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TEG > SEC Filings for TEG > Form 10-Q on 6-Nov-2012All Recent SEC Filings

Show all filings for INTEGRYS ENERGY GROUP, INC.

Form 10-Q for INTEGRYS ENERGY GROUP, INC.


6-Nov-2012

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our Annual Report on Form 10-K for the year ended December 31, 2011.

SUMMARY

We are a diversified energy holding company with regulated natural gas and electric utility operations (serving customers in Illinois, Michigan, Minnesota, and Wisconsin), an approximate 34% equity ownership interest in ATC (a federally regulated electric transmission company operating in Wisconsin, Michigan, Minnesota, and Illinois), and nonregulated energy operations.

                             RESULTS OF OPERATIONS



Earnings Summary



                                          Three Months Ended       Change in       Nine Months Ended       Change in
                                             September 30          2012 Over          September 30         2012 Over
(Millions, except per share amounts)       2012         2011         2011           2012         2011        2011

Natural gas utility operations          $    (14.0 )  $   (20.0 )      (30.0 )%  $     53.4    $   58.4         (8.6 )%
Electric utility operations                   47.2         39.5         19.5 %         92.4        82.8         11.6 %
Electric transmission investment              13.4         12.2          9.8 %         39.8        35.6         11.8 %
Integrys Energy Services' operations          24.2         10.9        122.0 %         35.0        27.7         26.4 %
Holding company and other operations          (5.1 )       (5.7 )      (10.5 )%        (7.2 )     (15.8 )      (54.4 )%

Net income attributed to common
shareholders                            $     65.7    $    36.9         78.0 %   $    213.4    $  188.7         13.1 %

Basic earnings per share                $     0.84    $    0.47         78.7 %   $     2.72    $   2.40         13.3 %
Diluted earnings per share              $     0.83    $    0.47         76.6 %   $     2.69    $   2.39         12.6 %

Average shares of common stock
Basic                                         78.5         78.7         (0.3 )%        78.5        78.6         (0.1 )%
Diluted                                       79.3         79.2          0.1 %         79.3        78.9          0.5 %

Third Quarter 2012 Compared with Third Quarter 2011

Our 2012 third quarter earnings were $65.7 million, compared with 2011 third quarter earnings of $36.9 million. The $28.8 million increase in earnings was driven by:

A $20.7 million after-tax non-cash increase in Integrys Energy Services' margins related to derivative and inventory fair value adjustments.

The $7.1 million after-tax positive impact of rate orders at the natural gas utilities, excluding items directly offset in operating expenses.

A $6.0 million positive quarter-over-quarter impact related to federal health care reform, driven by the reversal in 2012 of $5.9 million of deferred income taxes that had been expensed in prior years due to the implementation of federal health care reform. WPS was authorized recovery of this amount in its 2013 rate case settlement agreement.

These increases were partially offset by an $8.1 million decrease in income from discontinued operations at Integrys Energy Services, primarily related to impairment losses recorded in 2012 related to three generation plants that are held for sale. See Note 5, "Discontinued Operations," for more information.

Nine Months 2012 Compared with Nine Months 2011

Our earnings were $213.4 million during the nine months ended September 30, 2012, compared with $188.7 million during the same period in 2011. The $24.7 million increase in earnings was driven by:

The $20.2 million after-tax positive impact of rate orders at the natural gas utilities, excluding items directly offset in operating expenses.

A $17.1 million after-tax non-cash increase in Integrys Energy Services' margins related to derivative and inventory fair value adjustments.


Table of Contents

A $7.5 million positive period-over-period impact related to federal health care reform, driven by the reversal in 2012 of $5.9 million of deferred income taxes that had been expensed in prior years due to the implementation of federal health care reform. WPS was authorized recovery of this amount in its 2013 rate case settlement agreement.

A $4.8 million after-tax decrease in interest expense, primarily due to the maturity and repayment of $150 million of long-term debt at WPS in August 2011.

The $4.4 million net positive period-over-period impact of tax adjustments recorded in 2011 in connection with a change in tax law in Michigan.

A $4.2 million increase in earnings at the electric transmission investment segment.

A $4.0 million increase from the remeasurement of unrecognized tax benefit liabilities.

These increases were partially offset by:

A $22.1 million after-tax decrease in natural gas utility margins due to lower sales volumes driven by warmer weather, net of decoupling.

An $8.5 million increase in loss from discontinued operations at Integrys Energy Services, primarily related to the impairment losses recorded in 2012 related to three generation plants that are held for sale. See Note 5, "Discontinued Operations," for more information.

A $3.1 million after-tax decrease in Integrys Energy Services' realized retail electric margins, driven by the expiration of several large, lower margin contracts at the end of 2011, and by competitive pressure on per-unit margins.

Regulated Natural Gas Utility Segment Operations



                                            Three Months Ended     Change in      Nine Months Ended     Change in
                                               September 30        2012 Over        September 30        2012 Over
 (Millions, except heating degree days)      2012         2011       2011         2012        2011        2011

Revenues                                  $    220.0    $  239.3        (8.1 )% $ 1,139.4   $ 1,456.7       (21.8 )%
Purchased natural gas costs                     71.9        99.6       (27.8 )%     511.1       811.3       (37.0 )%
Margins                                        148.1       139.7         6.0 %      628.3       645.4        (2.6 )%

Operating and maintenance expense              119.7       121.1        (1.2 )%     382.0       391.7        (2.5 )%
Depreciation and amortization expense           33.2        31.7         4.7 %       98.3        94.2         4.4 %
Taxes other than income taxes                    9.0         8.7         3.4 %       27.1        26.3         3.0 %

Operating income (loss)                        (13.8 )     (21.8 )     (36.7 )%     120.9       133.2        (9.2 )%

Miscellaneous income                             0.1         0.2       (50.0 )%       0.6         1.6       (62.5 )%
Interest expense                               (11.7 )     (11.8 )      (0.8 )%     (35.1 )     (36.4 )      (3.6 )%
Other expense                                  (11.6 )     (11.6 )         - %      (34.5 )     (34.8 )      (0.9 )%

Income (loss) before taxes                $    (25.4 )  $  (33.4 )     (24.0 )% $    86.4   $    98.4       (12.2 )%

Retail throughput in therms
Residential                                     87.2        95.6        (8.8 )%     864.6     1,106.6       (21.9 )%
Commercial and industrial                       36.3        37.1        (2.2 )%     270.7       342.5       (21.0 )%
Other                                           23.3        12.0        94.2 %       56.2        45.7        23.0 %
Total retail throughput in therms              146.8       144.7         1.5 %    1,191.5     1,494.8       (20.3 )%

Transport throughput in therms
Residential                                     15.8        16.6        (4.8 )%     134.2       170.6       (21.3 )%
Commercial and industrial                      299.7       293.2         2.2 %    1,110.7     1,161.2        (4.3 )%
Total transport throughput in therms           315.5       309.8         1.8 %    1,244.9     1,331.8        (6.5 )%

Total throughput in therms                     462.3       454.5         1.7 %    2,436.4     2,826.6       (13.8 )%

Weather
Average heating degree days                      165         183        (9.8 )%     3,367       4,635       (27.4 )%


Table of Contents

Third Quarter 2012 Compared with Third Quarter 2011

Margins

Natural gas utility margins are defined as natural gas utility operating revenues less purchased natural gas costs. Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues since we pass through prudently incurred natural gas commodity costs to our customers in current rates. There was an approximate 30% decrease in the average per-unit cost of natural gas sold during the third quarter of 2012, which had no impact on margins.

Regulated natural gas utility segment margins increased $8.4 million:

Rate increases at PGL and NSG, effective January 21, 2012, and other impacts of rate design, drove an approximate $10 million net increase in margins. See Note 20, "Regulatory Environment," for more information.

Lower sales volumes excluding the impact of weather resulted in a partially offsetting approximate $3 million decrease in margins. Sales volumes were lower due to lower use per residential customer.

Operating Loss

Operating loss at the regulated natural gas utility segment decreased $8.0 million. This decrease was primarily driven by the $8.4 million increase in margins discussed above, partially offset by a $0.4 million increase in operating expenses.

The increase in operating expenses primarily related to:

A $5.3 million increase in natural gas distribution costs. The increase was partially due to additional costs related to compliance work and increased contractor costs associated with the movement of employees to the AMRP project. Costs associated with permits, restoration, and other miscellaneous distribution costs also contributed to the increase.

A $1.5 million increase in depreciation and amortization expense. The increase resulted from higher property and equipment balances, primarily driven by the AMRP.

These increases were substantially offset by:

A $2.4 million decrease in bad debt expense, driven by a new cost of gas component included as part of PGL's and NSG's bad debt expense tracking mechanisms. The change in the bad debt mechanisms was approved in PGL's and NSG's most recent rate orders, effective January 21, 2012. As a result of this component, bad debt expense was partially impacted by lower natural gas costs in 2012 and the decrease in volumes discussed above.

A $2.1 million decrease in energy efficiency program expenses related to WPS's participation in the Focus on Energy Program and MERC's conservation improvement program. Costs for both programs are recovered in rates.

A $1.0 million decrease in customer accounts expense driven by a decrease in maintenance of a customer billing system and a decrease in labor as a result of fewer customer disconnections.

Nine Months 2012 Compared with Nine Months 2011

Margins

Natural gas utility margins are defined as natural gas utility operating revenues less purchased natural gas costs. Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues since we pass through prudently incurred natural gas commodity costs to our customers in current rates. There was an approximate 21% decrease in the average per-unit cost of natural gas sold during 2012, which had no impact on margins.

Regulated natural gas utility segment margins decreased $17.1 million, driven by:

An approximate $37 million net decrease in margins, including the impact of decoupling, due to a 13.8% decrease in volumes sold.

Warmer weather during 2012 drove an approximate $64 million decrease in margins. Heating degree days decreased 27.4%.


Table of Contents

Decoupling impacts at certain natural gas utilities drove an approximate $27 million increase in margins.

Decoupling accruals in 2012 had an approximate $9 million positive impact on the period-over-period variance. Decoupling lessened the negative impact from some of the decreased sales volumes at WPS and MGU through higher future recoveries from customers. This was limited by an $8 million decoupling cap that was reached by WPS during the second quarter of 2012. In addition, although decoupling was implemented to minimize the impact of changes in sales volumes, it does not cover all jurisdictions or customer classes.

Decoupling accruals in 2011 had an approximate $18 million positive impact on the period-over-period variance. Decoupling lessened the positive impact in 2011 from some of the increased sales volumes at PGL, NSG, WPS, and MGU through higher future refunds to customers.

An approximate $7 million decrease in margins related to certain riders at PGL and NSG. Higher regulatory refunds and lower regulatory recoveries under these riders are offset by equal decreases in operating expenses, resulting in no impact on earnings.

We recovered approximately $6 million less for environmental cleanup costs at our former manufactured gas plant sites in 2012. The lower recovery reflects a pass-through to our customers in rates of an environmental settlement received from a potentially responsible party's performance and payment bond. See Note 12, "Commitment and Contingencies," for more information about the manufactured gas plant sites.

We refunded approximately $2 million more to customers under bad debt riders in 2012.

We billed approximately $1 million more to customers for energy efficiency programs in 2012.

An approximate $2 million decrease in margins due to a rider approved through September 30, 2011 for recovery of AMRP costs at PGL. See Note 20, "Regulatory Environment," for more information on this rider.

The decrease in margins was partially offset by an approximate $29 million net increase in margins due to rate orders. See Note 20, "Regulatory Environment," for more information.

The rate increases at PGL and NSG, effective January 21, 2012, and other impacts of rate design, had an approximate $33 million positive impact on margins.

A reduction in rates at WPS, effective January 1, 2012, resulted in an approximate $3 million negative impact on margins. The rate decrease was driven by reduced contributions to the Focus on Energy Program, which promotes residential and small business energy efficiency and renewable energy products. The margin impact from the reduction in contributions is offset by lower operating expenses.

MERC had an approximate $1 million decrease in margins in 2012 driven by the impact of a July 2012 rate order from the MPUC, relative to the impact of 2011 interim rates in effect since February 1, 2011.

Operating Income

Operating income at the regulated natural gas utility segment decreased $12.3 million. This decrease was primarily driven by the $17.1 million decrease in margins discussed above, partially offset by a $4.8 million decrease in operating expenses.

The decrease in operating expenses primarily related to:

A $7.9 million decrease in energy efficiency program expenses related to WPS's participation in the Focus on Energy Program and MERC's conservation improvement program. Costs for both programs are recovered in rates.

An approximate $7 million net decrease due to lower amortization of regulatory assets related to environmental cleanup costs for manufactured gas plant sites and higher amortization of regulatory liabilities related to bad debt riders and enhanced efficiency programs, all at PGL and NSG. Margins decreased by an equal amount, resulting in no impact on earnings.

A $7.0 million decrease in bad debt expense, driven by a new cost of gas component included as part of PGL's and NSG's bad debt expense tracking mechanisms. The change in the bad debt mechanisms was approved in PGL's and NSG's most recent rate orders, effective January 21, 2012. As a result of this component, bad debt expense was partially impacted by lower natural gas costs in 2012 and the decrease in volumes related to warmer weather discussed above.


Table of Contents

A $4.6 million decrease in employee benefit expenses. The primary driver of the decrease was lower postretirement health care expenses, driven by an increase in plan assets due to contributions to our trust.

A $1.6 million decrease in asset usage charges from IBS driven by certain computer hardware that was fully depreciated in 2011.

These decreases were partially offset by:

An $18.6 million increase in natural gas distribution costs. The increase was partially due to additional labor related to compliance work and increased contractor costs associated with the movement of employees to the AMRP project. Costs associated with permits, restoration, and other miscellaneous distribution costs also contributed to the increase.

A $4.1 million increase in depreciation and amortization expense. The increase resulted from higher property and equipment balances, primarily driven by the AMRP.

Regulated Electric Utility Segment Operations



                                   Three Months Ended      Change in      Nine Months Ended     Change in
                                      September 30         2012 Over        September 30        2012 Over
(Millions, except degree days)      2012         2011        2011         2012        2011        2011

Revenues                         $    366.8    $   367.5        (0.2 )% $   985.6   $ 1,005.5        (2.0 )%
Fuel and purchased power costs        160.9        157.5         2.2 %      423.9       428.9        (1.2 )%
Margins                               205.9        210.0        (2.0 )%     561.7       576.6        (2.6 )%

Operating and maintenance
expense                                96.6        102.7        (5.9 )%     296.7       310.4        (4.4 )%
Depreciation and amortization
expense                                22.3         22.0         1.4 %       66.4        66.1         0.5 %
Taxes other than income taxes          11.7         11.9        (1.7 )%      36.3        36.2         0.3 %

Operating income                       75.3         73.4         2.6 %      162.3       163.9        (1.0 )%

Miscellaneous income                    0.9          0.1       800.0 %        1.5         0.6       150.0 %
Interest expense                       (8.9 )       (9.4 )      (5.3 )%     (27.1 )     (33.2 )     (18.4 )%
Other expense                          (8.0 )       (9.3 )     (14.0 )%     (25.6 )     (32.6 )     (21.5 )%

Income before taxes              $     67.3    $    64.1         5.0 %  $   136.7   $   131.3         4.1 %

Sales in kilowatt-hours
Residential                           897.2        882.4         1.7 %    2,359.8     2,381.9        (0.9 )%
Commercial and industrial           2,275.4      2,275.9           - %    6,500.4     6,422.5         1.2 %
Wholesale                           1,587.7      1,257.4        26.3 %    3,838.3     3,455.6        11.1 %
Other                                   8.3          8.4        (1.2 )%      26.8        27.2        (1.5 )%
Total sales in kilowatt-hours       4,768.6      4,424.1         7.8 %   12,725.3    12,287.2         3.6 %

Weather
WPS:
Heating degree days                     252          246         2.4 %      3,864       5,222       (26.0 )%
Cooling degree days                     514          494         4.0 %        789         596        32.4 %

UPPCO:
Heating degree days                     434          346        25.4 %      4,898       5,941       (17.6 )%
Cooling degree days                     236          270       (12.6 )%       335         301        11.3 %

Third Quarter 2012 Compared with Third Quarter 2011

Margins

Electric margins are defined as electric operating revenues less fuel and purchased power costs. Management believes that electric utility margins provide a more meaningful basis for evaluating electric utility operations than electric operating revenues. To the extent changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in operating revenues.


Table of Contents

Regulated electric utility segment margins decreased $4.1 million, driven by:

An approximate $4 million decrease in margins due to impacts from the WPS 2012 rate case re-opener. The PSCW approved a rate increase effective January 1, 2012. The rate increase was driven by anticipated increases in fuel and purchased power costs that did not materialize. Under the fuel rules, WPS deferred a portion of the difference between the costs included in rates and the actual fuel costs. This portion will be refunded to customers. Excluding the impact from fuel and purchased power costs, the 2012 rate case re-opener resulted in a rate decrease. The rate decrease was primarily driven by reduced contributions to the Focus on Energy Program, which promotes residential and small business energy efficiency and renewable energy products. The margin impact from the reduction in contributions to the Focus on Energy Program was offset by lower operating expenses due to reduced payments to the program in 2012.

An approximate $2 million decrease in wholesale margins, driven by a decrease in sales volumes. The decrease was primarily due to a reduction in sales to one large customer.

An approximate $1 million net decrease in margins from residential and commercial and industrial customers due to variances related to sales volumes. A net increase in margins that resulted from an increase in sales volumes was more than offset by impacts from decoupling mechanisms. Although decoupling was implemented to minimize the impact of changes in sales volumes, WPS's decoupling mechanism does not cover all customers or jurisdictions. UPPCO's decoupling mechanism was terminated at the end of 2011.

             A 1.7% increase in sales volumes to residential customers drove an
              approximate $1 million increase in margins.

             A decrease in sales volumes to commercial and industrial customers
              resulted in an approximate $1 million decrease in margins.

             Margins decreased approximately $1 million due to decoupling mechanisms.

These decreases were partially offset by:

An approximate $2 million increase in margins due to a retail electric rate increase at UPPCO, effective January 1, 2012.

A $1.5 million increase in margins due to the reversal of the first quarter of 2012 write-off of UPPCO's net regulatory asset related to its 2010 and 2011 decoupling deferrals. The write-off was reversed due to an MPSC order stating it had the authority to approve UPPCO's decoupling mechanism, as UPPCO's decoupling mechanism was authorized pursuant to an MPSC-approved settlement agreement.

Operating Income

Operating income at the regulated electric utility segment increased $1.9 million. The increase was driven by a $6.0 million decrease in operating expenses, partially offset by the $4.1 million decrease in margins discussed above. The decrease in operating expenses was driven by:

A $2.9 million decrease in customer assistance expense driven by reduced payments to the Focus on Energy Program. These payments are recovered in rates.

A $2.3 million decrease in maintenance expense, mainly due to fewer storms in WPS's service territories as well as fewer repairs at UPPCO's hydroelectric facilities in 2012.

A $0.9 million decrease in bad debt expense, driven by the quarter-over-quarter impact of the 2011 write-off of receivables related to the bankruptcy of an UPPCO retail customer.

These decreases were partially offset by a $1.1 million increase in employee benefit related expenses. The increase was primarily due to the quarter-over-quarter change in the fair value of amounts owed to plan participants under deferred compensation plans.

Other Expense

Other expense decreased $1.3 million, driven by an increase in AFUDC, primarily related to environmental compliance projects at the Columbia plant. Also contributing to the decrease in other expense was a decrease in interest expense, driven by the maturity and repayment of $150 million of long-term debt at WPS in August 2011.


Table of Contents

Nine Months 2012 Compared with Nine Months 2011

Margins

Electric margins are defined as electric operating revenues less fuel and purchased power costs. Management believes that electric utility margins provide a more meaningful basis for evaluating electric utility operations than electric operating revenues. To the extent changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in operating revenues.

Regulated electric utility segment margins decreased $14.9 million, driven by:

An approximate $12 million decrease in margins due to impacts from the WPS 2012 rate case re-opener. The PSCW approved a rate increase effective January 1, 2012. The rate increase was driven by anticipated increases in fuel and purchased power costs that did not materialize. Under the fuel rules, WPS deferred a portion of the difference between the costs included in rates and the actual fuel costs. This portion will be refunded to customers. Excluding the impact from fuel and purchased power costs, the 2012 rate case re-opener resulted in a rate decrease. The rate decrease was primarily driven by reduced contributions to the Focus on Energy Program, which promotes residential and small business energy efficiency and renewable energy products. The margin impact from the reduction in contributions to the Focus on Energy Program was offset by lower operating expenses due to reduced payments to the program in 2012.

An approximate $5 million decrease in wholesale margins, driven by a decrease in sales volumes. The decrease was primarily due to a reduction in sales to one large customer and the loss of wholesale customers.

These decreases were partially offset by:

An approximate $4 million increase in margins due to a retail electric rate increase at UPPCO, effective January 1, 2012.

An approximate $1 million net increase in margins from residential and commercial and industrial customers due to variances related to sales volumes. The margin impact from the period-over-period change in sales volumes was more than offset by the impacts from decoupling mechanisms. Although decoupling was implemented to minimize the impact of changes in sales volumes, WPS's decoupling mechanism does not cover all customers or jurisdictions. UPPCO's decoupling mechanism was terminated at the end of 2011.

A 0.9% decrease in sales volumes to residential customers, driven by . . .

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