currently working through development activities like interconnection studies, permitting and assessing land acquisition for the program years 2 through 5. I'm also pleased to report that our 6 57 Megawatt Calusa generating station achieved commercial operation in December. This natural gas powered plant was built with a strong safety record and provides efficient an Assembly requested a study on whether the radio frequency emitted by smart meters causes health impacts. So the California Council on Science and Technology released a report last month finding that radio frequency exposure with smart meters 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 customers in those communities as we deploy smart meters throughout our service territory.
To date, we've deployed 7,500,000 new gas and electric meters and we remain on track to complete the rollout of a total of 10,000,000 meters in or 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 Q4 that Kent is going to discuss when we were reviewing the financial when he's reviewing the financial results. And so that concludes my discussion and I'll
Q4 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 and the supplemental earnings package. Starting with 4th quarter results, we reported $277,000,000 or $0.70 per diluted common share in earnings from operations. This excludes costs related to the San Bruno accident, which totaled $45,000,000 pretax or 0 point $7 during the quarter.
On a GAAP basis, we reported $250,000,000 or $0.63 per share for the 4th quarter. For the full year, we reported earnings from operations of 3.42 dollars per share. GAAP results for the year reflect items impacting comparability, including costs associated with the San Bruno accident, which totaled $283,000,000 pretax or 0.43 dollars per share for the year. That includes a $220,000,000 pre tax provision we took in the 3rd quarter for the estimated 3rd party liability and $63,000,000 pretax of direct expenses incurred during the 3rd and 4th quarters. Moving on to Table 4 for the Q over Q comparison.
Our earnings from operations of $0.70 per share represent the result of several factors which are summarized in the table. They include a $0.05 decrease associated with our smart meter program.
Won't
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 2 1,009. 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 investment. I'll now move on to guidance and I'll direct you to table 8. Our 2011 guidance for earnings from operations remains at $3.65 to 3 point $8.0 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
range for 20.11 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 estimated in Q3 to be $220,000,000 to $400,000,000 pre tax. That estimate has not changed. You'll recall that we booked the low end of that range $220,000,000 in the 3rd quarter. So remaining range for the 3rd party liability equates to $0 to $180,000,000 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 $100,000,000 to $150,000,000 pre tax covering the period beginning in Q4 of last year through the end of this year. Given the the that range is no longer adequate. We've increased our estimates of 20.11 direct expenses to be $200,000,000 to $300,000,000 pre tax.
This equates to $0.30 to $0.44 per share. The higher cost estimates primarily results in the work that Chris described. First, the huge effort we've initiated to collect and verify our pipeline records going back decades. This is
a
To support these efforts, we're utilizing a variety of industry experts and outside resources. We also expect to incur substantial legal costs investigation, 3rd 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'll undertake is not clearly known. But we do know that it's work that must get done. Therefore, we think it's appropriate to use a broader range for the estimate of direct costs.
If you combine the 2 components, the 3rd party liability and the direct costs, the sum ranges from 200,000,000 dollars to $480,000,000 pre tax 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 3rd party liability costs. That's mainly a timing issue. We're not going to book such an asset until a future period when the insurance recovery process has progressed efficiently and that could still be a ways off. I'll remind you we have 3rd party liability coverage of $992,000,000 and we leave guidance, a number of you have asked about 2012 and I anticipate that after we receive a GRC decision, we'll be able to provide later in the spring once the timing is clear.
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're still awaiting a proposed decision. And it's 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 Q1 and we'd expect to address the dividend in the Q2.
Next is equity issuance. In 2010, our equity issuance under the 401 and DRIP programs totaled about $200,000,000 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 a little more than $300,000,000 As we look at 2011, we'd expect our internal equity programs, the 401 and the DRIP to again be able to generate about $200,000,000 of equity during the 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 and 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'll keep you posted as the year progresses. And I'll now turn it back over to Peter.
Thanks, Kent. In closing, as we've 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?
Our first question comes from the line of Greg Gordon with Morgan Stanley. Please proceed.
Thank you. Good morning, gentlemen. Good morning, Greg. 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 $1,000,000 with roughly $360,000,000 of that direct costs and the remainder costs that you would hope to recover through insurance claims. And so it would seem like the 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 $760,000,000 assumes that the 3rd party liability piece of the IIC goes all the way up to the $400,000,000 dollars 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, which most of which will
be recovered by insurance. Great. And can you go into a little bit more detail about why does the smart meter cost rollout has gone to a higher cost than expected?
Yes, Greg. We're pretty far through this program now with 3 quarters of the way. As Chris said, we've implemented about 7,500,000 out of the 10,000,000 meters. And late last year, as our team has done periodically throughout this multiyear rollout, we did a re assessment of the program and at cost to completion. And as a result of that assessment, that's why we reserved $36,000,000 pre tax 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 solved them, but it's been a 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 learned that that is insufficient for our customers and we've committed additional resources to do that.
Thanks. Final question. There's a procedural order being contemplated at the CPUC that deals with or would address the cash flow benefits that all utilities, including yours in 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? Yes, Greg,
The current status of that is there is a draft resolution from the PUC which could be voted out next week. 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.
Okay. So you weren't counting on that money to defray your equity needs. So it doesn't in any way to put another way, your expectation that the current 200,000,000 you'd get through normal equity issuance through the 401 plan is sufficient. You hadn't counted on that deferred tax dollars. And so the fact that you funnel 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's not actually a big factor for us in 2011.
Okay. Could it a factor in 2012 or had you not counted on bonus depreciation in 2012 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
Josh, do we have another question?
Yes, sir. Our next question comes line of Dan Edgert with Credit Suisse. Please proceed.
Hi, good morning. Just following up on Greg's question a little bit more. It looks like 20 10 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 20 10 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 2011 and 2012?
Dan, we actually came in not that far off from where we expected. I remember saying maybe as 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 1st 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 in 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, there 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 are getting that we would have otherwise paid until quite late in the year. And there are some negative impacts of the 20 11 of the most recent tax law as well, such as the loss of manufacturers' 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 memo account would encompass all the revenue requirement impacts. We may 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.
Okay. And so then just mechanically help I 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 is it just sit there at 0 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. And so for the next 3 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
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 next couple of years in terms of what potential 200,000,000 dollars $300,000,000 plus kind of major projects may be in the pipeline for you going forward?
That is going to be part of our future generation. And then we continue to look at the landscape 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're going to 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 3 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.
Got
Our next question comes from the line of Brian Chin with Citigroup. Please proceed.
Hi, good morning.
Good morning, Brian.
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 Batory. 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 of our decisions going forward. We think they'll approach them 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. So I would expect him to recuse himself in any decision comes about here in the next month or 2. So I that's probably been his primary participation, but he was also a participant in our GT and S proceeding as well. So he may in fact recuse himself in that one as well.
And Brian, this is 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 LaSalle Jones with RBC Capital Markets. Please proceed.
Thank you. Just following up on Brian's question, are there particular sensitivities that these Tom Bottorff
again. They both Tom Batorf again. They both said in their opening comments that they're very much concerned about the incident or the incidents 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 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'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.
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 do? I know it's roughly fifty-fifty, 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 John 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'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 effective. And so that again would sort of push 1 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 is 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 in the future. We, of course, have our $1,500,000,000 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 fifty-fifty 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 fifty-fifty.
No, I understand that. Thank you very much. Appreciate
it.
The next question comes from the line of Lauren Duke with Deutsche Bank. Please proceed.
Hi, good morning.
Good morning.
I was hoping you guys could remind us 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. 1st, in terms of the 3rd party liability costs, which is part of the same Bruno cost, those we do 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 there's we talked about the the additional inspections and tests of our pipeline. We talked about the records validation project that 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, 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 3rd 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 try to recover would range depending on where you fall on that scale?
That's correct.
Okay. And then my second question, 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 Biotrff again. 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 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 of 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 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'll have to see how it ultimately comes out.
Great. Thank you so much, guys.
The next question comes from the line of Travis Miller with Morningstar. Please proceed.
Good morning. Apart
you've addressed some
the new commissioners are tending to lean, say in the second half or even early 2012?
This is Tom Bautorf again. I think you've highlighted some of the key issues or key cases, certainly for us it's the GRC and GT and 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 the rule making 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 maybe 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 2 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'll have to wait and see, but I think they'll come in 2 steps like that.
Our next question comes from the line of Paul Patterson with Glenrock Associates. Please proceed.
Good morning.
Good morning, Paul.
Most of my questions have been answered, but 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 costs might be? You know, much those new costs
might be? What I indicated before in terms of our direct costs is the overall cost in the $200,000,000 to $300,000,000 range of which that is a component. I think the tricky part here is with the investigation 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 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's 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, will we have a better idea with this pipeline safety protocol coming up next week or is there any way we get sort of any feeling for this because there's so sort of proposals going on
or? Yes, Paul, this is Chris Johns. I think that the and I can understand the frustration of 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 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
makers 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 really hard to predict what ultimately the outcome will be.
Okay. Thanks a lot.
Next question comes from the line of 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. Think 2010 ended up, I believe, at $21,100,000,000 for the weighted average rate base for last year.
Okay. And what is expected this year?
I don't have an updated forecast for that. That'd be something we probably address at our investor conference.
Okay. Okay. Thank you.
Question from the line of Michael Lapides with Goldman Sachs. Please proceed.
Hey, guys. Ken, on that rate based question, is that California and transmission, California elected electric and gas as well as transmission all blended together?
Yes, it is.
Okay. Thank you.
There are currently no further