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WR > SEC Filings for WR > Form 10-Q on 8-Nov-2012All Recent SEC Filings

Show all filings for WESTAR ENERGY INC /KS

Form 10-Q for WESTAR ENERGY INC /KS


8-Nov-2012

Quarterly Report


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Certain matters discussed in Management's Discussion and Analysis are "forward-looking statements." The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we "believe," "anticipate," "target," "expect," "estimate," "intend" and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals.

INTRODUCTION

We are the largest electric utility in Kansas. We produce, transmit and sell electricity at retail in Kansas and at wholesale in a multi-state region in the central United States under the regulation of the KCC and FERC.

In Management's Discussion and Analysis, we discuss our operating results for the three and nine months ended September 30, 2012, compared to the same periods of 2011, our general financial condition and significant changes that occurred during 2012. As you read Management's Discussion and Analysis, please refer to our condensed consolidated financial statements and the accompanying notes, which contain our operating results.

SUMMARY OF SIGNIFICANT ITEMS

Earnings Per Share

Following is a summary of our net income and basic EPS.

                                 Three Months Ended September 30,               Nine Months Ended September 30,
                                  2012           2011         Change            2012             2011         Change
                                                  (Dollars In Thousands, Except Per Share Amounts)

Net income attributable to
common stock                 $    139,281     $ 134,708     $  4,573     $    227,923         $ 209,935     $  17,988
Earnings per common share,
basic                                1.10          1.15        (0.05 )           1.79              1.82         (0.03 )

The increases in net income attributable to common stock were due primarily to higher retail prices, including implementing the April 2012 KCC order, and, for the nine months ended September 30, 2012, our having recorded additional corporate-owned life insurance (COLI) benefits. These increases were offset partially by higher operating costs, authorized as part of the April 2012 KCC order, and our having recorded a $7.2 million gain on the sale of a non-utility investment during the third quarter of 2011 for which we did not record a similar gain this year. Also contributing to the higher operating costs was our having reversed $22.0 million of previously accrued liabilities during the third quarter of 2011 as a result of settling litigation. See the discussion under "-Operating Results" below for additional information. In addition, basic EPS decreased as a result of more average equivalent common shares outstanding due primarily to our having issued additional shares in the latter part of 2011 to settle forward sale transactions.

Rate Case Agreement

In April 2012, the KCC issued an order authorizing higher revenues to recover higher expenses primarily for increased tree trimming to enhance reliability and increased pension costs resulting from the consequences of the 2008 financial crisis in accordance with the regulatory mechanism in place to account for such pension costs. As a result of this order, we expect selling, general and administrative expense to increase $32.1 million and the cost of operating and maintaining our distribution system to increase $10.9 million on an annualized basis. In addition, we revised our depreciation rates to reflect changes in the estimated useful lives of some of our depreciable assets. The change in estimate will decrease annual depreciation expense by $43.6 million. However, decreased depreciation expense as a result of lower depreciation rates may be offset by additions to property, plant and equipment.


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Sustainable Cost Reduction Activities

We have been reviewing our operations to identify sustainable cost savings. This review involves process improvements, streamlining organizational structures, and developing other labor and non-labor efficiencies. To date in this ongoing effort, we have identified approximately $16.0 million of anticipated annualized savings and have recorded $4.5 million of expense for the nine months ended September 30, 2012, related to achieving these cost savings.

Current Trends

The following is an update to and is to be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our 2011 Form 10-K.

Environmental Regulation

Environmental laws and regulations affecting power plants, which relate primarily to discharges into the air, air quality, discharges of effluents into water, the use of water, and the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, continue to evolve and have become more stringent and costly over time. We have incurred and will continue to incur significant capital and other expenditures, and may potentially need to limit the use of some of our power plants, to comply with existing and new environmental laws and regulations. While certain of these costs are recoverable through the ECRR and ultimately we expect all such costs to be reflected in the prices we are allowed to charge, we cannot assure that all such costs will be recovered or that they will be recovered in a timely manner. See Note 8 of the Notes to Condensed Consolidated Financial Statements, "Commitments and Contingencies," for additional information regarding environmental laws and regulations.

Air Emissions

The operation of power plants results in emissions of regulated substances and gases, including mercury, acid gases and other air toxics. In December 2011, the EPA published MATS for power plants, which replaces the prior federal CAMR and requires significant reductions in mercury, acid gases and other emissions. Companies impacted by the new standards will have up to three years, or four years with approval from a state environmental regulatory agency, and in certain limited circumstances up to five years, to comply. We have obtained approval from our state environmental regulatory agency and expect to be compliant with the new standards within four years. We continue to evaluate the new standards and believe that our related investment could be approximately $40.0 million.

In July 2011, the EPA finalized CSAPR which requires 28 states, including Kansas, Missouri and Oklahoma, to further reduce power plant emissions of SO2 and NOx. Under CSAPR, reductions in annual SO2 and NOx emissions were scheduled to begin January 1, 2012, with further reductions required beginning January 1, 2014.

In December 2011, the EPA published a final supplemental rule to CSAPR requiring five states, including Missouri and Oklahoma, to make summertime reductions in NOx emissions under an ozone-season control program implemented under CSAPR. Reductions in ozone-season NOx under this rule were scheduled to begin May 1, 2012. Although Kansas was included in the original proposed rule, the final supplemental rule instead called for the EPA to revisit Kansas' status under this supplemental rule once Kansas submitted an ozone state implementation plan.

In October 2011, we and numerous other parties filed legal challenges to CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit. In December 2011, the court issued its ruling to stay CSAPR, including the final supplemental rule, pending judicial review, which delayed CSAPR's implementation. After hearing arguments, a panel of three judges vacated CSAPR in August 2012 and remanded the rule to the EPA for further proceedings. In October 2012, the EPA filed a petition with the court requesting a rehearing before the full court. We cannot at this time predict the outcome of this request. Based on our current and planned environmental controls, if the regulations were to be reinstated or replaced, either partially or in whole, we do not believe the impact on our operations and consolidated financial results would be material.

Greenhouse Gases

In March 2012, the EPA proposed a New Source Performance Standard that would limit carbon dioxide emissions for new electric generating units. We are currently evaluating the proposal and believe it could impact our future generation plans if it becomes a final rule.


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Under EPA regulations known as the Tailoring Rule, the EPA is regulating GHG emissions from certain stationary sources. The regulations are being implemented pursuant to two federal Clean Air Act programs. The programs impose recordkeeping and monitoring requirements and also mandate the implementation of BACT for projects that cause a significant increase in GHG emissions (defined to be more than 75,000 tons or more per year or 100,000 tons or more per year, depending on various factors). The EPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. We cannot at this time determine the impact of these regulations on our operations and consolidated financial results, but we believe the costs to comply with the regulations could be material.

Regulation of Coal Combustion Byproducts

In the course of operating our coal generation plants, we produce coal combustion byproducts (CCBs), including fly ash, gypsum and bottom ash, which we must handle, dispose of, recycle or process. We recycle some of our ash production, principally by selling to the aggregate industry. In June 2010, the EPA proposed a rule to regulate CCBs, which we believe might curtail or impair our ability to recycle ash. The EPA is expected to issue a final rule in 2013. While we cannot at this time estimate the impact and costs associated with future regulations of CCBs, we believe the impact on our operations and consolidated financial results could be material.

National Ambient Air Quality Standards

Under the federal Clean Air Act, the EPA sets NAAQS for six criteria emissions considered harmful to public health and the environment, including PM, NOx, CO and SO2, which result from coal combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. In 2009, KDHE proposed to designate portions of the Kansas City area nonattainment for the 8-hour ozone standard, which has the potential to impact our operations. Recently the Wichita area exceeded the 8-hour ozone standard and may be designated nonattainment in the future.

In 2010, the EPA strengthened the NAAQS for both NOx and SO2. We continue to communicate with our regulators regarding these standards and are currently evaluating what impact this could have on our operations. If we are required to install additional equipment to control emissions at our facilities, the revised NAAQS could have a material impact on our operations and consolidated financial results.

Particulate matter, principally ash, is a byproduct of coal combustion. In June 2012, the EPA proposed to strengthen the fine PM NAAQS. We are currently evaluating the proposal. The EPA expects to issue a final rule by the end of 2012; however, because the rule has yet to be finalized, we cannot predict the impact it may have on our operations or consolidated financial results, but it could be material.

The EPA had been in the process of revising the NAAQS for ozone. However, in September 2011, the President of the United States ordered the EPA to withdraw its proposal. Work is currently underway to support the EPA's planned reconsideration of the standards in 2013.

Water

We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. The EPA plans to propose revisions to the rules governing such discharges from coal-fired power plants later in 2012 with final action on the proposed rules expected to occur in 2014. Although we cannot at this time determine the timing or impact of any new regulations, more stringent regulations could have a material impact on our operations and consolidated financial results.

In April 2011, the EPA issued a proposed rule that would set stricter technology standards for cooling water intake structures at power plants over concerns about aquatic life. We are currently evaluating the proposal as well as a recent information request from the EPA. The EPA is expected to finalize the rule in 2013; however, because the rule has yet to be finalized, we cannot predict the impact it may have on our operations or consolidated financial results, but it could be material.


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Renewable Energy Standard

Kansas law mandates that we maintain a minimum amount of renewable energy sources. Through 2015, net renewable generation capacity must be 10% of the average peak demand for the three prior years, subject to limited exceptions. This requirement increases to 15% for years 2016 through 2019 and 20% for 2020 and thereafter. During the third quarter of 2012, we began purchasing under 20-year supply contracts the renewable energy produced from approximately 370 MW of additional wind generation, which, together with existing facilities, supply contracts and renewable energy credits, will allow us to satisfy the net renewable generation requirement through 2015 and contribute toward meeting the increased requirements beginning in 2016. If we are unable to meet future requirements, our operations and consolidated financial results could be adversely impacted.

Wolf Creek Regulation and Operating Costs

In January 2012, Wolf Creek experienced a loss of off site power that resulted in an unscheduled outage, with the plant returning to normal operation in March 2012. Operating costs at Wolf Creek increased during the nine months ended September 30, 2012, due principally to the unscheduled outage. The NRC increased its oversight of Wolf Creek following the loss of off site power. We expect future increases in operating costs due to increased NRC oversight and efforts to comply with new industry-wide regulations adopted by the NRC earlier this year after a review of U.S. nuclear power plant safety prompted by Japan's Fukushima Daiichi nuclear power plant event in 2011.

CRITICAL ACCOUNTING ESTIMATES

Our discussion and analysis of financial condition and results of operations are based on our condensed consolidated financial statements, which have been prepared in conformity with the instructions to Form 10-Q and Article 10 of Regulation S-X. Note 2 of the Notes to Condensed Consolidated Financial Statements, "Summary of Significant Accounting Policies," contains a summary of our significant accounting policies, many of which require estimates and assumptions by management. The policies highlighted in our 2011 Form 10-K have an impact on our reported results that may be material due to the levels of judgment and subjectivity necessary to account for uncertain matters or their susceptibility to change.

From December 31, 2011, through September 30, 2012, we have not experienced any significant changes in our critical accounting estimates. For additional information, see our 2011 Form 10-K.


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OPERATING RESULTS

We evaluate operating results based on EPS. We have various classifications of revenues, defined as follows:

Retail: Sales of electricity to residential, commercial and industrial customers. Classification of customers as residential, commercial or industrial requires judgment and our classifications may be different from other companies. Assignment of tariffs is not dependent on classification.

Other retail: Sales of electricity for lighting public streets and highways, net of revenue subject to refund.

Wholesale: Sales of electricity to electric cooperatives, municipalities and other electric utilities, the prices for which are either based on cost or prevailing market prices as prescribed by FERC authority. Margins realized from sales based on prevailing market prices generally serve to offset our retail prices and the prices charged to certain wholesale customers taking service under cost-based tariffs.

Transmission: Reflects transmission revenues, including those based on tariffs with the SPP.

Other: Miscellaneous electric revenues including ancillary service revenues and rent from electric property leased to others. This category also includes energy marketing transactions unrelated to the production of our generating assets, changes in valuations of related contracts and fees we earn for marketing services that we provide for third parties.

Our revenues are impacted by things such as rate regulation, fuel costs, customer conservation efforts, the economy and competitive forces. Changing weather also affects the amount of electricity our customers use as electricity sales are seasonal. As a summer peaking utility, the third quarter typically accounts for our greatest electricity sales. Hot summer temperatures and cold winter temperatures prompt more demand, especially among residential customers. Mild weather reduces customer demand. Our wholesale revenues are impacted by, among other factors, demand, cost and availability of fuel and purchased power, price volatility, available generation capacity, transmission availability and weather.


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Three and Nine Months Ended September 30, 2012, Compared to Three and Nine
Months Ended September 30, 2011

Below we discuss our operating results for the three and nine months ended
September 30, 2012, compared to the results for the three and nine months ended
September 30, 2011. Significant changes in results of operations shown in the
table immediately below are further explained in the descriptions that follow.

                                Three Months Ended September 30,                       Nine Months Ended September 30,
                          2012          2011         Change      % Change        2012           2011         Change     % Change
                                                    (Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential            $ 250,757     $ 246,756     $   4,001         1.6     $  566,069     $  556,784     $  9,285         1.7
Commercial               194,032       188,070         5,962         3.2        493,814        470,452       23,362         5.0
Industrial                96,656        98,060        (1,404 )      (1.4 )      278,036        268,501        9,535         3.6
Other retail               6,407        (3,304 )       9,711       293.9          1,125         (8,759 )      9,884       112.8
Total Retail Revenues    547,852       529,582        18,270         3.4      1,339,044      1,286,978       52,066         4.0
Wholesale                 88,784       101,086       (12,302 )     (12.2 )      228,966        257,195      (28,229 )     (11.0 )
Transmission (a)          49,137        39,075        10,062        25.8        144,480        115,411       29,069        25.2
Other                      9,985         8,409         1,576        18.7         25,208         25,179           29         0.1
Total Revenues           695,758       678,152        17,606         2.6      1,737,698      1,684,763       52,935         3.1
OPERATING EXPENSES:
Fuel and purchased
power                    177,506       199,540       (22,034 )     (11.0 )      452,840        486,697      (33,857 )      (7.0 )
Operating and
maintenance              149,001       137,823        11,178         8.1        461,515        412,429       49,086        11.9
Depreciation and
amortization              65,061        72,202        (7,141 )      (9.9 )      204,640        213,551       (8,911 )      (4.2 )
Selling, general and
administrative            54,300        27,499        26,801        97.5        164,346        132,233       32,113        24.3
Total Operating
Expenses                 445,868       437,064         8,804         2.0      1,283,341      1,244,910       38,431         3.1
INCOME FROM OPERATIONS   249,890       241,088         8,802         3.7        454,357        439,853       14,504         3.3
OTHER INCOME
(EXPENSE):
Investment earnings        2,729         2,914          (185 )      (6.3 )        6,456          6,255          201         3.2
Other income               6,115         3,404         2,711        79.6         27,242          8,210       19,032       231.8
Other expense             (6,278 )      (5,470 )        (808 )     (14.8 )      (14,246 )      (13,951 )       (295 )      (2.1 )
Total Other Income         2,566           848         1,718       202.6         19,452            514       18,938         (b)
Interest expense          45,017        43,844         1,173         2.7        131,886        130,681        1,205         0.9
INCOME BEFORE INCOME
TAXES                    207,439       198,092         9,347         4.7        341,923        309,686       32,237        10.4
Income tax expense        66,372        61,700         4,672         7.6        107,156         94,812       12,344        13.0
NET INCOME               141,067       136,392         4,675         3.4        234,767        214,874       19,893         9.3
Less: Net income
attributable to
noncontrolling
interests                  1,786         1,442           344        23.9          5,228          4,212        1,016        24.1
NET INCOME
ATTRIBUTABLE TO WESTAR
ENERGY, INC.             139,281       134,950         4,331         3.2        229,539        210,662       18,877         9.0
Preferred dividends            -           242          (242 )    (100.0 )        1,616            727          889       122.3
NET INCOME
ATTRIBUTABLE TO COMMON
STOCK                  $ 139,281     $ 134,708     $   4,573         3.4     $  227,923     $  209,935     $ 17,988         8.6
BASIC EARNINGS PER
AVERAGE COMMON SHARE
OUTSTANDING
ATTRIBUTABLE TO WESTAR
ENERGY, INC.           $    1.10     $    1.15     $   (0.05 )      (4.3 )   $     1.79     $     1.82     $  (0.03 )      (1.6 )


 _______________


(a) Reflects revenue from an SPP network transmission tariff. For the three and nine months ended September 30, 2012, our SPP network transmission costs were $42.5 million and $124.1 million, respectively. These amounts, less administration costs of $7.0 million and $20.0 million, respectively, were returned to us as revenue. For the three and nine months ended September 30, 2011, our SPP network transmission costs were $33.9 million and $98.6 million, respectively. These amounts, less administration costs of $5.3 million and $13.6 million, respectively, were returned to us as revenue.

(b) Change greater than 1000%.


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Gross Margin

Fuel and purchased power costs fluctuate with electricity sales and unit costs. As permitted by regulators, we adjust our retail prices to reflect changes in the costs of fuel and purchased power. Fuel and purchased power costs for wholesale customers are recovered at prevailing market prices or based on a predetermined formula with a price adjustment approved by FERC. As a result, changes in fuel and purchased power costs are offset in revenues with minimal impact on net income. For this reason, we believe gross margin is useful for understanding and analyzing changes in our operating performance from one period to the next. We calculate gross margin as total revenues, including transmission revenues, less the sum of fuel and purchased power costs and amounts billed by the SPP for network transmission costs. Accordingly, gross margin reflects transmission revenues and costs on a net basis. However, we record transmission costs as operating and maintenance expense on our consolidated statements of income. The following table summarizes our gross margin for the three and nine months ended September 30, 2012 and 2011.

                                 Three Months Ended September 30,                       Nine Months Ended September 30,
                           2012          2011         Change     % Change        2012            2011          Change     % Change
                                                                  (Dollars In Thousands)
REVENUES:
Residential             $ 250,757     $ 246,756     $  4,001         1.6     $   566,069     $   556,784     $  9,285         1.7
Commercial                194,032       188,070        5,962         3.2         493,814         470,452       23,362         5.0
Industrial                 96,656        98,060       (1,404 )      (1.4 )       278,036         268,501        9,535         3.6
Other retail                6,407        (3,304 )      9,711       293.9           1,125          (8,759 )      9,884       112.8
Total Retail Revenues     547,852       529,582       18,270         3.4       1,339,044       1,286,978       52,066         4.0
Wholesale                  88,784       101,086      (12,302 )     (12.2 )       228,966         257,195      (28,229 )     (11.0 )
Transmission               49,137        39,075       10,062        25.8         144,480         115,411       29,069        25.2
Other                       9,985         8,409        1,576        18.7          25,208          25,179           29         0.1
Total Revenues            695,758       678,152       17,606         2.6       1,737,698       1,684,763       52,935         3.1
Less: Fuel and
purchased power expense   177,506       199,540      (22,034 )     (11.0 )       452,840         486,697      (33,857 )      (7.0 )
SPP network
transmission costs         42,516        33,887        8,629        25.5         124,142          98,623       25,519        25.9
Gross Margin            $ 475,736     $ 444,725     $ 31,011         7.0     $ 1,160,716     $ 1,099,443     $ 61,273         5.6

The following table reflects changes in electricity sales for the three and nine months ended September 30, 2012 and 2011. No electricity sales are shown for transmission or other as they are not directly related to the amount of electricity we sell.

                        Three Months Ended September 30,                  Nine Months Ended September 30,
                     2012        2011      Change    % Change         2012           2011      Change    % Change
                                                         (Thousands of MWh)
ELECTRICITY SALES:
Residential          2,270      2,372       (102 )      (4.3 )      5,314           5,579       (265 )      (4.7 )
Commercial           2,215      2,232        (17 )      (0.8 )      5,841           5,825         16         0.3
Industrial           1,437      1,528        (91 )      (6.0 )      4,216           4,304        (88 )      (2.0 )
Other retail            20         21         (1 )      (4.8 )         63              66         (3 )      (4.5 )
Total Retail         5,942      6,153       (211 )      (3.4 )     15,434          15,774       (340 )      (2.2 )
Wholesale            2,094      2,122        (28 )      (1.3 )      5,391           5,808       (417 )      (7.2 )
Total                8,036      8,275       (239 )      (2.9 )     20,825          21,582       (757 )      (3.5 )

. . .

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