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Xcel Energy Inc. (NYSE:XEL)

Q2 2011 Earnings Call

July 28, 2011 10:00 AM ET

Executives

Paul Johnson – MD, IR and Assistant Treasurer

Benjamin Fowke – President, CEO and COO

David Sparby – VP and CFO

Scott Wilensky – VP, Regulatory and Resource Planning

Analysts

Justin McCann – Standard & Poors Investment Advisory, Inc.

Ali Agha – SunTrust Robinson Humphrey

Greg Reiss – Catapult Capital Management

Travis Miller – Morningstar Research

Mike Bates – D. A. Davidson & Co.

Jim Bellessa – D. A. Davidson & Co.

Operator

Ladies and gentlemen, thank you for standing by and welcome to the Second Quarter 2011 Earnings Conference Call. During today’s presentation, all parties will be in a listen-only mode. Following the presentation, the conference will be opened for questions. (Operator Instructions) This conference is being recorded today, Thursday, July 28, 2011.

I would now like to turn the conference over to Paul Johnson, Managing Director of Investor Relations and Assistant Treasurer. Please go ahead, sir.

Paul Johnson

Thank you and welcome to Xcel Energy’s second quarter 2011 earnings release conference call. With me today are Ben Fowke, President and Chief Operating Officer; Dave Sparby, Vice President and Chief Financial Officer; Teresa Madden, Vice President and Controller; Scott Wilensky, Vice President, Regulatory and Resource Planning; and George Tyson, Vice President and Treasurer.

Today, we plan to cover our second quarter results and accomplishments. In addition, we are reaffirming our 2011 ongoing earnings guidance of $1.65 to $1.75 per share.

Please note that there are slides that accompany the conference call, which are available on our web page. I want to remind everyone that some of the comments we make may contain forward-looking information. Significant factors that could cause results to differ from those anticipated are described in our earnings release and in our filings with the SEC.

You will notice that today’s press release refers to both GAAP and ongoing earnings. Second quarter 2011 ongoing earnings were $0.33 per share compared with $0.29 per share in 2010. The second quarter 2011 GAAP earnings were also $0.33 per share compared with $0.30 per share in 2010.

While there are no differences between GAAP and ongoing earnings during the second quarter of 2011, the second quarter of 2010 included a $0.01 per share benefit due to recognition of a tax benefit related to a previously-held investment. Management believes ongoing earnings provide a more meaningful comparison of results, and is representative of Xcel Energy’s fundamental core earnings power. As a result, we will only discuss ongoing earnings during this call. Please see our earnings release for a reconciliation of GAAP to ongoing earnings.

I will now turn the call over to Ben Fowke.

Benjamin Fowke

Thank you, Paul, and welcome to everyone on today’s call. This morning, we reported second-quarter ongoing earnings of $0.33 per share compared with $0.29 per share in 2010. As a result, we remain well-positioned to deliver ongoing earnings within our 2011 earnings guidance range of $1.65 to $1.75 per share. Dave will discuss second-quarter results in more detail in a few moments.

Let me now bring you up-to-date on some recent developments, all of which are favorable to our customers and supportive of our goals. We continue to make excellent progress on our transmission construction plans, as witnessed most recently with the completion of the Midway project in Colorado, a project consisting of 82 miles of 345 kV transmission line.

In June, we passed an important milestone regarding one of the CapX2020 transmission lines. The MISO Board of Directors granted approval for the Brookings transmission line on the condition that this project is included in the full portfolio of multi-value projects being approved in December 2011. Our CapX2020 transmission project remains on schedule. These transmission projects will facilitate access to renewable energy and improve reliability for our customers.

There are also positive developments regarding our nuclear operations. We are pleased that the NRC renewed the operating licenses for our Prairie Island nuclear generating units for 20 years. The renewal will allow units one and two to continue to provide emission-free power to our customers through 2033 and 2034, respectively. These units have operated in a safe, reliable, economic, and environmentally sound manner for nearly 40 years and our significant investments to support life extension will enable continued solid performance for the next 20 years.

Another positive event for our customers was the settlement we reached with the federal government regarding costs incurred by NSP and its customers related to the DOE’s failure to provide long-term spent fuel storage facility by the required deadline.

Under the terms of the settlement, the federal government will pay NSP approximately $100 million for spent fuel storage costs at our nuclear plants incurred through 2008. The federal government will also pay for spent fuel storage costs incurred from 2009 through 2013. We project those costs to be an incremental $100 million. Finally, the settlement does not address costs for used fuel storage after 2013, which could be the subject of future litigation. Settlement funds will be refunded to our customers in our NSP service territory.

As you know, we are striving to improve regulatory recovery and reduce regulatory lag in each of our jurisdictions. In that regard, another significant development occurred in Minnesota this spring, when a law was passed which allows utilities to file multi-year rate plans. As a result, we plan to seek to implement a multi-year plan that would establish rates for a three-year period, adjusting rates annually based on our investments and costs.

We will first propose a multi-year plan in Minnesota, potentially followed by similar proposals in North Dakota and South Dakota. Undertaking a significant change in our regulatory process will require collaboration with stakeholders to demonstrate the benefits of the plan. We anticipate proposing to implement the plan concurrent with the 2013 Minnesota Electric Rate Case filing expected to be filed in November 2012.

Finally, we continue to make significant progress on our efforts to provide our customers with competitively-priced renewable energy and to meet the 30% renewable portfolio standards in Minnesota and Colorado. We recently took advantage of favorable market conditions for the development of new wind projects by signing long-term renewable energy purchase agreements in Minnesota and Colorado.

In Minnesota, we contracted to purchase 200 megawatts of wind energy to be generated at the Prairie Rose Wind Farm in Southwest Minnesota; while in Colorado, we agreed to purchase 200 megawatts of wind energy from the Limon Wind Energy Center. In addition, we’ve been negotiating with several wind developers for the potential ownership of a wind project in North Dakota. These projects will provide our customers with competitively-priced energy and increase the amount of emission-free generation in our portfolio.

I’ll now turn the call over to Dave.

David Sparby

Thanks, Ben. Let’s begin by reviewing second-quarter earnings results at our four utilities. Earnings at NSP Minnesota increased $0.04 per share, largely due to higher interim electric rates in Minnesota and North Dakota, partially offset by higher property taxes and depreciation expense.

Earnings at PSCo decreased $0.02 per share, primarily due to seasonal rates which were implemented in June 2010, higher O&M, property taxes, and depreciation expense.

At NSP Wisconsin, earnings increased $0.01 per share, due to the implementation of new electric rates, partially offset by higher O&M and depreciation.

At SPS, earnings were flat for the quarter.

Now I’d like to discuss the items that affected certain lines of the income statement, beginning with retail electric margin. Electric margin increased $84 million for the quarter, largely driven by three items: A $35 million increase in revenue requirements reflecting the acquisition of two natural gas facilities in Colorado. However, these revenue requirements are partially offset by higher O&M, depreciation, property taxes, and financing costs; $23 million as a result of retail rate increases in several states; and $19 million for recovery of conservation and DSM expenses and incentives.

Turning to our natural gas business, margins increased $7 million for the quarter, driven primarily by weather and recovery of conservation expenses and incentives. The improvement in our second-quarter electric and natural gas margins was partially offset by O&M expenses, which increased $16 million or 3%; higher plant generation costs; and higher labor and contract labor costs were the primary drivers of the increase.

Through the first half of the year, O&M expenses increased 4.5%, which is consistent with our expectations. We continue to project 2011 O&M costs to increase approximately 4%.

Also offsetting some of the improvement in margins, depreciation and amortization increased $17.8 million or 8.4% versus the comparable period last year due primarily to several plants going into service in 2010, including Comanche Unit 3, the Nobles Wind Project, and the acquisition of two natural gas plants. In addition, we experienced an $11.5 million or 14.2% increase in non-income taxes. The increase was primarily due to higher property taxes in Colorado and Minnesota.

Let’s move on to our financing plans. Our plan enables us to maintain a solid balance sheet and strong credit metrics. As I’m sure you can appreciate, this plan is subject to change depending on the timing of capital expenditures, internal cash generation, market conditions, and other factors. Our financing plans for 2011 are relatively light. We plan to issue approximately $250 million of first mortgage bonds at PSCo during the third quarter and approximately $200 million of bonds at SPS in the third quarter. In addition, Xcel Energy also anticipates issuing approximately $75 million of equity through our DRIP and various benefit programs.

Now I’ll provide an update on several of our pending and recent rate cases. In Minnesota, we are requesting $123 million of electric rate increase for 2011 and a $45 million increase for 2012, both based on a 10.85% ROE. The primary intervener, the Department of Energy Resources, is recommending a 2011 rate increase of approximately $85 million and a $34 million increase for 2012, based on a 10.37% ROE. The main difference between our position and the Department’s is ROE.

During the second quarter, we established a provision of approximately $15 million for the Minnesota Electric Rate Case. This reserve is sufficient to address an outcome that is more consistent with the Department’s position and NSP Minnesota’s position on several issues. However, we strongly believe that the appropriate level of rate recovery is our request of $123 million, and we’ll continue to advocate for our position. We are anticipating an ALJ recommendation in the fall and a PUC order in the fourth quarter, although there will be some delay as a result of the recent government shutdown in Minnesota.

In Colorado, we reached a constructive settlement in our natural gas rate case. The settlement effectively provides approximately $21 million in additional revenue, beginning in September 2011. In addition, a rider for gas pipeline integrity cost is projected to add an additional $13 million in revenue in 2012.

Turning to North Dakota; we are requesting a 2011 electric rate increase of $18 million and a 2012 electric rate increase of $2.4 million, based on an 11.25% ROE. Interim rates of $17.4 million were effective in February. Intervener testimony is expected in mid-August; rebuttal testimony in September; and evidentiary hearings in October. We anticipate a final decision in the first quarter of 2012. And, in South Dakota, in June 2011 NSP Minnesota filed a request to increase electric rates $14.6 million, based on a 2010 historic test year, adjusted for known and measurable changes; an 11% ROE; an equity ratio of 52.5%; and an electric rate base of $323 million. South Dakota does not allow interim rates but they typically process rate cases in about six to seven months. Final rates are expected to be effective in early 2012.

At NSP Wisconsin, we filed a request with the Public Service Commission at Wisconsin to increase electric rate to $29 million and gas rate to $8 million. The filing is based on a 2012 forecast test year, 10.75% ROE, and an equity ratio of 52.5%. NSP Wisconsin’s 2012 rate base is forecast to be approximately $718 million for the electric utility and $84 million for the natural gas utility.

Finally, in New Mexico, as you recall, last February SPS filed an electric rate case with the New Mexico Public Regulation Commission, seeking an annual base rate increase of approximately $20 million. The rate filing is based on a 2011 test year adjusted for 2012 known and measurable changes; a requested ROE of 11.25%; an electric rate base of $390 million; and an equity ratio of 51%. Rates are expected to go into effect during the first quarter of 2012. That concludes my regulatory update.

In summary, we had another good quarter, highlighted by several positive outcomes. Our strong financial results position us to meet our annual earnings guidance. We received conditional approval for our Brookings transmission line. We received approval to extend the operating license of our Prairie Island nuclear plant by 20 years. We were awarded a $100-million settlement from the DOE. The Minnesota Legislature passed a bill, authorizing multi-year rate plans we contracted for 400 megawatts of wind power. We’ve made good progress on our multiple rate cases. The Board of Directors raised the annual dividend by $0.03 per share, and the Board ensured a smooth management transition, naming Ben Fowke to succeed Chairman and CEO, Dick Kelly, upon his retirement next month.

That concludes my prepared remarks. Operator, we will now take questions

Question-and-Answer Session

Operator

Thank you, sir. We will now begin the question-and-answer session. (Operator Instructions) Our first question is from the line of Justin McCann with Standard & Poor’s. Please go ahead.

Justin McCann – Standard & Poors Investment Advisory, Inc.

Good morning.

David Sparby

Good morning.

Justin McCann – Standard & Poors Investment Advisory, Inc.

Two things; one, what are the conditions of the conditional approval for the Brookings transmission line? And two, an update on Minot.

David Sparby

What was the second half of that question, Justin? An update on...?

Justin McCann – Standard & Poors Investment Advisory, Inc.

An update on Minot, the flooding.

Paul Johnson

Minot, the flooding.

David Sparby

Okay. Well, with respect to the Brookings line, the condition is the approval of the remainder of the portfolio under condition – under consideration at the end of the year. And, the flooding situation in Minot, the recovery tends to go well up there. Obviously, there was significant amount of damage to the system but it – we continue to recover as we planned.

Justin McCann – Standard & Poors Investment Advisory, Inc.

Okay, thank you.

Operator

Our next question is from the line of Ali Agha with SunTrust. Please go ahead.

Ali Agha – SunTrust Robinson Humphrey

Thank you. Good morning.

David Sparby

Good morning, Ali.

Ali Agha – SunTrust Robinson Humphrey

Ben or Dave, I believe you mentioned that your O&M expense through the first half are pretty much on plan. Could you also let us know your – the retail sales – weather-adjusted retail sales that you’ve been seeing so far, how they are comparing to plan? And any change for your outlook from listening to your customers looking forward?

David Sparby

Sure, Ali. The – certainly, the first half of the year sales were a little weaker than we anticipated. It’s important to remember, though, there were some unique events in the first half of the year. We had the Texas cold snap if you recall. That was a fairly significant impact. Second quarter, in Colorado we had some large customers also that had some fairly unique situations.

And, it’s also important to remember that our conservation programs, of course, are running very well for us in the first half of the year. That said, certainly our local economies, like others, face some headwinds from higher gasoline prices and other impacts during the first half of the year. And so, we are at the lower half of our guidance range that we provided in terms of sales for the remainder of the year.

Benjamin Fowke

Hey, Ali. I would also add to Dave’s comments that July has been an extremely hot month for us across all of our service territories. And, it’s been pretty active from a storm perspective too. So, just factor that into your analysis as well.

Ali Agha – SunTrust Robinson Humphrey

And, also related to that, just remind me and I think, Ben, you alluded to that, in terms of making sure you minimized regulatory lag. Where do we stand currently, if you look at, say, LTM, ROEs, et cetera? What kind of lag are you currently estimating in your system?

David Sparby

Well, we’re currently anticipating at an Xcel basis to earn about 10% this year, Ali. We continue to make progress reducing regulatory lag, as you saw in the settlement of our Texas case. We certainly did win the ability to defer some costs and have a 2012 step – looking at putting a 2012 step in place in our Minnesota case and our North Dakota case. So, we continue to make progress that we can point to on reducing that regulatory lag.

Ali Agha – SunTrust Robinson Humphrey

And, then just to keep it apples-to-apples, the 10% you expect to earn across the Xcel – at the Xcel level, what would that compare to in terms of authorized ROE?

David Sparby

Well, the – probably the average, and of course each state is fairly unique, but probably the average authorized right now is close to 10.5%.

Ali Agha – SunTrust Robinson Humphrey

Okay, got it. And, last question; any further updates or thinking on the next round of equity offering? Is that still something that you will look at in 2012? Or, have the timelines changed somewhere on that?

David Sparby

We’ve said, Ali, that we don’t have any intention to offer equity this year and we have provided no guidance following 2011.

Benjamin Fowke

Ali, you usually – this is Ben. You usually ask about the ROEs, and Dave’s absolutely right. Consolidated ROEs are about 10%. But, remember, we do have some additional leverage at the holdco. So, when you really look at what our utilities are earning, the lag is a little more pronounced than what it might appear on the surface. That’s the challenge but that’s also the opportunity if we can close that gap through multiyear plans etcetera and get closer to our authorized ROEs.

Ali Agha – SunTrust Robinson Humphrey

And Ben is that usually like a 50 basis point extension?

Benjamin Fowke

Yes, I think, I’m looking at the group, I think it’s probably about 50, maybe a little bit more of that, so that would imply that the regulated utilities are earning somewhere around $9.5, so about 100 basis points off of the authorized. So I mean that’s the opportunity and the challenge for us.

Ali Agha – SunTrust Robinson Humphrey

Correct. You’re right. Thank you.

Operator

Thank you. Our next question is from the line of Greg Reiss with Catapult Capital Management. Please go ahead.

Greg Reiss – Catapult Capital Management

Hi, guys. Congrats on a good quarter.

David Sparby

Thanks, Greg.

Greg Reiss – Catapult Capital Management

Just real quick question, could you just comment a little bit more about this $15 million refund? Does that mean you are not currently booking earnings on a portion of that $123 million interim request?

David Sparby

What we said, Greg, is we reserved $15 million second quarter and that reflects our assessment of looking at the issues and also that it’s more consistent with the DOER’s position on several issues in the case.

Greg Reiss – Catapult Capital Management

And do you anticipate to reserve any more money going forward?

David Sparby

We would anticipate, yes, reserving another $15 million over the remainder of the year.

Greg Reiss – Catapult Capital Management

Got it. Thanks, guys.

David Sparby

Thank you.

Operator

Thank you (Operator Instructions) And our next question is from the line of Travis Miller with Morningstar. Please go ahead.

Travis Miller – Morningstar Research

Good morning.

David Sparby

Good morning, Travis.

Travis Miller – Morningstar Research

A quick follow-up on that last one. If you’re going to take those charges, why would you keep your request at that same level? Because you’re roughly in line right now with the interim rate so if you have another $30 million or so why wouldn’t that result in another decrease in your request?

David Sparby

Well, we strongly believe that our request is appropriate and is consistent with the cost of the company so it remains our request. Our reserve reflects our review of the current positions of the Department as well as some Commission decisions as well.

Benjamin Fowke

Travis, I mean, it’s basically the principle of conservativism. So that’s what we’re doing while we continue to push for a better outcome than what we’re reserving for.

Travis Miller – Morningstar Research

Okay. So it suggests that you would expect somewhere in the range of a $93 million increase?

David Sparby

Yeah, we do expect to prevail on our request. We’re reflecting, once again, the Department’s position as well as some Commission decisions.

Travis Miller – Morningstar Research

Okay. What’s the impact from bonus depreciation in the rate cases that you filed, say, in the last six months?

David Sparby

We have really seen very little impact. Because we were in an NOL position entering into the rate cases, it’s had very little impact on us. Some movement of monies between companies, but no revenue requirement impact, Travis.

Travis Miller – Morningstar Research

Okay. So it hasn’t reduced rate base all that much –

David Sparby

No.

Travis Miller – Morningstar Research

...for any particular one? Okay, great. Thanks a lot.

Operator

Thank you. Our next question is from the line of Jim Bellessa with D. A. Davidson. Please go ahead.

Mike Bates – D. A. Davidson & Co.

Good morning, guys; this is actually Michael Bates here with Jim. I had a couple of questions for you. In reference to the legislation in Minnesota that’s going to allow you to file these multiyear rate plans, can you give us just a little more color on how receptive has the PUC been to the concept? And will there be any need for a change in legislation to file these plans in North and South Dakota in the future?

David Sparby

Well, the PUC has shown some interest in the plans. They certainly are interested in seeing a plan come from us.

With respect to the question about North Dakota, I’m not sure, Scott, do you have an answer for that?

Scott Wilensky

I think that the Dakotas we would not need legislation. They’ve been more willing to exercise their general authority on alternative rate-making. We’ve actually had alternative rate-making plans in North Dakota in the past. So we don’t expect that need. Minnesota, when they’ve actually wanted to move to alternative rate-making, has done that by legislation and that’s why this was so important to get done.

Mike Bates – D. A. Davidson & Co.

Got you. Okay. And then one other question. You mentioned that you’re negotiating at this point for a possible ownership of a North Dakota-based wind project. Can you give us any idea of what the timeframe or the size of that project might end up being?

David Sparby

Well, I can tell you we recently filed a kind of a brief progress report with the North Dakota Commission. We informed them that we continue to make good progress and will update them in other couple weeks as to where we stand at that point in time. That’s about all the additional color I can provide at this point.

Jim Bellessa – D. A. Davidson & Co.

This is Jim Bellessa and I have a question about the municipalization efforts in Boulder, Colorado. I don’t believe I heard much from the Company. I heard a lot from Boulder, Colorado, but does company have any comment?

Benjamin Fowke

Well, this is Ben. I mean, yes, you’re hearing a lot of press about it, but I think you’re starting to also see some of the facts come out. And the bottom line is that we believe municipalization would be a bad thing for the citizens and customers that reside in Boulder. I ultimately think the facts will speak for themselves and they won’t vote for municipalization. If they do, and I think it’d be an unfortunate thing if they vote for municipalization, be assured that we will make sure that we get a fair price and include elements of fair market value of our asset separation cost, stranded cost, etcetera.

And we’ll make sure we get the price that we’re entitled to so that our customers in Colorado, outside of Boulder, aren’t harmed nor are our shareholders. But, in a nutshell, I think it’s a bad idea for Boulder. And I think what we offer in terms of price, reliability, and environmental leadership is pretty tough to beat.

Jim Bellessa – D. A. Davidson & Co.

Thank you very much.

Operator

Thank you (Operator Instructions)

David Sparby

Okay. Well, I want to thank you for participating in our second quarter earnings call this morning. We look forward to meeting with many of you in the next couple weeks.

If you have any follow-up questions, please direct them to Paul Johnson and the IR team, who are available to take your calls. Thank you very much.

Operator

And ladies and gentlemen, that does conclude our conference for today. If you’d like to listen to a replay of today’s conference, please dial 303-590-3030 or 1-800-406-7325, followed by the access code of 4451887 and the pound sign. Thank you for your participation. You may now disconnect.

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