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EDE > SEC Filings for EDE > Form 10-K on 21-Feb-2014All Recent SEC Filings

Show all filings for EMPIRE DISTRICT ELECTRIC CO

Form 10-K for EMPIRE DISTRICT ELECTRIC CO


21-Feb-2014

Annual Report


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

Electric Segment

As a traditional, vertically integrated regulated utility, the primary drivers of our electric operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth and usage and (4) general economic conditions. The utility commissions in the states in which we operate, as well as the Federal Energy Regulatory Commission (FERC), set the rates which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily fuel and purchased power) and/or rate relief. We assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary. The effects of timing of rate relief are discussed in detail in Note 3 of "Notes to the Consolidated Financial Statements" under Item 8. Of the factors driving revenues, weather has the greatest short-term effect on the demand for electricity for our regulated business. Very hot summers and very cold winters increase electric demand, while mild weather


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reduces demand. Residential and commercial sales are impacted more by weather than industrial sales, which are mostly affected by business needs for electricity and by general economic conditions.

Customer growth, which is the growth in the number of customers, contributes to the demand for electricity. We expect our electric customer and sales growth to be less than 1.0% annually over the next several years. Our electric customer growth for the year ended December 31, 2013 was 0.5%. We define electric sales growth to be growth in kWh sales period over period excluding the estimated impact of weather. The primary drivers of electric sales growth are customer growth, customer usage and general economic conditions.

The primary drivers of our electric operating expenses in any period are:
(1) fuel and purchased power expense, (2) operating maintenance and repairs expense, including repairs following severe weather and plant outages, (3) taxes and (4) non-cash items such as depreciation and amortization expense. We have a fuel cost recovery mechanism in all of our jurisdictions, which significantly reduces the impact of fluctuating fuel and purchased power costs on our net income.

Gas Segment

The primary drivers of our gas operating revenues in any period are:
(1) rates we can charge our customers, (2) weather, (3) customer growth and usage, (4) the cost of natural gas and interstate pipeline transportation charges and (5) general economic conditions. The MPSC sets the rates which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily commodity natural gas) and/or rate relief. We assess the need for rate relief and file for such relief when necessary. A Purchased Gas Adjustment (PGA) clause is included in our gas rates, which allows us to recover our actual cost of natural gas from customers through rate changes, which are made periodically (up to four times) throughout the year in response to weather conditions, natural gas costs and supply demands. Weather affects the demand for natural gas. Very cold winters increase demand for gas, while mild weather reduces demand. Due to the seasonal nature of the gas business, revenues and earnings are typically concentrated in the November through March period, which generally corresponds with the heating season.

Customer growth, which is the growth in the number of customers, contributes to the demand for gas. Our annual customer growth is calculated by comparing the number of customers at the end of a year to the number of customers at the end of the prior year. Our gas segment customer contraction for the year ended December 31, 2013 was 0.1%, which we believe was due to depressed economic conditions. We expect gas customer growth to be flat during the next several years. We define gas sales growth to be growth in mcf sales excluding the impact of weather. The primary drivers of gas sales growth are customer growth and general economic conditions.

The primary driver of our gas operating expense in any period is the price of natural gas. However, because gas purchase costs for our gas utility operations are normally recovered from our customers, any change in gas prices does not have a corresponding impact on income unless such costs are deemed imprudent or cause customers to reduce usage.

Earnings

For the year ended December 31, 2013, basic and diluted earnings per weighted average share of common stock were $1.48 on $63.4 million of net income compared to $1.32 on $55.7 million of net income for the year ended December 31, 2012. Increased electric gross margins (defined as electric revenues less fuel and purchased power costs) positively impacted net income for 2013 as compared to 2012, reflecting an increase in electric revenues of approximately $25.7 million, mainly due to increased electric rates for our Missouri customers effective April 1, 2013. Improved electric customer counts, favorable winter weather and increased AFUDC due to higher levels of construction activity during 2013 also positively


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impacted results. Increased regulatory operating expense and depreciation and amortization expense negatively impacted 2013 results.

The table below sets forth a reconciliation of basic and diluted earnings per share between 2012 and 2013, which is a non-GAAP presentation. The economic substance behind our non-GAAP earnings per share (EPS) measure is to present the after tax impact of significant items and components of the statement of income, including segment revenues and operating expenses, on a per share basis before the impact of additional stock issuances. The dilutive effect of additional shares issued included in the table reflects the estimated impact of all shares issued during the period.

We believe this presentation is useful to investors because the statement of income does not readily show the EPS impact of the various components, including the effect of new stock issuances. This could limit the readers' understanding of the reasons for the EPS change from the previous year's EPS. This information is useful to management, and we believe this information is useful to investors, to better understand the reasons for the fluctuation in EPS between the prior and current years on a per share basis.

In addition, although a non-GAAP presentation, we believe the presentation of gross margin (in the table below and elsewhere in this report) is useful to investors and others in understanding and analyzing changes in our electric operating performance from one period to the next, and have included the analysis as a complement to the financial information we provide in accordance with GAAP. This reconciliation and margin information may not be comparable to other companies' presentations or more useful than the GAAP presentation included in the statements of income or elsewhere in this report. We also note that this presentation does not purport to be an alternative to earnings per share determined in accordance with GAAP as a measure of operating performance or any other measure of financial performance presented in accordance with GAAP. Management compensates for the limitations of using non-GAAP financial measures by using them to supplement GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone.

                Earnings Per Share - 2012                  $  1.32
                Revenues
                Electric segment                              0.38
                Gas segment                                   0.15
                Other segment                                 0.02


                Total Revenue                                 0.55
                Electric fuel and purchased power             0.05
                Cost of natural gas sold and transported     (0.11 )


                Gross Margin                                  0.49
                Operating - electric segment                 (0.15 )
                Operating - gas segment                      (0.01 )
                Operating - other segment                    (0.01 )
                Maintenance and repairs                      (0.01 )
                Depreciation and amortization                (0.13 )
                Loss on plant disallowance                   (0.03 )
                Other taxes                                  (0.05 )
                AFUDC                                         0.06
                Change in effective income tax rates          0.02
                Other income and deductions                  (0.02 )


                Earnings Per Share - 2013                  $  1.48


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Fourth Quarter Results

Earnings for the fourth quarter of 2013 were $15.2 million, or $0.35 per share, as compared to $9.6 million, or $0.23 per share, in the fourth quarter of 2012. Electric segment gross margins increased during the quarter ending December 31, 2013 compared to the 2012 quarter, reflecting the impact of colder weather experienced during the fourth quarter of 2013 as compared to the same period in 2012 and the April 2013 Missouri electric rate increase, partially offset by increased electric operating and maintenance expenses.

2013 Activities

Regulatory Matters

On December 3, 2013, we filed a request with the Arkansas Public Service Commission for changes in rates for our Arkansas electric customers. We are seeking an annual increase in total revenue of approximately $2.2 million, or approximately 18%. The rate increase was requested to recover costs incurred to ensure continued reliable service for our customers, including capital investments, operating systems replacement costs and ongoing increases in other operation and maintenance expenses and capital costs.

On February 22, 2013, we filed a Nonunanimous Stipulation and Agreement (Agreement) with the Missouri Public Service Commission (MPSC) which issued an order approving the Agreement on February 27, 2013, effective March 6, 2013. The Agreement provided for an annual increase in base revenues for our Missouri electric customers in the amount of approximately $27.5 million, effective April 1, 2013, and the continuation of the current fuel adjustment mechanism.

On May 18, 2012, we filed a request with the Federal Energy Regulatory Commission (FERC) to implement a cost-based transmission formula rate (TFR). On June 13, 2013, we, the Kansas Corporation Commission and the cities of Monett, Mt. Vernon and Lockwood, Missouri and Chetopa, Kansas, filed a unanimous Settlement Agreement (Agreement) with the FERC. The Agreement includes a TFR that establishes an ROE of 10.0%. The FERC conditionally approved the Agreement on November 18, 2013, and we made a compliance filing with the FERC on December 18, 2013 in connection with this conditional approval. Final FERC action on our compliance filing is pending.

For additional information on all these cases, see Note 3 of "Notes to Consolidated Financial Statements" under Item 8 for information regarding regulatory matters.

Integrated Resource Plan

We filed our Integrated Resource Plan (IRP) with the MPSC on July 1, 2013. The IRP analysis of future loads and resources is normally conducted once every three years. Our IRP supports our Compliance Plan discussed in Note 11 of "Notes to Consolidated Financial Statements" under Item 8.

As part of our IRP, we agreed to introduce additional demand-side management programs to help our customers use energy more efficiently. On October 30, 2013 we filed a request with the MPSC to implement a portfolio of demand-side management programs under the Missouri Energy Efficiency Investment Act (MEEIA). The request, subject to regulatory approval, would implement new energy efficiency programs for customers in 2014. The request also includes a Demand-Side Program Investment Mechanism (DSIM) that would be added to monthly customer bills if approved by the MPSC. The DSIM charge is designed to offset the financial costs associated with the programs. On January 14, 2014, the MPSC granted a motion to suspend the procedural schedule to allow the parties to the case more time to hold additional technical conferences and perform additional financial analysis on our proposed demand-side management portfolio.


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Financings

On October 30, 2012, we entered into a Bond Purchase Agreement for a private placement of $30.0 million of 3.73% First Mortgage Bonds due May 30, 2033 and $120.0 million of 4.32% First Mortgage Bonds due May 30, 2043. The delayed settlement of both series of bonds occurred on May 30, 2013. Interest is payable semi-annually on the bonds on each May 30 and November 30, commencing November 30, 2013.

A portion of the proceeds from the above sale of bonds was used to redeem all $98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013. The remaining proceeds were used for general corporate purposes.

For additional information, see Note 6 of "Notes to Consolidated Financial Statements" under Item 8.

RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the years 2013, 2012 and 2011.

The following table represents our results of operations by operating segment for the applicable years ended December 31 (in millions):

                                       2013     2012     2011
                         Electric     $ 58.6   $ 52.6   $ 50.6
                         Gas             2.3      1.3      2.7
                         Other           2.5      1.8      1.6


                         Net income   $ 63.4   $ 55.7   $ 54.9

Electric Segment

Overview

    Our electric segment income for 2013 was $58.6 million as compared to
$52.6 million and $50.6 million for 2012 and 2011, respectively.

    Electric operating revenues comprised approximately 89.9% of our total
operating revenues during 2013. Electric operating revenues for 2013, 2012, and
2011 were comprised of the following:

                                              2013     2012     2011
                   Residential                 42.6 %   42.2 %   42.4 %
                   Commercial                  30.4     31.2     30.1
                   Industrial                  15.1     15.5     15.1
                   Wholesale on-system          3.7      3.6      3.7
                   Wholesale off-system         2.9      3.1      4.5
                   Miscellaneous sources*       2.8      2.7      2.6
                   Other electric revenues      2.5      1.7      1.6


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    *


Primarily other public authorities


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Gross Margin

    The table below represents our electric gross margins for the years ended
December 31 (in millions).

                                                        2013      2012      2011
      Electric segment revenues                        $ 536.4   $ 510.7   $ 524.3
      Fuel and purchased power                           175.4     178.9     200.3


      Electric segment gross margins                   $ 361.0   $ 331.8   $ 324.0

Margin as % of total electric segment revenues 67.3 % 65.0 % 61.8 %

As shown in the table above, electric segment gross margin, defined as electric revenues less fuel and purchased power costs, increased approximately $29.2 million during 2013 as compared to 2012. Increased electric rates for our Missouri customers, an increase in average electric customer counts and colder weather in the first and fourth quarters of 2013 positively impacted revenues and gross margin during 2013. These increases were partially offset by a change in our unbilled revenue estimate in the third quarter of 2012.

The electric gross margin increased approximately $7.8 million during 2012 as compared to 2011. Decreased sales demand, resulting from mild winter weather in the first quarter of 2012 and less favorable weather in the third quarter of 2012 as compared to the same period in 2011, negatively impacted revenues and margins. This negative impact was partially offset by a full year of electric customer rate increases for our Missouri customers and improving electric customer counts as customers continued to return to the system following the May 2011 tornado. The change in our unbilled revenue estimate in the third quarter of 2012 also positively impacted gross margin. Decreases in non-volume fuel expenses also increased margin by approximately $4.3 million over 2011.

Sales and Revenues

    The amounts and percentage changes from the prior periods in kilowatt-hour
("kWh") sales by major customer class for on-system and off-system sales were as
follows:

                                                    kWh Sales
                                                  (in millions)
 Customer Class     2013        2012       % Change(1)      2012        2011       % Change(1)
 Residential        1,936.6     1,850.8             4.6 %   1,850.8     1,982.7            (6.7 )%
 Commercial         1,541.7     1,558.3            (1.1 )   1,558.3     1,576.3            (1.1 )
 Industrial         1,015.5     1,028.4            (1.3 )   1,028.4     1,022.8             0.6
 Wholesale
 on-system            343.1       353.1            (2.8 )     353.1       364.9            (3.2 )
 Other(2)             129.4       124.2             4.2       124.2       128.7            (3.5 )


 Total
 on-system
 sales              4,966.3     4,914.8             1.0     4,914.8     5,075.4            (3.2 )
 Off-system           654.0       704.0            (7.1 )     704.0       740.0            (4.9 )


 Total KWh
 Sales              5,620.3     5,618.8             0.0     5,618.8     5,815.4            (3.4 )


--------------------------------------------------------------------------------
    (1)


Percentage changes are based on actual kWh sales and may not agree to the rounded amounts shown above.

(2)
Other kWh sales include street lighting, other public authorities and interdepartmental usage.

KWh sales for our on-system customers increased slightly during 2013 as compared to 2012 primarily due to increased demand due to colder temperatures in the first and fourth quarters of 2013 as compared to the same periods in 2012. Residential kWh sales, the most weather sensitive class, increased 4.6% primarily due to these weather impacts and an increase in the average residential customer count.


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Commercial sales decreased 1.1% primarily due to a net unbilled sales adjustment recorded in 2012. Industrial sales decreased 1.3% during 2013 as compared to 2012 due to operating reductions by several large industrial customers. On-system wholesale kWh sales decreased during 2013 as compared to 2012 reflecting the closure of a large dairy facility in Monett, Missouri. Total heating degree days (the sum of the number of degrees that the daily average temperature for each day during that period was below 65 F) for 2013 were 31.7% more than 2012 and 5.0% more than the 30-year average. Total cooling degree days (the cumulative number of degrees that the average temperature for each day during that period was above 65 F) for 2013 were 19.7% less than 2012 although they were 2.1% more than the 30-year average. The weather was unseasonably hot in June and July of 2012.

KWh sales for our on-system customers decreased approximately 3.2% during 2012 as compared to 2011 primarily due to decreased demand due to milder winter temperatures in 2012 as compared to 2011 and a trend toward more efficient utilization of electric power by our customers. Residential and commercial kWh sales decreased primarily due to these weather impacts and efficient utilization of electric power. Industrial sales increased slightly during 2012 as compared to 2011. On-system wholesale kWh sales decreased during 2012 as compared to 2011 reflecting the milder weather in 2012.

The amounts and percentage changes from the prior period's electric segment operating revenues by major customer class for on-system and off-system sales were as follows:

                                           Electric Segment Operating Revenues
                                                     ($ in millions)
Customer Class             2013      2012      % Change(1)     2012      2011      % Change(1)
Residential               $ 227.7   $ 214.5             6.1 % $ 214.5   $ 221.7            (3.2 )%
Commercial                  162.4     158.8             2.3     158.8     157.4             0.9
Industrial                   80.5      78.8             2.2      78.8      78.9            (0.2 )
Wholesale on-system          20.0      18.6             8.0      18.6      19.1            (3.1 )
Other(2)                     15.0      14.0             7.0      14.0      13.9             0.7


Total on-system
revenues                    505.6     484.7             4.3     484.7     491.0            (1.3 )
Off-system                   15.5      15.7            (1.3 )    15.7      23.3           (32.6 )


Total revenues from KWh
sales                       521.1     500.4             4.1     500.4     514.3            (2.7 )
Miscellaneous
revenues(3)                  13.2       8.5            55.2       8.5       8.2             4.0


Total electric
operating revenues        $ 534.3   $ 508.9             5.0   $ 508.9   $ 522.5            (2.6 )
Water revenues                2.1       1.8            19.2       1.8       1.8             1.2


Total Electric Segment
Operating Revenues        $ 536.4   $ 510.7             5.0   $ 510.7   $ 524.3            (2.6 )


--------------------------------------------------------------------------------
    (1)


Percentage changes are based on actual revenues and may not agree to the rounded amounts shown above.

(2)
Other operating revenues include street lighting, other public authorities and interdepartmental usage.

(3)
Miscellaneous revenues include transmission service revenues, late payment fees, renewable energy credit sales, rent, etc.

Revenues for our on-system customers increased approximately $20.9 million (4.3%) during 2013 as compared to 2012. Rate changes, primarily the April 2013 Missouri rate increase, contributed an estimated $24.6 million to revenues. Weather and other related factors increased revenues an estimated $3.1 million in 2013 as compared to 2012. Improved customer counts increased revenues an estimated $2.7 million. These revenue increases were partially offset by a $6.1 million decrease in fuel recovery revenue (and corresponding reduction in fuel expenses, resulting in no net effect on gross margin) from Missouri customers during 2013 as compared to 2012. The change in our unbilled revenue estimate recorded in the third quarter of 2012, as mentioned below, negatively impacted revenues as compared to 2012, making up the remainder of the change.


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Revenues for our on-system customers decreased approximately $6.4 million (1.3%) during 2012 as compared to 2011. Weather and other related factors decreased revenues an estimated $25.6 million in 2012 as compared to 2011, primarily due to mild weather in the first quarter of 2012 and less favorable weather in the third quarter of 2012 as compared to the same period in 2011. Rate changes, primarily the June 2011 Missouri rate increase, the March 2011 Oklahoma rate increase, the January 2012 Kansas rate increase and the April 2011 Arkansas rate increase, contributed an estimated $12.0 million to revenues. Improved customer counts increased revenues an estimated $4.2 million. Additionally, a $3.4 million period over period change in our estimate of unbilled revenues during the third quarter of 2012 contributed $3.0 million to revenues.

On-system revenues increased in all classes during 2013 primarily due to the April 2013 Missouri rate increase.

Residential revenues decreased during 2012 due to the milder weather and efficient utilization of electric power. Commercial revenues increased primarily due to the Missouri, Kansas, Oklahoma and Arkansas rate increases. Industrial revenues decreased slightly.

Off-System Electric Transactions

In addition to sales to our own customers, we also sell power to other utilities as available, including through the Southwest Power Pool (SPP) energy imbalance services (EIS) market. See "- Markets and Transmission" below. The majority of our off-system sales margins are included as a component of the fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictions and our transmission rider in our Arkansas jurisdiction and generally adjust the fuel and purchased power expense. As a result, nearly all of the off-system sales margin flows back to our on-system customers and has little effect on net income.

Off-system sales and revenues decreased during 2013 as compared to 2012 mainly due to low third quarter demand in the SPP market.

Off-system sales and revenues decreased during 2012 as compared to 2011 primarily due to the milder weather in 2012 as compared to 2011, as well as lower gas and purchased power prices.

Miscellaneous Revenues

Our miscellaneous revenues increased approximately $4.7 million during 2013 as compared to 2012 and approximately $0.3 million in 2012 as compared to 2011, primarily due to increased Southwest Power Pool (SPP) transmission revenues. These miscellaneous revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.


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Operating Revenue Deductions - Fuel and Purchased Power

    The table below is a reconciliation of our actual fuel and purchased power
expenditures (netted with the regulatory adjustments) to the fuel and purchased
power expense shown on our statements of income for 2013, 2012 and 2011.

(in millions)                                                 2013      2012      2011
Actual fuel and purchased power expenditures                 $ 182.1   $ 173.6   $ 196.5
Missouri fuel adjustment recovery(1)                            (2.7 )     3.4       7.3
Missouri fuel adjustment deferral(2)                            (0.6 )     5.3      (2.7 )
Kansas and Oklahoma regulatory adjustments(2)                   (0.3 )     1.0      (0.6 )
SWPA amortization(3)                                            (2.8 )    (2.8 )    (1.5 )
Unrealized (gain)/loss on derivatives                           (0.3 )    (1.6 )     1.3


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