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Executives

Christopher P. Johns - Former President and Director

Kent M. Harvey - Chief Financial Officer, Senior Vice President, Treasurer and Senior Vice President of Financial Services - Pacific Gas & Electric Company

Anthony F. Earley - Chairman, Chief Executive Officer and President

Gabriel B. Togneri - Vice President of Investor Relations

Thomas E. Bottorff - Senior Vice President of Regulatory Relations-Pacific Gas & Electric Company

Analysts

Andrew L. Smith - JP Morgan Chase & Co, Research Division

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Paul Patterson - Glenrock Associates

Dan Eggers - Crédit Suisse AG, Research Division

Jonathan P. Arnold - Deutsche Bank AG, Research Division

Andrew Levi - Caris & Company, Inc., Research Division

Greg Gordon - ISI Group Inc., Research Division

Matt Fallon

Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division

Thomas O'Neill

Steven I. Fleishman - BofA Merrill Lynch, Research Division

PG & E (PCG) Q3 2011 Earnings Call November 3, 2011 9:00 AM ET

Operator

Good morning, and welcome to the PG&E Third Quarter Earnings Conference Call. [Operator Instructions] At this time, I would like to introduce your host, Gabe Togneri with PG&E. Thank you and enjoy your conference. You may proceed, Mr. Togneri.

Gabriel B. Togneri

Thank you, Lynn, and good morning, everyone. Thanks for joining us on the call. Along with our earnings release and the supplemental tables including the Reg G reconciliations, we've also provided you this morning with PowerPoint slides. Our remarks today will include forward-looking statements based on the assumptions and expectations reflecting information currently available to management. Some of the important factors that could affect our results are provided on Slide 2. We encourage you to review that, as well as the 10-Q report we'll be filing later today and all of the more fulsome discussion of factors in that. Today's speakers are noted on Slide 3, and other members of the team as usual are here to participate in the Q&A that will follow. And with that, I'll hand it over to Tony.

Anthony F. Earley

Good morning and thanks for joining us. We have a lot of tough news to communicate today, but since this is my first quarterly call at PG&E, I thought it'd be a good idea to take some time to share some initial impressions and my plans. So I'm going to start with Slide 4.

I am totally committed to making Pacific Gas & Electric one of the best operated utilities in the country, and I am certain that we can do that. But in order to succeed, we need to be brutally honest about how we stack up against the best today, then we need to have a culture that celebrates those gaps as a roadmap to future improvement. We know that San Bruno was a tragic event that has made it clear to us that our operations are not where they need to be. In my first 6 weeks with the company, I've spent time meeting with our leaders and assessing whether we have the right organizational structure and the right expertise and experience now on board. So let me start with organizational structure.

Earlier this year, the company split the Gas and Electric businesses into distinct operating units and created Gas and Electric EVP roles, and I think that was a very good move. It's already resulting in better focus and clear accountability for each business. Within those business units, we've done organizational alignment to get better focus on operational excellence. I've also shut down our corporate strategy group that was tasked with looking at industry trends and non-utility investments, again to get clearer focus on utility operations.

So let me move to Slide 5 and talk about the officer team. There have been some key leadership changes at PG&E since San Bruno. In addition to myself, we've added Nick Stavropoulos, an outstanding leader in the Gas business. Nick has been building up his organization including hiring experienced senior staff from companies including TransCanada, Public Service of New Mexico and El Paso Pipeline. We've added Karen Austin, our new CIO from the retail industry, who will accelerate our use of technology to support our operations improvement. We also just announced that we hired a new VP of Communications, Roger Frizzell from American Airlines. Our officer team overall includes a good mix of people with long-term PG&E experience as well as those with impressive industry experience at such companies as Exelon, Entergy, FPL and PP&L, to name just a few. I'm convinced that the team that we now have in place will deliver the results that we're going to need.

We all know that resolving all of the gas pipeline issues will be challenging. As you saw in our press release this morning and as shown on Slide 6, we have determined that we need to spend more on both our gas and electric system to reach our goal of operational excellence. Spending approximately $200 million incremental to our previous plan will have a negative impact on our earnings in 2012, which will continue into 2013. It is our objective, however, to earn our authorized return in 2014. Some of this additional spending will be acceleration of work we've previously planned to complete over a longer period and some will be new work that we've identified in our review of operations. Kent is going to take you through the details of our earnings guidance and Chris will provide more information on the operational areas we're targeting a little bit later on the call.

Work to improve our operations is vital to restoring the confidence and trust of customers and regulators. My personal experience at both LILCO and DTE is that you cannot PR or lobby your way to credibility. There's only one solution and that's to provide consistently better service to customers. Operational excellence and accountability drive customer perceptions. Operational excellence improves regulatory relations. We're going to use ongoing benchmarking to measure our progress and allow us to set meaningful improvement goals for the future.

Given what has happened at the company over the last few years, this strategy we believe is in the best interest of all our stakeholders. We need to provide superior service to our customers because average performance is just not going to be enough. We cannot afford any significant operational issues and we understand that even routine operations are under intense scrutiny, so we have to be better than expected. To execute this strategy, Chris and his team have put together plans that I'll ask Chris to describe now. So Chris?

Christopher P. Johns

Thanks, Tony, and good morning, everyone. First, I'm going to discuss our review of operations and the steps we're taking to improve our operational performance, then I'll bring you up-to-date on the status of our gas pipeline work over the quarter and our related regulatory proceedings. And then finally I'll also describe the developments related to our Hinkley compressor station that led us to increased environmental accrual.

So let me begin with Slide 7. To build on Tony's point, restoring trust and confidence in PG&E is our key focus. There's only one way to get there: by providing safe, reliable electric and gas service. We are fully committed to improving the safety and reliability of our operations. Not all of our operations are where they should be, which is unacceptable to us, our customers and our stakeholders. As Tony said, we are also operating in a world with much more scrutiny. The expectations of our customers, our policymakers and our regulators are higher than they've ever been, and rightly so. Regulations and expectations are changing. This is raising the bar for performance and we are expected to meet that challenge. Over the last year, we've been taking some actions to improve certain aspects of our operations and we've continued to evaluate all of our operations across the company beyond just the gas pipeline business, and we've been incorporating the findings of the CPUC's independent review panel, the NTSB, and other reviews that have been performed. But we still need to do more now in key operational areas to improve our overall performance.

So as you'll see on Slide 8 and as Tony stated, to do this additional work, we will need to expand our resources, which means expending approximately $200 million more than previously planned in 2012 and most likely a similar amount in 2013. The decision to move forward with this work will cause us to under-earn relative to our authorized levels, and Kent will describe the implications to our guidance in just a couple of minutes. But let me first describe the work we'll be doing. The majority of the work as you would expect is in the gas transmission and distribution system. About a third of the additional spending will be dedicated to accelerating work we originally planned to address over a number of years and that we now intend to complete most of it by 2013.

Let me give you a couple of examples of this work on the gas side of the business. We'll be completing our evaluation and the remediation of our gas deal services that are more vulnerable to corrosion, we'll be increasing our right of way clearances, and we'll be increasing our protection or relocating our gas distribution meters to prevent damage. On the electric side of the business, we'll be accelerating the inspection cycle and reinforcement of electric poles, we'll be increasing the physical inspection of areas that are most susceptible to wildfires, and we'll be accelerating our overhead and underground line maintenance work.

The remaining 2/3 of the spending in 2012 will be to elevate our performance and put it on a solid foundation going forward. On the gas side of the business, a couple of examples include work related to increasing our staffing and training for our gas control center, shortening our leak repair and leak recheck interval requirements, and improving our integrity management and class location programs. On the electric side, work will include technology projects primarily targeted at improving our asset investment and management programs. We will also be taking steps to improve our customer service by enhancing support for small and medium business customers and increasing our overall customer communications and education efforts. As we get this work done, we expect to raise the level of performance in each of these areas, and going forward, we'll continue to drive for additional improvements over time.

Now let me move on to gas pipeline matters in Slide 9, starting with an update on the regulatory proceedings. The NTSB issued its final report during the quarter. We've embraced their recommendations, although they were still very difficult to hear. In addition, at the CPUC, there are 2 major regulatory proceedings: the record-keeping investigation and the forward-looking rulemaking for all gas pipeline operators. In the rulemaking proceeding, we've filed our Pipeline Safety Enhancement Plan at the end of August. We proposed to spend $2.2 billion between 2011 and 2014 to modernize and improve our pipeline system. Right now, the rulemaking and investigation are proceeding on generally parallel paths that probably won't be resolved until the middle of 2012 sometime, but we still have important work to do this year to enhance the safety and integration of our -- integrity of our gas system.

We've continued driving our gas pipeline work plan and have successfully met our commitments and key milestones. As planned, we increased our strength testing work in the third quarter, testing more than 46 miles of pipe, and as of September 30, we had tested, verified through records or replaced more than 100 miles of pipe. Last week we experienced our first test failure; that pipe was replaced and successfully retested. By year end, we expect to be right around our aggressive target of 152 miles. This represents an unprecedented level of pressure testing of pipes already in the ground and located in densely populated areas.

Our gas engineering teams have also worked diligently to meet our targets for validating maximum allowable operating pressures for the highest priority pipelines. We met the CPUC's June, July and August targets and are on track to validate more than 1,800 miles of pipe. We anticipate doing a lot more work like this in 2012 as part of the Pipeline Safety Enhancement Plan.

What I just described represents our direct pipeline work. We're also working to address the needs of the San Bruno Community and resolve the third-party claims associated with the accident. We took an additional charge of $96 million for third-party liabilities this quarter. This brings the total accrual to $375 million. The high end of the range, which was previously $400 million, has also been updated and is now $600 million. These changes reflect additional information regarding the nature of the claims and our experience to date in resolving key cases. They also reflect developments in the litigation and regulatory proceedings related to San Bruno.

Finally, but very important, I want to bring you up to date on our environmental remediation efforts related to chromium in Hinkley and that's shown on Slide 10. During the quarter, we took a significant charge of $125 million for environmental-related costs associated with groundwater contamination. As you may be aware, decades ago the company used the chemical hexavalent chromium at our gas compressor station in Hinkley, California. For several years, we've worked with the Regional Water Quality Control Board to develop, test and deploy a variety of methods to clean up the chromium contamination in the groundwater. The next step for us is to build on this extensive cleanup work and to seek approval of a final remediation plan for the site. During the quarter, we submitted our plan to the Water Board proposing a range of options for the ultimate resolution of our liability for the Hinkley site. These remediation costs represent the primary driver for the increased accrual. The accrual also reflects new environmental data about the remediation site, as well as recent orders from the Water Board. It includes estimates for higher potential remediation costs and costs to provide replacement water to certain residences impacted by the plume. We are fully committed to remediating the groundwater in Hinkley and providing bottled water to affected residents, but we have some concerns about the approach the Water Board is taking and we're working with the Board on these issues. We expect more information from the regional and the state water boards in the coming months about the range of our remediation efforts, the resolution of the replacement water issue and potential new standards, which could lead to additional charges in 2012.

As I turn it over to Kent to discuss our financial results, I'll reiterate what Tony said. We know we're sharing some tough news on this call, but we also know this is the right path to take. Demonstrating capability through effective operations is the only way to restore the trust of our customers and all of our stakeholders, and that is exactly what we are doing. And now, I'll turn it over to Kent.

Kent M. Harvey

Thanks, Chris, and good morning. I plan to cover our third quarter results, our outlook for the remainder of 2011 and our guidance for 2012. I'm also going to address our financing needs and the dividends.

So let's start with the quarter, and on Slide 11, you can see that earnings from operations for Q3 were $436 million or $1.08 per diluted common share. On a GAAP basis, earnings were $200 million or $0.50 per share. The difference between the two reflects 2 items impacting comparability, one for the natural gas pipeline matters and one for environmental-related costs at Hinkley. The gas pipeline item totaled $0.40 per share for the quarter, and the environmental-related item totaled $0.18. Chris already described the factors affecting the environmental accrual, but I will spend a moment on the gas pipeline item.

You can see in the table below that the largest component was the pipeline-related costs of $177 million pretax. This includes the strength testing and the pipeline validation work in the field that Chris described, as well as legal and other costs incurred during the quarter. The other component was the additional accrual of $96 million pretax for third-party liability claims. Since the accident, we've now accrued a total of $375 million for third-party liability. There were no insurance recoveries booked during the quarter, and you remember, we only book insurance recoveries once we've resolved the claims with each carrier.

Slide 12 has the quarter-over-quarter comparison for earnings from operations, and the $1.08 for the third quarter represents a $0.06 increase compared to Q3 of last year. And here are the key items. First, we had a $0.10 increase due to higher authorized rate base investment. We also had a number of smaller items totaling $0.03 positive. These increases were partially offset by higher costs for litigation and regulatory matters totaling $0.04 negative, and the primary driver here was an additional accrual for the proposed decision of the Rancho Cordova proceeding. We were also $0.03 negative due to a greater number of shares outstanding.

Based on our results to date and our projections for the rest of the year, we're maintaining our guidance range for 2011 earnings from operations of $3.45 to $3.60 per share, and this is shown at the top of Slide 13. On this slide, you'll see that we're updating our 2011 guidance range for the item impacting comparability for gas pipeline matters to between $0.65 and $1.28 per share, and we're showing the additional item impacting comparability for environmental-related costs at Hinkley. This reflects the third quarter accrual totaling $0.18 per share.

Let me walk you through the various components of the pipeline item in the table below. First, we're not changing our range for the pipeline-related costs. They remain at $350 million to $550 million pre-tax, although I will say, given where we are in the year, I do not expect we'll end up at either extreme of that range. Second, we are updating our 2011 range for third-party liability to reflect the assessment made at the end of Q3 that Chris described. The new range shown here is $155 million to $380 million, and let me explain how you get to that range. You may remember that our original estimate for third-party liability after the accident was $220 million to $400 million and that we accrued the lower end of that range last year. Based on the information we currently have, we've increased that range to between $375 million and $600 million if you deduct the $220 million we booked last year to get our new 2011 range of $155 million to $380 million. We booked $155 million this year. And third, I'll remind you that we don't include any future insurance recoveries in our guidance, so what you see here is the $60 million of recoveries we booked in Q2. We also don't include any future fines or penalties in connection with the pipeline accident.

I'd now like to move on to our guidance for 2012. We've decided to provide 2012 guidance now based on the operational review we've recently conducted which Tony and Chris described. Obviously, we still have some key issues that need to be resolved; in particular, the outcomes of the various gas pipeline proceedings could have a significant effect on our item impacting comparability, our equity needs and our share count. But for purposes of our 2012 guidance, we've assumed that our Pipeline Safety Enhancement Plan is approved as filed, including our proposed cost recovery. 2012 guidance also excludes the impact of any future fines or penalties. Those are important assumptions to highlight upfront.

Let me go through our other assumptions. Let's start with rate base, which is shown on Slide 14. We're assuming an average authorized rate base of about $24.5 billion in 2012, which is up about 5% over 2011, and CWIP of about $1.6 billion. This reflects our General Rate Case, our gas transmission case, the Electric Transmission business and our separately funded projects like SmartMeter, Cornerstone, and then the Photovoltaic Program. You should expect that roughly half of next year's earnings on CWIP will be offset by below-the-line costs such as charitable contributions, advertising and public affairs activities, since we don't recover those costs through rates.

In terms of CapEx, you'll see that we assume $4.6 billion to $4.8 billion of CapEx next year, and this is an increase from our 2011 level, which has been at about $4.2 billion and mainly reflects the incremental CapEx that we expect to be funded by bonus depreciation. Our cost of capital and cap structure will be unchanged in 2012 under the existing mechanism, which is in place through the end of next year. The PUC will be reconsidering these issues for 2013.

On Slide 15, as Chris described, we expect to increase our expenses next year to improve the safety and reliability of our operations. Chris already covered the areas that we're focusing on here. We expect to spend roughly $200 million more than previously planned, about 1/3 for work that would be completed by the end of 2013 and about 2/3 for new ongoing work.

On Slide 16, you can see that based on these assumptions, we're establishing guidance for 2012 earnings from operations of between $3.10 and $3.30 per share, and this obviously represents a significant decline from our 2011 guidance. There are 2 main drivers: First, the higher expense level in order to improve our operations; and second, we expect higher shares outstanding on average next year as compared with this year. These items more than offset the higher earnings associated with year-over-year rate base growth. We expect the average shares outstanding will be higher because the shares issued throughout 2011 will be outstanding for the entire year in 2012, and we also expect to issue additional shares next year. And I'll cover future share issuance in a moment.

Slide 17 summarizes our 2012 guidance. So, in addition to the earnings from operations I described on the first line, we also showed the ranges for the 2 items impacting comparability. The range for the gas pipeline matters item is $0.14 to $0.60 per share. We're also providing a range of $0.00 to $0.14 per share for environmental-related costs at Hinkley. This reflects the potential for additional accruals next year depending on the final remediation plan that's approved, the resolution of the replacement water issue that Chris described, as well as other issues.

In terms of the gas pipeline item, the components are shown in the table before and it's a bit [indiscernible] so I want to walk you through. The first is pipeline-related costs outside the scope of the Pipeline Safety Enhancement Plan. These are costs we do not plan to recover through rates. We estimate them at $100 million to $200 million pretax for the year. What are they? Roughly half is for specified work on our pipeline such as strength testing and validation for post-1970 pipe, as well as some additional in-line inspections. The rest is mainly for costs associated with litigation and regulatory proceedings.

We have not included the Pipeline Safety Enhancement Plan cost in our guidance range for next year's item impacting comparability. The assumption here is that we receive a final decision on our proposed plan during 2012 and that the PUC approves our proposed cost recovery. Until we actually receive the PUC's approval, we won't be able to offset the expenses we incur for the plan with revenues. This will increase the item impacting comparability until we receive a final decision. Once we receive it, the year-to-date revenues would offset the prior expenses in the item impacting comparability. If our plan is approved as filed, we'd expect these to net to 0 for the year.

The second component of the gas pipeline item is for estimated third-party liability, and the range for this component is $0 to $225 million. And this just reflects the difference between the total amount we've accrued to date, $375 million, and the upper end of our estimated range for third-party liability of $600 million.

As has been our practice, we're not including future insurance recoveries in our guidance. We continue to believe that a significant portion of our third-party liability costs will be recovered through insurance, but we'll only book insurance recoveries once we've resolved the claims with each of our carriers. Our 2012 guidance also does not reflect any future fines or penalties.

Now I'll turn to financing and dividends, and that starts on Slide 18. And this shows that year-to-date through September, we've issued roughly $400 million of equity. About half that has been through our internal programs, our 401(k) and DRIP programs, and about half externally through our continuous equity offering or Dribble Program.

Providing a forecast for equity needs is challenging in our current situation, but based on the assumptions and the guidance I've laid out, we would anticipate needing additional equity somewhere in the $600 million range between now and the end of next year. When you compare the equity issuance over these 2 periods that are shown in the table, the key drivers of the increase are higher CapEx next year as well as lower earnings from operations. In addition, the accruals we took in Q3 increased our going-forward equity estimate. Partially offsetting these factors is the lower level of unrecovered pipeline costs expected next year. Again, this estimate assumes our Pipeline Safety Enhancement Plan is approved next year as filed and it excludes the impact of any fines or penalties. The changes in these assumptions will drive additional equity needs in order for us to maintain our capital structure and our credit quality, which is important to us.

In terms of timing, I currently expect that more than half of the additional equity would be issued by the middle of next year. We're looking at $250 million to be issued through our internal programs, the 401(k) and DRIP, and we also have about $100 million of capacity left under our current Dribble Program. For the remaining needs, we'll consider an additional Dribble Program [Audio Gap].

Earlier this year, we announced that given the challenges we were facing, we would not make any changes in our dividend during 2011. I know this was disappointing to investors, especially given our lower-than-average payout, but it was the right thing to do. Currently we're not planning an increase for 2012. Obviously, we still have a lot of issues to resolve, including the outcomes of the PUC's rule making and investigation. After those proceedings are concluded, we'll assess our situation and any other issues that remain and then determine what makes sense. We recognize that dividend growth is important to our investors and we want to be able to provide that growth in the future. But in the meantime, we intend to maintain our current dividend of $1.82 per share. I'm now going to hand it back to Tony.

Anthony F. Earley

Thanks, Kent. So we've talked about a lot on this call, so let me make a run at trying to summarize the key messages. First, our operations are not where they need to be, particularly in light of the intense scrutiny we've experienced after San Bruno. Second, getting them there will require higher expenditures. While it's the right thing to do, it does result in disappointing guidance for 2012. Our spending profile is likely to be similar in 2013 but we are committed to earning our allowed return in 2014. We've outlined the importance of addressing the challenges that we face: resolving our pipeline issues, improving our operational performance, restoring our reputation with customers and regulators. I believe that is the only way to achieve sustainable earnings and dividend growth in our industry, and I can tell you that the whole PG&E team has committed to that sustainable success. So with that, we'll take your questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Daniel Eggers with Credit Suisse.

Dan Eggers - Crédit Suisse AG, Research Division

Tony, I guess the thought was that you're going to face some higher costs to try and get operations up to snuff, but that $200 million, I guess question number one is when you look out to '14 in your near-lot [ph] ROE, are you assuming that you'll be back on course after 2 years of spending your spread up or are you going to have to go to the commission in the next rate case and assume you get squared up that way?

Anthony F. Earley

No, it's too early to really give you details on what that next General Rate Case would look like. I think it's probably a combination of things. There are some things as we said that we're pulling forward, that would be over with, but then in looking at our operations, we'll have to look at going forward what spending is appropriate given the high level of performance that we want to provide.

Dan Eggers - Crédit Suisse AG, Research Division

And then I guess kind of the next question on that vein is that the $200 million of additional cost -- the assumption I guess is that PG&E was a reasonably good operator. As you've gotten in, are you finding structural problems or cultural problems that have kind of led to some of these gaps?

Anthony F. Earley

I think if you -- and I know you read the NTSB report, and that's certainly highlighted in a couple of areas where we need improvement. And we've taken a top-to-bottom look at the company being very self-critical, and I think that's the approach you need to take. And the other point that I'd make is as you go through an event like San Bruno, the level of scrutiny and the level of expectations increases to an even higher level. So to get ourselves back to having the support of our customers and our regulators, we can't just have average performance, we have got to have an outstanding performance, and that's driving some of the additional spending.

Dan Eggers - Crédit Suisse AG, Research Division

I guess Tony, as you envision it from us on the outside, given kind of all the challenges you have, what sort of benchmarks do you guys plan to share with the street so we can try to keep track of the improvements in performance in a way to gauge whether the plan is working and the ability to repair the relationship is in course?

Anthony F. Earley

That's a good question, and obviously, a company this size should have literally hundreds and hundreds of benchmarks you can use. We're still working on what would be good measures to continue to share on an ongoing basis. But we do want to be transparent as we go through this around our performance metrics, but I don't think we're ready yet to say here is exactly what we're going to share.

Dan Eggers - Crédit Suisse AG, Research Division

And Kent, just one last clarification question. The $600 million through end of '12, that'd be $600 million on top of the $400 million this year before any sort of additional equity to fund the fine or something like that?

Kent M. Harvey

That's correct. We've already issued $400 million, and we estimate what we need from today through the end of next year, based on all the assumptions I laid out, we estimate roughly in the $600 million range, and the drivers were on that slide that I covered a little while ago.

Operator

Our next question comes from the line of Greg Gordon with ISI Group.

Greg Gordon - ISI Group Inc., Research Division

Couple questions. The earnings guidance, does it include the expectation that -- I think you've explained what you're doing in terms of this item impacting comparability on pipeline-related costs. You're not including the assumption that your operating costs associated with the August 26 filing are approved, but once they are approved, you'll reverse that. Is that right, Kent?

Kent M. Harvey

Yes. The way to think about it, Greg, I think you've got it right is, if you're in the first quarter and we don't have final approval yet for the Pipeline Safety Enhancement Plan, the expense components obviously we would be showing as an increment to that item impacting comparability. Once we get final approval and if the plan were approved as filed, we would reverse that because we'd be able to show the associated revenues year-to-date when the approval happens.

Greg Gordon - ISI Group Inc., Research Division

Okay. So that item is going to grow as we move through the year if we don't have approval?

Kent M. Harvey

That's correct. And the final approval assuming is what we have proposed would tend to offset the accruals during the year.

Greg Gordon - ISI Group Inc., Research Division

And does your earnings guidance assume that the capital program as filed in the PSEP is impacting rate base and that you're getting recovery on that?

Kent M. Harvey

Yes. It assumes that the commission makes the decision during 2012 and ultimately allows for recovery of those reasonable going-forward costs that are incremental to what we've currently been spending under past standards.

Greg Gordon - ISI Group Inc., Research Division

And it assumes you earn a return on the capital?

Kent M. Harvey

That's correct.

Greg Gordon - ISI Group Inc., Research Division

Okay, great. So just a higher-level question. If I look at the earnings guidance and I look at the $200 million of unrecoverable cost, you're basically telling us that, all things equal, the earnings power of the company would be around $350 million next year, if it were healthy? What is your expectation of sort of the underlying rate base growth profile? And that's off of a rate base growth -- a rate base number that you've also laid out in the presentation that is a number of $24.5 billion. What's your expectation of sort of the level of rate base growth that investors should expect as we move out past 2012?

Kent M. Harvey

Greg, we really haven't provided rate base growth beyond there yet, and I think that gets back to some of the issues that Tony described about thinking through what we're really going to be looking at by the time we get to 2014. So I guess what I'd say is year-over-year this year is in the 5% range, and I just don't know if that's going to be specifically a good indicator of future years at this point or not.

Greg Gordon - ISI Group Inc., Research Division

Okay. Final question. The $1.6 billion in CWIP, the earnings associated with that, should we continue to assume they're offset by unrecoverable expenses?

Kent M. Harvey

Yes. I think my suggestion is that you'd assume that roughly half of those earnings on CWIP would be offset by those costs that are below the line.

Operator

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

Paul Patterson - Glenrock Associates

Boy. When we're looking, I guess -- I guess when do you feel that we'll get back on sort of a more normalized track on operating expenses? And I guess going forward, past the next couple of years, when do think this would become to get more normalized?

Anthony F. Earley

Well, as we said in the presentation, 2012, 2013 will probably have a similar spending profile. Our objective is to be back to earning our allowed return in 2014, which would be a combination of finishing some of the spending and also will have gone through a General Rate Case.

Paul Patterson - Glenrock Associates

Okay. So I mean -- I understand that -- so in other words, you feel that all these expenses that you currently have or what will be going forward after this period in time will be at a level that the commission, everything would be okay with it. Is that the way to think about it?

Anthony F. Earley

Yes. What we're spending now comes under the existing General Rate Case, which means it's spending that we are not going to seek recovery of, and when we file a General Rate Case, we think we'll be able to justify whatever spending levels that we put in that case. And obviously, as you know, those General Rate Cases are subject to discussion with the commission, but yes, we think we're confident that we've got a good plan in place.

Operator

Our next question comes from the line of Hugh Wynne with Sanford Bernstein.

Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division

My first question is for Kent. Your estimate of equity issuance next year apparently excludes fines and penalties. Have you budgeted any equity issuance to cover third-party liability costs that may not be recovered under your insurance policy?

Kent M. Harvey

Hugh, when we do our forecasting, we have forecasted internally the third-party liability issue and then we also forecast insurance recoveries over time, and I think the reality from a cash perspective is that we tend to accrue the third-party liabilities when they are probable. And so it's a going forward, and often, as has been the case, we accrue before we actually incur the cash. So if you look at our cumulative accrual for third-party liability, we talked about that being over $375 million year-to-date. The cash outlay to date is more in the $80 million to $90 million range. So you have to look at both the cash and the accruals, and in the case of the insurance, again we do try to forecast when we think the claims will be resolved. But that's obviously on a lag because a lot of the litigations still has to proceed.

Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division

Are you anticipating that recoveries under your liability insurance will be materially less than the claims you pay out?

Kent M. Harvey

I guess the way we're articulating is that we continue believe that a significant amount of our liability claims will be recovered through insurance.

Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division

Okay. Tony, a question for you on the incremental expenditures, the $200 million of incremental expenditures. Should we -- which way should we be thinking of these -- are these expenditures that, to some extent, will have to continue beyond the next 2 years because they reflect operations, outlays for maintenance or for data monitoring that the company should have incurred and wasn't incurring and therefore there's going to be an ongoing bump up in your cost, or should we think of these as perhaps more productivity enhancing expenses, outlays that you'll make now that are going to make operations not only safer but also more streamlined in the future and therefore will not have that effect of ratcheting up your cost on a going-forward basis?

Anthony F. Earley

I think it will be both, and let me let Chris just address that in a little more detail.

Christopher P. Johns

Yes, this is Chris, and I would agree. Some of it as we said is going to be items that we are accelerating and so those are going to be a 1- to 2-year kind of increase, and then in other areas we are going to be increasing our performance. And you would expect that when you increase your performance that, yes, there may be some costs associated with doing the extra work, but at the same time, we're going to be looking at what best practices are in driving for productivity, driving unit costs to be at lower levels. And so it is a little hard to predict right now where we'll be by 2014, but it will be a combination of doing some of the cost increases to get the performance up to a good level, but at the same time, constantly reevaluating the processes and driving productivity through the organization to put the downward pressure on those costs.

Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division

Okay. So it sounds to me like we should probably assume that not all the $200 million really disappears in 2014 and that there's sort of an ongoing level of higher costs that you'll incur to maintain a higher level of operations performance?

Anthony F. Earley

I think that's probably a good assumption, that there'll be some level that will be in the next General Rate Case request.

Operator

Our next question comes from the line of Andy Levi with Caris and Company.

Andrew Levi - Caris & Company, Inc., Research Division

For the O&M level to kind of use for a base for 2012, can you kind of give us a little guidance on that at the utility level?

Kent M. Harvey

I guess normally, your models I would assume have had estimated O&M for us for next year that would be consistent with us earning our authorized return, putting aside the items impacting comparability. And what we're articulating here is that we see an increment of about $200 million above the levels you would otherwise estimate for us to earn our authorized return.

Andrew Levi - Caris & Company, Inc., Research Division

Okay. But you can't give us a number on that, right? Not on the 2011 kind of the base number?

Kent M. Harvey

No, we're not providing a specific number on a line item on the income statement.

Andrew Levi - Caris & Company, Inc., Research Division

Okay. And then just also to understand, so if you were to incur a fine, whatever that fine is from the state of California on the pipeline issue, that would lead to incremental equity, is that what you're saying?

Kent M. Harvey

Andy, that's correct. For the charges we've been taking for our unrecovered expenses as well as for any future costs like that, we would issue additional equity in order to maintain our capital structure.

Andrew Levi - Caris & Company, Inc., Research Division

Okay. And why was it that you didn't recover any insurance costs in the third quarter? Is it just timing or anything else?

Kent M. Harvey

The insurance process -- our insurance coverage involves a number of carriers that are in a tower, and so we have discussions, frequent discussions we've been having with our insurance providers as we go through the litigation process and are trying to resolve some of the cases. But we do have to continue to advance that process before we resolve claims with a lot of our additional insurance providers, so that's just a process that takes a while.

Operator

Our next question comes from the line of Steve Fleishman with Bank of America.

Steven I. Fleishman - BofA Merrill Lynch, Research Division

Tony, you've still been there a relatively short period of time, so when you've come up with these kind of $200 million expected numbers, how set in stone are these numbers? Did you leave some cushion in them, given that I assume you're still reviewing operations to some degree or is that review totally done?

Anthony F. Earley

No. I mean, we will continue to review operations. I think we're obviously comfortable enough with those numbers to be able to give 2012 guidance. And I think one of our next steps going forward, both in 2012 and 2013, we'll be looking for opportunities to offset those costs through efficiencies, but we're nowhere near being able to say "Well, here's what we think we can offset."

Steven I. Fleishman - BofA Merrill Lynch, Research Division

Okay. And just from a General Rate Case standpoint, your next kind of scheduled filings, both electric and gas are for the 2014 implementation year?

Thomas E. Bottorff

This is Tom Bottorff from Regulatory Relations. Yes, we are on schedule to file our General Rate Case application towards the latter part of next year.

Steven I. Fleishman - BofA Merrill Lynch, Research Division

So that would be implemented essentially beginning of '14?

Thomas E. Bottorff

Yes.

Steven I. Fleishman - BofA Merrill Lynch, Research Division

On that schedule. Okay.

Gabriel B. Togneri

Steve, this is Gabe. And the gas transmission and storage case isn't scheduled until one year later, so that one would be 2015. But that's a much smaller case than the GRC.

Steven I. Fleishman - BofA Merrill Lynch, Research Division

Last question, just -- is there a rough way to say of this $200 million, how it's split between electric, gas and maybe transmission?

Christopher P. Johns

Yes -- this is Chris. I would say the majority of it is gas transmission and gas distribution. It's a smaller part on the electric and the customer side of it, but most of it is on the gas side of the business.

Operator

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

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Kent, real quick just in terms of what's in and what's not in 2012 guidance. I apologize. I know you went over this a little bit after Greg's question. I want to make sure we totally understand. The EPS from operations assumes the plan is approved, the PSEP plan, but also incorporates $200 million of incremental expenses that are above and beyond the plan. Is that correct?

Kent M. Harvey

Let me just quickly walk you through it. And it is complicated so I want to acknowledge that upfront. But we've tried to lay it out as clearly as we can, given just how complex our situation is. If you look on the Slide 17 that we used for guidance, the earnings from operations there excludes those items impacting comparability. So it excludes the gas pipeline stuff and then it includes any potential additional accrual related to the environmental costs at Hinkley. But what is in the earnings from operations is the incremental $200 million of expenditures that we've been talking about. So that is reflected in that $3.10 to $3.30 range. The gas pipeline items have the 3 components that are shown down at the bottom: the direct costs, where we're estimating between $100 million and $200 million, and in that $100 million and $200 million, those are costs that are outside the scope of the Pipeline Safety Enhancement Plan. So we have assumed that the Pipeline Safety Enhancement Plan is approved as filed during this year and therefore would not, by the end of the year, have an impact on that item impacting comparability. And then we talked about the third-party liability claim guidance just takes you up to the maximum in the range, the upper end of the range that we described is the low guidance range here.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Okay. Because you're pulling -- and Tony, this may be more of a regulatory question. Because you're pulling forward a lot of the work that you would had originally laid out in the Pipeline Safety Enhancement Program, do you have to go back and refile that? Do you have to file an amendment? Does the OIR process have to almost, not start over again but get a little bit of a restart?

Anthony F. Earley

No, let me let Chris deal with that.

Christopher P. Johns

Michael, we're not -- the work that we're talking about in the $200 million is not work that was included in the Pipeline Safety Enhancement Plan. This is other ongoing work. So let me just give you a couple of examples. So we're accelerating some of our leak repair process -- cycle process, so it's something we would normally do over a 15- to 18-month period, we're now going to do over a 12-month period of time. Or we had programs on the distribution side of the business that we had to have done by 2016, we're now going to do by 2013. So most of the stuff in the $200 million that we're talking about on the gas side, which is the majority is on the distribution piece, whereas the plan that we filed with the commission is on the transmission side of the business. And so, although there's some of it on transmission, we're not accelerating anything related to the filing that we've made, and so that's still all items that would be included as on schedule.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Got it. Okay. Last, Tony, when you think about organizationally, you've made a lot of changes and there were changes underway before you came. What's left from an organizational structure standpoint and from a process standpoint that you see at PG&E in your first 6 weeks there that are dramatically different than what you've experienced elsewhere or that what you would prefer to see at PG&E in the future?

Anthony F. Earley

Well, a lot of the changes that we've made -- I was very pleased when I got here, things were happening and happening very quickly. I think the biggest organizational change was splitting gas and electric. Those of us who have been at combination companies, and this is my third, understand that you need to have that singular focus on each line of business. Actually as the brand newly minted President of Long Island Lighting Company in 1989, I thought it would be a great efficiency move to try and combine the 2 businesses. I found out very quickly that, that wasn't such a good idea. And I think most people will tell you that getting that singular focus from a very senior person on a line of business means that you get the right resourcing. So, I mean, that was one of the biggest things. There are obviously always small tweaks to organizations, but I think from both a structure and a personnel standpoint, I am now very comfortable that we've got the right elements in place.

Operator

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

Jonathan P. Arnold - Deutsche Bank AG, Research Division

Quick question on -- so the $200 million -- sorry to come back to this that we're discussing is basically an O&M type of number. Is there an element of capital spending that's also going on here that's sort of embedded in that CapEx forecast that's also part of this accelerated plan, or am I not thinking about that right?

Kent M. Harvey

Jonathan, this is Kent. We do have a higher capital in 2012 as compared to 2011, and that's largely been accommodated by the bonus depreciation treatment where, as you know, we have the benefits of bonus depreciation and the commission has set up a memo account for us to use to do [ph] incremental CapEx. When you look at the increase from '11 to '12, there is a significant amount of that that is on the gas side, including gas distribution. So we are ramping up our expenditures, which will tend to also improve operations. They're just not out of the norm because we do have the bonus depreciation situation in 2012 .

Jonathan P. Arnold - Deutsche Bank AG, Research Division

Okay. So from a rate base standpoint, it sort of maybe nets out?

Kent M. Harvey

That's correct. Yes, you won't see the full impact on rate base of the higher CapEx because you also have the increase in deferred taxes from bonus depreciation and those largely offset one another.

Jonathan P. Arnold - Deutsche Bank AG, Research Division

Okay. And if I may, just send a little bit more into the types of things that you're doing on the gas business, and there was a round of enhanced accelerated spending on gas distribution 2 or 3 years ago, what's -- what are you doing now that you weren't doing then?

Christopher P. Johns

Well, the things that we did a couple of years ago is that we basically just resurveyed. We accelerated a 5-year program into about 2 1/2 years. And so at this point, we're taking similar type of actions but just different from that. So we've got a meter protection program so for the safety of meters putting -- making sure that there's protection around -- those around the homes. That was a program that we were originally going to complete by 2016, we're now going to finish that by the end of 2013. We've got some steel services, which you've heard a lot a lot about, maybe the Adelaide pipe, but there's also other types of services, cast iron and steel services that we've had programs on, and we're accelerating the completion of those. So it's several of those kinds of things. And then when you talk about some of the previous questions, there's other things that were related to the findings in the NTSB report. So for instance, there was a lot of focus on our control room, and so there is an instance where we're going to hire more folks to be involved in that program, we're going to have training costs that we're going to have to do. And so those are types of costs that will be incremental and will stay there. We will do some enhancements of scada controls and monitoring so that we'll get some efficiencies out of that, but those are some examples of the costs that we're going to be incurring.

Jonathan P. Arnold - Deutsche Bank AG, Research Division

Thanks, Chris. And if I can just on -- more on the regulatory strategy front, obviously you have these -- I think there was a schedule just came out in the last couple of days on the pipeline case. Are we looking at sort of a midyear type of -- into 2012 before we get some certainty on these? Or Tony, do you see any opportunities to push for a faster resolution or try and get these cases wrapped up kind of together rather than separately or any comments there?

Anthony F. Earley

Well, John and we certainly would like to get them wrapped up and behind us as soon as we can, but given the reality of that schedule that was just announced, I think your midyear number is a good time frame.

Jonathan P. Arnold - Deutsche Bank AG, Research Division

And then as for having that happen sort of as a pair rather than separately, is there any scope for that?

Anthony F. Earley

Let me let Tom discuss that.

Thomas E. Bottorff

This is Tom Bottorff again. Now these proceedings are pretty much on separate tracks; the rule making to look at what cost recovery is appropriate for improvements in our transmission program, that's on one track. And an investigation called the records OII, that's pretty much on a separate track, and just this week the commission issued proposed schedules for both proceedings. So you mentioned the rule making which Tony just affirmed is scheduled for a decision probably in the summer of this year. The records OII, that schedule suggests a final ruling in that proceeding probably won't occur until the latter part of 2012.

Operator

Our next question comes from the line of Andy Smith with JPMorgan.

Andrew L. Smith - JP Morgan Chase & Co, Research Division

Question for you, maybe shifting a little bit to the operational side and the testing side. You guys had one of your large diameter pipelines fail in one of the pressure tests a couple weeks ago. I wonder if you guys can just give us an update there. Has there been any kind of root cause analysis yet? Essentially I think Nick was quoted in the media as saying that where it failed was one of the highest-quality wells in the pipe. I just kind of want to understand with how you guys were thinking about that and if that was impacting your testing strategy going forward.

Christopher P. Johns

This is Chris. It's not changing our testing strategy. I mean, basically, this was the pipe that we want to run it up at a very high pressure, and so we had to spike it up there when we do it at about 150% of what we anticipate running it at, and it did have a seam weld that failed. We removed that. We're doing testing on it to get further into what the root cause was, but we replaced it and moved forward on it. Given the amount of testing that we've done, we don't know whether -- we don't ever expect any of these things to occur but we will go and we've sent it away for analysis to make sure that we can learn from it, but we don't have that analysis done yet.

Andrew L. Smith - JP Morgan Chase & Co, Research Division

Okay. And you guys have talked about the sort of a permitting issue when you do your testing, being sort of extensive. This rupture was in a rural area, it sounds like it was in a field somewhere. Do you think this complicates permitting going forward when you test maybe in more urban areas, or what's your sense there?

Christopher P. Johns

I mean, all of our testing actually is in what we term highly populated areas, so in this instance it was still a pretty relatively populated area other than the break occurred out in the farmland-type area. But we're -- as we said, we're over 100 miles out of the 150 that we had planned to do and we're on schedule still with the permitting that's associated with those, so I don't anticipate by this event that we're going -- that that's going to change.

Operator

Our next question comes from the line of Matt Fallon with Talon Capital.

Matt Fallon

Just wondering, on Slide 17, to hit the high end of your guidance, the $3.30 number, does that assume that you only incur $100 million out of the $200 million that you've been discussing for incremental expenses, or does it assume that you recover $100 million out of that $200 million?

Kent M. Harvey

This is Kent. We don't make different assumptions for the high or low. We have an overall scenario with assumptions that we provide for you and then we have a range around it.

Matt Fallon

Okay. So I guess the guidance, the $3.10 to $3.30 does assume that you eat the $200 million incremental [ph] cost, is that correct?

Kent M. Harvey

That is correct.

Gabriel B. Togneri

This is Gabe. Let me break in at this point. If we have one more question, we'll go ahead and take that, but we are on the hour right now and so let's see if there's one more question.

Operator

Your next question comes from the line of Tom O'Neill with Green Arrow.

Thomas O'Neill

I just wanted to ask, I guess just a broader question, just the amount sort of being foregone by shareholders now is starting to approach a pretty good chunk of the rate base at the time the San Bruno explosion occurred. Just kind of curious if you can take us through the thoughts that you went through and why the scenario of either sell it or ring-fence it isn't viable?

Kent M. Harvey

This is Kent, Tom. The reality is our gas business is very much -- on the pipeline system is very much integrated with our distribution system. They're operationally not totally separate nor separable. And yes, we have incurred a lot of costs since the accident obviously, and we're working through all those issues. But from our perspective, our intent is to operate the gas business well and successfully and safely, and it's not to sell the business.

Anthony F. Earley

Okay. I want to thank all of you for joining us this morning. Thanks for your questions, and we look forward to seeing many of you at the EEI next week. Thanks.

Operator

Ladies and gentlemen, thank you for attending the PG&E Third Quarter Earnings Conference Call. This now concludes the conference. Enjoy the rest of your day.

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