PG&E Corp (PCG) 2011 Q4 法說會逐字稿

Good morning, and welcome to the PG&E Corporation fourth-quarter earnings conference call.

Just to let you know, all lines will be muted through the presentation portions of the call, with an opportunity for questions and answers at the end.

At this time, I would like to introduce your host, Mr.

Gabe Togneri.

Thank you.

Have a good conference.

You may proceed, Mr.

Togneri.

Good morning, everyone.

Let me provide the usual upfront remarks.

Our comments today will include forward-looking statements based on assumptions and expectations reflecting information currently available to management.

Some of the important factors that could affect our results are described at the front of today's slides.

We also encourage you to review the more fulsome discussion of risk factors that appear in our 2011 annual report that will be filed as an exhibit to the Form 10-K with the SEC later today.

This morning's speakers are Tony Earley, Chris Johns, Nick Stavropoulos and Kent Harvey.

Other members of the team are also here to participate in the Q&A.

And with that, I will hand it over to Tony.

Thank you, Gabe, and thank you all for listening in today.

Since this is only my second quarterly earnings call, I think I am still enough of a newcomer to share some of my observations of the Company before we get to the heart of our discussion this morning.

At our last earnings call, I made several points about what we had done to start to transform PG&E.

We had hired a lot of top-tier talent to supplement the strong core of PG&E veterans that we have.

We made organizational changes that establish clear lines of accountability for our gas and electric businesses.

We put a strong emphasis on operational excellence.

And we made a commitment of resources to turn the business around and ultimately to make our operations the safest in the country.

With the benefits of a few more months on the job, let me add a couple more observations.

Our team understands that public safety is our highest priority, and we are now rolling out technologies to get us there.

They understand that the focus is on back to basics, that we have to focus on benchmarking and to put in place a continuous improvement program.

Most of all, the team understands that we have to deliver.

We know the areas we need to improve on, and we've got a solid foundation from which we can execute.

And that is significant, because it means that in contrast to where we were just seven or eight months ago, we now have a very real opportunity in 2012 first, to truly tackle and resolve our gas issues; second, focus on repositioning PG&E for long-term success; and third, rebuild relationships with key stakeholders.

And that is exactly what our executive team is focused on.

So let me start with the first point, the gas issues.

The new gas organization we put in place last year has delivered on our key commitments and made impressive progress in 2011.

Chris and Nick will give you the update on the details in just a couple of minutes.

What you will hear is that we've still got an extremely demanding amount of work ahead in 2012.

Much of this falls under our Pipeline Safety Enhancement Plan.

It is work that is critical to meeting the new pipeline safety standards being adopted by the CPUC and in Congress.

It is also essential to resolving the San Bruno issues, and rebuilding public trust and confidence in the Company.

But at the same time, it is important to distinguish between the work that was necessary to close the gaps in our past performance and work that is newly required going forward.

Our Pipeline Safety Enhancement Plan is largely new work for a new world, where the CPUC is setting future safety standards at a higher level than ever before.

With minor exceptions, it is not all work to meet yesterday's standards, as some have claimed.

To avoid confusion, we have already asked the CPUC to separate the review of the appropriateness of the plan over the issue of who should pay for the plan.

You see in our press release this morning that although we are maintaining our guidance from earnings from operations, we've updated our outlook for our 2012 pipeline costs.

The update reflects our current understanding of our costs, based on the experience that we gained in the field last year.

We've also made some conservative assumptions about the timing of the CPUC's ruling on our safety plan.

Let me underscore that we are going to continue to work hard to accelerate a decision on a safety plan and to resolve all of the gas-related proceedings at the Commission.

Reaching as much clarity and closure as we can on the regulatory and legal fronts, and doing so as soon as we can is a top priority for our team, and we know it is a top priority for our investors as well.

Shareholders have stepped up and are bearing substantial cost to address past issues, and it's important that regulators recognize this when it comes time to make a decision on costs for work going forward, and we will urge them to take that into account.

Let me turn briefly to positioning the Company for long-term success.

Success for us is delivering overall results for customers that are in the first quartile.

The key is honestly assessing our business, benchmarking our performance and then acting to close any gaps that we find.

We are going to ingrain this into our operations and our culture.

Focusing on operational excellence is the single best way to rebuild our relationships with customers, regulators, and, we believe, investors.

As you've heard me say before, based on my past experience in similar situations, the only way to convince customers that you are a different company is to prove it by listening to them and then delivering great service, and our entire executive team understands this.

None of us expects to get there overnight, but we've set a high bar, and we will make significant progress in 2012.

So with that, I will turn to Chris and then Nick to take you through our operational progress in 2011 and our plans for the coming year.

Chris.

Thanks, Tony.

Today, I am going to summarize the significant work that we completed in 2011 to help resolve the gas pipeline issues, and I'll touch on the work we are doing to position the broader company for success.

I'll also discuss some of the regulatory developments over the last couple of months.

Let me start with the gas work in 2011.

We accomplished a remarkable amount of work this past year to improve the safety of our gas pipeline system.

To give you just a couple of examples, by the end of January, we had validated the maximum allowable operating pressures, or what we refer to as MAOP, for all of the more than 2,000 miles of transmission pipeline in high-consequence areas.

And along the way, we met every one of our commitments with our regulators.

In the process, we conducted a records validation effort more detailed and comprehensive than anything done before anywhere.

We also completed an unprecedented amount of pressure testing, validating the safety of over 160 miles of gas transmission pipe.

This was technically difficult and highly complex work on in-service pipes in densely populated areas.

As Nick will discuss later, we will be doing a similar amount of work this year to further validate and enhance the safety of our system.

Now, gas operations employees were not the only ones working hard to improve the safety and reliability of our operations last year.

We made a number of safety enhancements to our electric system, focusing on reducing the risk from outages and reducing the number of and the impact from equipment failures.

At the same time, we had another strong year in electric reliability, where we had our second consecutive year with a new low of outage frequency.

In the area of renewables, 19.3% of the electric power we delivered in 2011 came from renewable resources, putting us on track to meet the interim benchmarks as we move towards California's 33% goal by 2020.

This is in addition to the 40% of clean energy sources from our vast hydroelectric system and our nuclear facility.

Speaking of which, we had another very successful year of nuclear operations at Diablo Canyon, including an industry-leading safety performance during our refueling outage.

Finally, we installed 1.5 million SmartMeters in 2011, bringing our total to 8.9 million out of the planned 9.7 million.

And we are utilizing those meters and the capabilities to reduce our outage times.

As we look into 2012, we will continue to drive our safety performance improvement in all areas of the Company.

And Nick's going to discuss the gas plans in just the few minutes, but in the electric operations, we will be doing more reinforcement and inspection work on poles and increasing our overhead and underground line maintenance work in an effort to identify and resolve potential issues before they disrupt our customers or cause unsafe situations.

Throughout the business, we will continue to work on improving our processes and using technology to achieve our safety and reliability objectives.

Finally, I would like to discuss regulatory developments which affect our operational outlook and plans.

As you know, the CPUC initiated two new investigations since our last earnings call.

So we are now working through three gas-related investigations as well as the rulemaking proceeding.

You may recall that the original investigation was initiated in early 2011, focused mainly on our records management.

Then in November, the CPUC initiated the class location investigation to review whether we operated our pipeline system at pressures consistent with current class designations.

We've provided our responses in that proceeding, identifying our errors and properly designating class locations and adjusting operating pressures accordingly.

The most recent investigation, the gas pipeline investigation, covers all areas of our pipeline operations.

It takes into account a report by the Safety Division on the Company's gas pipeline operations and practices, which the report attempts to broadly connect with the San Bruno pipeline rupture.

This is the most comprehensive review of operations by the CPUC leading to a penalty proceeding.

In addition to these investigations, the CPUC in December gave the staff new citation authority in their oversight of gas companies.

Through that new authority, Safety Division staff issued a citation for about $17 million for our self-report of some maps missing from our distribution leak survey schedule, which our team identified and then promptly corrected.

We believe this fine is excessive under the circumstances and we have appealed the citation.

However, there are no precedents to rely on here, so we can't predict the final outcome.

Given all of these recent developments, and considering the CPUC's wide discretion in these matters, the magnitude of the San Bruno event, and developments such as the citation issued by the Safety Division, we've taken a charge for $200 million.

This is an estimate, and it does require a lot of judgment.

But we believe this represents the low end of the range of expected fines and penalties associated with the various gas matters.

Meanwhile, in the rulemaking proceeding, there has been no action or progress on our request for a memo account, and the procedural schedule beyond the March hearings remains unclear.

We previously assumed that we would be able to recover the costs for work we do related to the Pipeline Safety Enhancement Plan in 2012 to comply with the new standards.

But that is now much less likely before the rulemaking proceeding is resolved.

To be conservative for guidance purposes, we now assume resolution will not occur until the end of this year.

This means that costs incurred during 2012 related to the safety plan and prior to a final CPUC order will fall to the bottom line.

This obviously has implications for our guidance, which Kent will discuss in just a few minutes.

But before we go to Kent, Nick is going to provide more detail about our gas safety plans in 2012.

Nick?

Thanks, Chris.

As Chris told you, we've completed a lot of gas work this last year, but we've also been building a strong team of experts from both within the Company and from industry-leading firms across the country.

As we go forward, we will be making additional progress in gas operations, including improving our integrity management program, our gas distribution practices and the use of technology, all designed to enhance public safety.

We know a lot more about our gas pipeline system than we did a year ago, and we've also uncovered new challenges even during this past quarter.

Based upon all of our experiences last year, we've adjusted our operational plans and our cost expectations for this year.

In terms of the scope of work for this year, we plan on pressure testing or verifying records for 185 miles of transmission pipe, replacing about 40 miles and upgrading 78 miles to enable in-line inspections on those segments.

Also, by early 2013, we will complete the MAOP validation for all remaining transmission pipelines in the system, more than 4,000 additional miles.

We now expect our cost for the pipeline-related work in 2012 to be about $120 million higher than we had previously estimated.

The main driver is the cost for the hydrostatic pressure testing program.

As a reminder, we filed our Pipeline Safety Enhancement Plan last summer, including estimated costs which were based upon our limited experience up to that point.

We completed the majority of our 2011 pressure testing since that time, which impacted our cost expectations for this year.

Based upon what we experienced last year in the pressure testing program, we expect to continue to incur a cost per mile much higher than what you might see from some of our industry peers.

There are a couple of reasons for this.

First, industry average costs for pressure testing are generally based upon long-line pipe of uniform size with minimal population or customer impacts.

We, on the other hand, need to conduct tests on shorter segments of older pipes, often in densely populated areas.

And second, we face challenges in local permitting and environmental activities like water disposal, and we expect these to continue as we focus our program on more pipelines in the San Francisco Bay area this year.

So while additional lead time allows us to bid and contract for these projects more strategically, which will lower these costs compared to 2011, we still expect our pressure testing costs to be substantially more than the industry average.

Although the pressure testing unit costs are by far the biggest driver of our higher estimates this year, we will also need to complete work on some pipelines that we had not originally planned to address in 2012.

This carryover work will also increase our pipeline expenses.

The combination of all the work I've described and our ongoing performance improvement efforts should bring us greater certainty and higher performance in our gas business going forward.

Now I will turn things over to Kent.

Good morning.

I have a fair amount to cover, so I would like to provide the big picture, before I go through all the details.

And I think there are five key takeaways.

First, we took a $200 million accrual in Q4 for potential penalties associated with all the gas matters.

Second, our other Q4 results were in line with guidance.

Third, we are maintaining our 2012 guidance for earnings from operations at $3.10 to $3.30 per share.

Fourth, we are modifying our 2012 guidance for pipeline-related costs.

And fifth, we are increasing our estimate of 2012 equity needs.

I'll explain each of these as I go through my remarks.

I'm going to start with our Q4 results, which are summarized on slide 6.

Here, you can see that earnings from operations for Q4 were $366 million or $0.89 per share, and earnings from operations for the year totaled $3.58 per share.

GAAP earnings for the quarter were $83 million or $0.20 per share.

The difference between Q4 earnings from operations and GAAP earnings is the item impacting comparability for natural gas matters, and the details of that are shown in the table at the bottom of the slide.

First is the pipeline-related costs, which totaled $180 million pre-tax during the quarter, and this includes the strength testing and the pipeline validation work that Chris and Nick talked about, as well as our legal and other costs that we incurred during the quarter.

For the year, this totaled $483 million pre-tax and was in line with our guidance.

Below that, you see the $200 million accrual we took in Q4 for potential penalties stemming from the various gas matters.

As you know, this was an item we had not provided guidance on.

Chris described the regulatory developments that occurred since our last call and some of the factors we considered in determining the amount of the accrual, which clearly involved a lot of judgment.

Obviously, we will continue to assess the accrual in future quarters until the issues are resolved.

Next, you can see that there were no additional accruals during the quarter for third-party liabilities.

Prior to Q4, we had accrued a cumulative $375 million for third-party liabilities, including $155 million in 2011, which you see on the right.

And finally, you can see that we booked additional insurance recoveries of $39 million related to third-party claims during Q4.

That brings us to $99 million of insurance recoveries since the accident.

And we will continue to wait until we've resolved claims with each carrier before booking additional insurance recoveries.

Slide 7 has the quarter-over-quarter comparison for earnings from operations.

The $0.89 earned in the fourth quarter, which is shown on the far right, represents a $0.19 increase compared to Q4 of 2010.

You see that [$0.10] (corrected by company after the call) is due to higher authorized rate-based investment, and then we also incurred costs for two items in Q4 of 2010 that we did not have in Q4 of 2011, $0.06 for a nuclear refueling outage and $0.05 related to the SmartMeter program.

Litigation and regulatory matters also was $0.04 favorable compared to Q4 2010, in part because the prior period included an additional initial accrual for the Rancho Cordova accident.

These increases were partly offset by higher shares outstanding, which had a $0.03 impact, and miscellaneous items totaling about $0.04 negative, including some employee-related costs such as severance and workers' comp.

That completes my summary of our 2011 results.

So I'm now going to move on to our outlook for 2012.

On slide 8, you can see that our guidance for 2012 earnings from operations remains at $3.10 to $3.30 per share.

As I will cover in a moment, we do expect additional equity issuance this year, which will result in some dilution.

However, notwithstanding that, we are maintaining our 2012 guidance for EPS from operations at $3.10 to $3.30 per share.

I will remind you also that on last quarter's call, we provided some of the key assumptions underlying our 2012 guidance, including authorized rate base, CapEx spending levels, incremental expenses we expect to incur and authorized ROE and cap structure.

And that info is again included on a slide in the appendix.

Back to slide 8, there also is no change in our 2012 guidance related to our item impacting comparability for environmental related costs.

This is in connection with chromium cleanup and mitigation at Hinkley.

However, we are updating our guidance for the item impacting comparability for natural gas matters.

And if you turn to slide 9, I will walk you through the changes.

Starting on the left-hand side of the slide, you'll remember that our 2012 gas pipeline related work includes the work we proposed in our Pipeline Safety Enhancement Plan, which was originally estimated to cost about $230 million, as well as work that fell outside the PSEP, which we estimated would cost between $100 million and $200 million.

The non-PSEP costs included work on post-1970 pipe, as well as litigation and other costs.

Previously, the pipeline safety enhancement plan work was excluded from our 2012 guidance for the item impacting comparability because we assumed approval of the PSEP as filed.

So as you can see at the bottom on the left, our item impacting comparability included only the non-PSEP work, which, as you know, we weren't seeking recovery of.

At the upper right side of the slide, you can see the updated cost estimate for our 2012 pipeline work, which has increased by about $120 million for the reasons Nick described.

Remember, the original PSEP cost estimates were done last summer prior to a lot of our experience in the field.

Our estimate now reflects that experience.

In addition, our outlook for the PSEP recovery has also changed.

Since our last call we haven't seen progress in approving a memo account for costs we incur pending a final decision, and the procedural schedule for a final decision is still unclear beyond hearings scheduled in March.

We've decided to conservatively assume that the PSEP is not resolved by the Commission until the end of this year.

Therefore, we are now including our PSEP and non-PSEP costs in our 2012 guidance for the item impacting comparability.

The updated guidance range for these costs is $450 million to $550 million.

On slide 10, you can see a summary of our current 2012 guidance.

As I mentioned before, there is no change in guidance for EPS from operations or for our environmental related costs.

The natural gas matters item is broken out in the table below into its components, including the pipeline related costs I just described.

The range for third-party liability claims remains unchanged at $0 to $225 million.

This range reflects the difference between the amount we've accrued to date, $375 million, and the upper end of our estimate for third-party liability, which is $600 million.

As has been our practice, we are not providing guidance for additional penalties beyond what we've already accrued or for future insurance recoveries.

I'm going to finish with an update on our equity issuance in 2011 and our plans for 2012, and that is on slide 11.

On our last call, we estimated that based on guidance assumptions at the time, we expected to issue roughly $600 million of equity starting in the fourth quarter of 2011 through the end of 2012, and you can see that on the left.

Next to that, you can see we actually issued $276 million of equity in Q4.

Of course, our guidance now assumes higher unrecovered costs for our gas pipeline related work in 2012, and in Q4 we took the $200 million accrual for gas-related penalties.

Both of these factors have contributed to an expected increase in our 2012 equity issuance of about $300 million.

As a result, we expect our 2012 equity needs to be roughly in the $600 million range, based on our current assumptions.

Obviously, our actual issuance during the year is going to depend on the resolution of the gas matters, as well as other factors.

We'd expect to issue between $150 million and $250 million through our internal programs, the 401(k) and DRIPP, with the balance coming from external issuance.

Our existing dribble program has about $300 million of remaining capacity, and we will consider another dribble program as well as other alternatives to address any remaining needs during the year.

That completes our prepared remarks for this morning's call and so we will go ahead now and open up the lines for your questions.

(Operator Instructions) Dan Eggers, Credit Suisse.

Good morning.

Kent, I just kind of following up on where you finished off your conversation, with the $200 million fine accrual in your numbers in the fourth quarter.

What could cause that number to change up or down other than some sort of definitive agreement or some sort of fine out of the Commission, where that could move over the course of the year?

Dan, the $200 million that we talked about obviously involved a lot of judgment.

And every quarter, we will continue to monitor the overall situation and all the factors that Chris described.

And we need to be confident at the end of each quarter that our accrual accurately represents the lower end of a reasonable range.

So then you would adjust -- if that number were to move up, then the equity number would go up in step with that.

Is that the right way to think about kind of the one-for-one as you accrue against an equity need?

Yes.

The only thing I would say maybe to just refine on that a little bit is in the case of our accrual that we took in the fourth quarter, obviously, that is a non-cash accrual at this point.

And depending upon the resolution of the gas matters, at some point, it will become a cash item.

While it is a non-cash accrual, is not a 100% you fund with equity, because obviously you are raising cash which otherwise you don't need at this point when you issue the equity.

So in some ways you end up initially raising roughly half of what you need and displacing debt issuance that you otherwise would have needed.

Ultimately, when you pay a cash amount for the item, then we would raise the remaining equity and a little bit of debt to offset what you displaced initially, and it becomes one-for-one eventually.

Okay.

Tony, I know you've spent a lot of time trying to focus on the benchmarking work.

Can you just kind of talk to us a little bit, now that you have some metrics in place where you see the businesses ranking out against your benchmarks today, and then what kind of deliverables you've promised or committed to the Board over the '12 and '13 timeframe to get improvement up to kind of meet the goals you want to have?

Sure, I'd be happy to.

I think what the benchmarking has told us, that there are some areas that we have made some real progress.

As Chris mentioned, some of our reliability numbers on the electric system, we've seen some tremendous improvements.

We've also seen some very nice improvements in things like OSHA recordables on safety.

Although we still have some issues we've got to work on in terms of serious injuries and fatalities at the Company, and we've committed to our Board to move those along.

Clearly, on some of the perceptual benchmarking -- so our customer satisfaction numbers, which combines not only our operational performance, but also the perception of the Company in the marketplace -- those continue to reside squarely in third and fourth quartile.

And to deal with those, you've got to do a combination of improving the service and also improving the credibility of the Company in the marketplace.

That is why some of the work that Nick and his team has done this past year on the hydro testing and the MAOP, we're starting to get some recognition.

And we really have committed to having the safest gas system, and I think eventually people will start to realize it is a very real commitment that we are delivering on.

So I would say while there are some areas we've made some real progress, we continue -- on some of our operational areas that affect our customer satisfaction numbers and the like, we are still average to below average.

And then what is your commitment to the Board as far as making improvements over the course of '12 or '13?

Are there numbers we should be looking at to gauge success?

Our long-term target is to have everything in the first quartile.

There are some things, like safety, we want to be top decile.

My commitment to the Board is we will show significant progress in 2012.

Okay, thank you.

Greg Gordon, ISI Group.

Thanks.

Good morning.

Tony, I just want to go back to your comments from the beginning of the call.

I just want to be clear in my understanding that you feel very strongly that the Commission, from a legal precedent perspective, needs to differentiate prudently incurred costs associated with new mandates and allow their recovery as it compares to the cost that you've already incurred and will incur in 2012 on sort of catching up with old mandates.

Is that a fair regurgitation of your statement?

That is absolutely fair.

And as I said, there was a lot of confusion, because in the proceeding around our Pipeline Safety Enhancement Plan, there seemed to be more discussion from some of the parties around the issue of who pays rather than whether the scope of the plan is the right scope and that we are working on the right things to make this the safest system that we can make it.

So we did file a request to separate those two issues.

We'll have to see what the Commission does with it, but we are making it very clear you do have to separate those two issues.

Okay.

When I look at slide 9 of your presentation, which goes through the increase in the costs, your non-PSEP cost estimate previously was $100 million to $200 million.

Is the full $120 million increase associated with non-PSEP related costs?

This is Kent.

I would say the majority of that amount is associated with non-PSEP costs.

If you think about it, in the PSEP, we had originally proposed work on pipe that was from 1961 to 1970, that timeframe, and we have since agreed that should be outside the scope of the PSEP.

So while the cost of the hydrostatic testing both in and outside the program has gone up, the increase within the program is somewhat mitigated by the fact that we've reduced some scope within the program and moved it outside.

So most of the overall impact will be on the non-PSEP side.

Okay, so basically, the underlying tenet here is that PSEP costs, to the extent they are deemed to be in line with new regulation, should be recoverable; non-PSEP costs are on the shareholders?

That's correct.

Great.

One more question on that line.

In reading the TURN and the DRA testimony, they were very critical of a lot of things, frankly, but they were very critical of the cost estimates for doing certain types of work, including hydrostatic testing.

And they cited their experts indicating they thought you could do it for less.

And here you are increasing the estimate of how much it is going to cost.

Can you speak to why there is such a wide difference of opinion on what the right cost is to complete this work?

Let me start off and then I will turn it over to Nick to get into the detail.

Having built pipelines like the Millennium Pipeline, Iroquois Pipeline, when you go in and do hydrostatic testing on a brand-new pipeline, you've got the pipe laying there in the trench, you know where you are going to do the hydrostatic testing in advance.

It is all laid out.

And it is a relatively simple process.

We are doing hydrostatic testing on pipe that has been in the ground 50, 60 years that neighborhoods have grown up around, streets have been paved over.

It is a major project.

The other issue that we discovered was when you put a brand-new pipe in the ground, you fill it with water, you pressure-test it, the water comes out clean.

When you put water in a pipe that has been around for 50 or 60 years, you've got residual hydrocarbons, you've got corrosion products in there, and we've had to then spend a huge amount of money treating the water coming out of the pipe.

So Nick and his team have been working very hard to simplify the process, but, Nick, there still is a lot of challenge out there.

Tony, thank you.

I think it is fair to say the work that we did this past year and that we are going to do in 2012 regarding hydrostatic testing is probably the most complex hydrostatic testing program anywhere in the United States.

And as Tony alluded, that these are shorter segments of older pipelines, very difficult working conditions to be able to stage the equipment at the point where you need to begin, and then stage additional equipment at the end of the test.

The environmental requirements here in California are, appropriately, the most rigorous in the country, so those standards that we are adhering to here are the highest bar, no doubt, and drive a lot of these costs.

And the majority of the costs that we incurred that were unanticipated really relate to handling the water in the hydro test program, where we need to, in many cases, before we began our hydro test, flush these lines to make sure that the water in the pipe when we do the hydro test, the actual test itself, is up to drinking water standards.

So that has required us to do a lot of water-handling, a lot of water treatment, a lot of water disposal, way over and above what would be required, as Tony indicated, in a new pipeline.

That said, over the course of 2011, our cost per mile was around $1.6 million a mile.

Our estimate for this year is somewhere in the $1.1 -$1.15 million per mile, so a significant reduction of what we incurred in 2011.

I would also add that we are dealing with shorter segments of pipe than I think that most people do, and so that adds to the cost per mile.

Thank you very much.

Very thorough.

Paul Patterson, Glenrock Associates.

Just to go to the penalty stuff, how should we think about how you guys go about sort of -- I know there is a lot of judgment involved -- but sort of how do you go about sort of estimating what you think they might be?

I mean, is this based on discussions or just how do we get a feel for that process?

Let me start, and then I will flip it over to Kent.

And just to clarify, what we accrued is not what we thought it might be.

It is the low end.

And you get to there -- as we looked at all the developments that we concluded having no accrual at all was not the appropriate place to be, because I think it was certain we are going to have a penalty.

And in looking at all the facts and circumstances and using judgment concluded that $200 million -- we didn't think that the penalty would in any realistic circumstance be below $200 million.

Now, there are a lot of facts that went into that.

Kent, you might want to comment on some of the things you look at.

But I want to make sure -- that is what we think the minimum is.

It is not what we think -- the best guess at what it is going to be.

Okay.

Paul, Tony's overall summary is exactly right.

And the things we looked at were the various proceedings at the Commission, including we looked at the CPSD's report that was filed early in the year; we looked at the new OII in San Bruno that was issued in January; and also the citation from the CPSD related to the maps that Chris covered earlier.

And the reality of the situation, when you look at all the different issues, is that there are no clear precedents really, and there is not just like a formula that can be applied to the situation.

But all the indications are that the PUC will impose a large penalty here.

So we considered previous penalties, such as Rancho Cordova.

And then we tried to take into account the magnitude of this event, and we determined overall that the penalty will likely be higher than anything that has been previously issued by the PUC for all of those reasons.

And we ended up thinking that $200 million was a reasonable estimate for the low end of the range of possible outcomes.

Okay.

And then also, there was a week or two ago, some articles regarding welders saying that the hydrostatic testing wasn't perhaps as good as it could have been or was -- I was just wondering.

I know it has been pretty recent since this came out, but just any -- do you guys have any thought process as to what they are talking about or the validity of it?

This is Nick.

We take every communication that comes in to us concerning questions about whether or not we accomplish work properly very seriously.

And so we took a look at what these two welders had to say, and we've gone back and made an intensive records review.

We've pulled all the radiographic welding records and all the as-build material.

We have looked at this every way we possibly can, and we find absolutely no merit whatsoever into the allegations that have been brought forth by these two folks.

I can't speak to their motivations.

But we take everything like this very seriously, and we have found nothing to suggest that our workmanship was nothing but top quality.

That is another thing going back to the cost of these hydrostatic testing programs.

We have put in an extraordinarily extensive QA/QC program, way beyond what industry standards are, to make sure that this work, when it is done, it is done properly.

And that certainly adds to the cost or to the time of execution.

But we find absolutely no indication whatsoever that we had any issues with our testing last year.

Okay, great.

Thanks.

That is what I would expect.

Thanks a lot.

Jonathan Arnold, Deutsche Bank.

Good morning, guys.

Good afternoon for us I guess.

On the -- just to be sure I understand the PSEP number and how it has impacted guidance, is the situation that that $230 million before was kind of neither in your operating guidance nor in the GAAP guidance, because you were assuming recovery?

And all that is really happening is now it is in the GAAP guidance, having been a net zero before, effectively.

Jonathan, that's right.

Essentially, we said last quarter that we were assuming full recovery of the PSEP cost so they wouldn't flow through to the bottom line.

Although I remember sort of talking through the fact that there could be a timing -- once you have a memo account in place, there would be a timing about when we get a final decision, but that the costs would be recoverable.

And we left it up to you guys if you wanted to make different assumptions.

Okay.

So now, if you were to get a memo account sometime midyear and some of those costs end up being recovered, that would just reduce the amount of charge to the GAAP earnings.

That's correct.

Okay.

Thank you for that.

Just on the time -- you obviously put the slide out with the regulatory calendar, and just the way you've laid it out, it is sort of tempting to imagine that some of these hearings and proceedings could come to a head at more or less the same time.

Am I reading too much into that, one?

Two, what chances do you see that there would be some kind of merging of any of these proceedings at the Commission?

And I guess a third strand of that, would you need to see that in order to be able to potentially settle any of these?

This is Tom Bottorff, responsible for regulatory relations.

I don't foresee the Commission consolidating the three investigations at this point, but that doesn't preclude the parties to the proceeding from engaging in settlement discussions in connection with each of the investigations.

Is that something that has potentially happened already or are we a little too early in the game for that?

I think it's early in the game, although the judge at the prehearing conference that was held this Tuesday in the San Bruno investigation did strongly encourage parties to agree on issues where they could, and actually offered himself up as a potential mediator to help facilitate settlement discussions.

Great.

Thank you.

Steve Fleishman, Bank of America Merrill Lynch.

Thank you.

A couple questions.

First, if you add the penalty accrual, the PSEP now being kind of rolling through, as well as this additional $120 million, altogether that is a lot more than the additional equity issuance.

Is the difference just this penalty issue that you are not actually having to spend the money yet?

When you add all those up, I think you probably get $500 million, $600 million of additional hit to the balance sheet.

This is Kent.

It is that, and that is why I elaborated a little on that issue earlier, that it is not as simple as saying you accrue $200 million and you immediately issue $200 million.

We actually, as you know, have to actively manage our capital structure, and we do really monthly forecasting to do that.

So you really do have to consider both when you book things, and therefore affect your retained earnings, but also when the cash goes out the door.

And that does affect that, as well as you want to think about the expenditures that are now going to be unrecovered for gas pipeline matters occurring throughout the year, rather than all at the beginning of the year.

And as a result, that tends to also affect the timing of the equity issuance.

Okay.

Second question is just, if you now take this update and go back to the beginning of the San Bruno, what is the total cost that shareholders have now borne?

Steve, we can easily now get up to costs that are well in excess of $1.5 billion, and I will just kind of recap them.

You saw in our press release that cumulative to date, we have spent around $550 million that is not going to be recovered, that is at a shareholder cost.

And obviously, our guidance indicates that we could spend nearly that much in 2012 on pipeline related items.

We accrued a $200 million penalty.

So when you add all that up, that brings you to about $1.2 billion to $1.3 billion that shareholders have incurred.

As you know, we have also committed to spend $200 million this year and $200 million next year on all of our operations, which is not going to be funded by customers but in fact at shareholders' cost.

And that is how you can get to $1.6 billion to $1.7 billion, which obviously, is a very significant price tag.

In fact, that is actually approaching the total net investment in our pipelines that we built up over decades.

And I would also say that this business typically is authorized to earn about $100 million a year.

So the costs here that shareholders have now incurred represents 15 to 20 years of earnings, basically.

Okay.

One last question.

There was the testimony on the San Bruno OII that -- I guess that audit, so to speak, that talked about underspending and overearning over a long period of time, at least alleged that.

Could you just go through kind of -- my sense is some of those issues you may not exactly agree with.

Could you go through some of the issues in that analysis?

This is Chris.

There is a couple of things that you have to take into consideration when you look at that.

First of all is that for the most part, most of our gas transmission rate cases were settled, so they were settlement agreements.

And when you have a settlement agreement, you don't necessarily do a line item by line item tracking of the different types of costs.

And a lot of times, you also don't address how costs are allocated between years.

So there is a lot of judgment that goes into trying to determine what were the authorized amounts of costs to be spent in any one of those given years.

And so when you go back and look at the findings or the assertions, if you will, in that audit, you can see that there is a lot of different assumptions that they are making that, quite frankly, we disagree with, and we will dispute as we move forward in the process.

The second thing, though, that you really need to focus here on is that the majority of the costs that they are alleging that we did not spend, the $400 million out of the $500 million, relates to the programs that are, quite frankly, at-risk programs, and it generally is around our gas storage and our ability to utilize those funds.

Many years ago, the CPUC decided they did not want the customers to have the risks around that, and so we were - we, the shareholders then were the ones that would suffer the consequences of a marketplace that didn't have activity in it, or could have the rewards of it.

And in fact, over the last couple of years, we've seen very little in terms of rewards and income off of those businesses.

And so what they are asserting is that we should have taken at-risk revenues that were designed to incent or penalize shareholders and apply them elsewhere.

And then finally, when you look at the totality of our returns over the last 15 to 20 years, you will see that, in general, they are pretty much right around our authorized return in total for the Company.

And so it is not like all of that went and caused us to have a Companywide excessive earnings.

We were utilizing that for other parts of the business.

So there is a lot there that will come out and be asserted differently by us as we move forward in the regulatory proceedings.

Thank you.

Hugh Wynne, Sanford C.

Bernstein & Company.

Hi.

I also had a question related to the Consumer Protection and Safety Division's report.

What struck me most about that report were not so much the details of the audit, but the line of argument that the Division was presenting, which I think you could paraphrase as something along these lines, that PG&E had a legal obligation to run its gas pipeline system in a safe and reliable fashion.

It requested and received most recently through a settlement the revenues that it deemed necessary to do so.

The events at San Bruno and the record presented in the report indicate that the Company failed in its obligation to provide safe and reliable service.

Now, the Company is coming back and saying a large portion of our PSEP budget which relates to more onerous regulatory standards should be recoverable, and the amounts that are being requested for recovery are comparable to the rate base of the system.

And the argument seems to say, didn't we pay you once for the assets and the O&M necessary for safe and reliable service, and if you failed to provide it, given that we paid for it already, why should we pay for it again.

And it seemed to me an argument that would strike a chord with intervenors.

Obviously, it has with Commission staff.

And it might strike a chord with commissioners themselves.

So I wanted to ask you, how have you seen that argument received at the Commission?

And secondly, and perhaps most importantly, how do you rebut it?

Well, we can't comment on where the Commission is on this because the proceedings are going on, and we'll see how they come out.

But I think you have to look at it in the overall context.

When you are talking about safe and reliable systems, it is a measure against what are the standard practices in the industry.

And I think what we've said in response, there are some places where we weren't following standard practices, and to the extent that was the case, then we ought to absorb those costs.

But to the extent that the standards are being changed and being increased, those new requirements ought to be recoverable from our customers through our rates.

And I think you're going to see across the country, as we see new both national pipeline standards and I think other states will start to look at what happens here in California, you will see the same thing, that while people were followed accepted practices in the past, technology has changed, the understanding of the risks have changed, and therefore these new standards should be recoverable as part of the normal course of business.

Great.

Thanks a lot.

Michael Lapides, Goldman Sachs.

Two questions.

First, Kent, other uses of cash likely in 2012, when I think about what is embedded in your guidance, and maybe even one or two sources.

Can you comment on Hinkley-related costs?

Can you comment on expected funds to be paid out due to the generator settlements and some of that kind of that liability that is sitting there on your balance sheet?

And then can you talk about the short-term debt balance?

Because the short-term debt balance is at a level we haven't seen in a long while, at about $1.6 billion.

And normally at this time of year -- normally the peak in short-term debt balance is third quarter, not fourth quarter, so it is not all funds or proceeds being utilized, it seems, for fuel and power procurement.

It is for, obviously, the gas side.

Can you touch on those three items?

Sure.

First of all, in terms of Hinkley, we did, as you know, accrue a liability in the third quarter for Hinkley.

Those, are in terms of a cash impact, those are activities that are going to take place over many years.

And we have guidance out there for a potential increase in the liability this year.

And again, most of those activities would take place over many years.

So I don't see that as a significant driver of short-term cash.

In terms of generator settlements, we don't see a lot of activity there this year.

I think that is a little bit further out.

So again, kind of same answer.

That is not a big driver of our short-term cash needs.

And in terms of where we ended up the year with short-term debt, we do have a fair amount of collateral posted, which we do as part of our normal activities related to energy procurement, as well as hedging.

And when you have low gas prices, as we currently have, while that reduces the cash outlay for procuring fuel and gas for customers, it does cause us to have to post collateral to secure the arrangements we have with counterparties.

And that is a big driver of what you are seeing at the end of the year.

Meaning that the short-term debt balance is higher this go-round versus let's say a year ago or two years ago from now at the same quarter because the lower commodity price required an increased collateral posting?

That's correct.

Okay.

Finally, and, Tony, this one for you, total costs related to San Bruno getting close to the actual rate base in the pipeline business.

Is there a point -- what is kind of the breaking point?

What is the tipping point where it has gone too far, meaning that it is too detrimental to shareholders?

Or is there not a number that can be assigned to that?

Well, my personal view is shareholders have paid a lot of money, and I really believe that the Commission needs to take that into account when they are assessing how much additional penalty ought to be involved.

Because I will tell you that right now, we are doing everything we can, and we are not going to do anything differently or more depending upon what the size of the penalty is.

In fact, I think everyone, including the Commission, recognizes this Company needs to be financially healthy to be able to keep the investment going.

Because we are going to be working on this for a number of years.

That said, we are totally committed to whatever it takes to meet the commitments that we've made in the PSEP program and to make sure that we have the safest possible gas system.

I can't put a number on that.

And the reality is we don't have a choice.

We are committed to doing that.

You can't just say, well, we are not going to make this safe.

We need to build credibility with our customers, and I think the way we build it is by showing we are serious with our actions.

Okay.

Thank you.

Travis Miller, Morningstar.

Hi.

Thanks.

I had a question on the capital structures, parent and utility, and that accrual along with that equity issue.

Does the accrual go to the Utility or will that stay at the Parent?

No, the accrual does go to the Utility.

So how does that affect the capital structure then, if the accrual ends up staying through and the cash impact doesn't come into effect during the year.

When you guys go in for that capital structure review, is that going to change the equity share?

What happens is for rate-making purposes, the capital structure at the Utility is affected in the short term by the accrual because you are reducing retained earnings by that amount.

As we've indicated, our plans are to maintain a balanced capital structure consistent with our authorized capital structure, and that does require that we issue additional equity to offset the accrual.

It eventually becomes a one-for-one impact, but because it is a non-cash accrual initially, there is a little bit of -- less of an impact in the near term, but over time, it becomes the one-for-one impact.

Okay.

So then if we think back to that $300 million extra, but then you had the -- correct me if I'm wrong -- the $200 million accrual plus the $120 million, so $420 million of extra costs.

Am I hearing that correct?

Yes.

You will want to remember that the accrual for the penalty is not tax-deductible.

Our ongoing gas cost, which would include the higher estimate now by $120 million, those are larger, unrecovered costs, which over time, gradually, will affect what would have been our retained earnings.

And so again, we displace essentially the after-tax amount of that over time with additional equity.

Okay, I got it.

So the $600 million gets you back to the 52%?

That is correct.

Based on your expectations.

Okay, great.

Thanks a lot.

Josh, since we are approaching the one-hour mark, if there is one more question, we will take that.

Andy Levi, Caris.

Good afternoon -- or good morning for you guys.

Just an insurance question.

So, just remind us again how much insurance you guys have?

At the time of the accident, for third-party liabilities, we had $992 million of insurance.

$992 million, and you've gotten back about $100 million so far?

That is correct.

And obviously, we don't intend to have the liability -- we don't expect the liability will reach that full level.

Okay.

Can you give us any idea of kind of how much you have requested or filed for on the insurance side thus far, and whether that number changes or that is kind of what you are asking for?

Well, we have estimated -- publicly, we have accrued $375 million total for the accident.

We've said that the maximum liability, based on our estimates, is in the $600 million range.

The way it works with our carriers is that as we resolve claims with third parties, then we take those claims to our insurance carriers.

And our insurance policy represents a tower of insurance companies at different layers in the coverage.

And so we are in the process of working through that with the first several layers of our insurance coverage, and those are the proceeds that you have seen so far.

Those are for claims that have been resolved with third parties that we've brought to our first few layers and have resolved the recovery with them.

Okay, but it sounds like the maximum amount that you are kind of looking to receive is about $600 million?

That is what we estimate is the maximum likely liability.

But we have currently accrued the low end of our range, which is $375 million.

We just have not resolved that level yet of third-party claims, so we have not yet brought that magnitude to the insurance carriers.

Got it.

Thank you very much.

All right.

I would like to thank everybody for being on the call today and your interest, and have a great day.

Bye now.

Ladies and gentlemen, thank you for attending the PG&E fourth-quarter earnings conference call.

This now concludes the conference.

Please enjoy the rest of your day.