10-24-13 5:00 AM EDT | Email Article

Company reports diluted earnings per share of $0.40 for third quarter 2013

Reaffirms full year 2013 guidance of $2.45 - $2.60 per diluted share

Declares a quarterly dividend of $0.38 per share, payable December 31, 2013

SIOUX FALLS, S.D., Oct. 24, 2013 /PRNewswire/ -- NorthWestern Corporation d/b/a NorthWestern Energy (NYSE: NWE) reported financial results for the quarter ended September 30, 2013.  Net income was $15.6 million or $0.40 per diluted share, for the quarter ended September 30, 2013, compared with a net loss of $3.8 million, or a loss of $0.10 per diluted share, for the quarter ended September 30, 2012.  The loss in the third quarter last year was primarily related to the impairment of the Mountain States Transmission Intertie (MSTI) project and the revenue deferral due to the FERC ALJ's nonbinding decision regarding revenue allocation at our Dave Gates Generating Station (DGGS).  

"We are very excited about our recently announced $900 million hydro acquisition and the long-term benefits it will provide all of our stakeholders for decades to come. There is no resource better suited to serve the needs of our Montana customers. We continue to be keenly focused on our day-to-day responsibilities of delivering safe and reliable services to our customers while delivering a fair return to our investors," said Bob Rowe, Chief Executive Officer.  "This was another solid quarter demonstrating that commitment."

Summary Financial Results

Three Months Ended

September 30,


Nine Months Ended

September 30,

(in thousands, except per share amounts)

2013


2012


2013


2012

Total Revenues

$

262,248



$

235,866



$

835,429



$

789,569


Cost of Sales

104,298



93,061



343,407



327,884


Gross Margin

157,950



142,805



492,022



461,685


Operating Expenses








Operating, general and administrative

72,540



63,056



208,741



195,725


MSTI impairment



24,039





24,039


Property and other taxes

25,956



24,796



77,525



74,395


Depreciation

28,053



26,505



84,685



79,364


Total Operating Expenses

126,549



138,396



370,951



373,523


Operating Income

31,401



4,409



121,071



88,162


Interest Expense, net

(17,056)



(17,743)



(50,976)



(49,598)


Other Income

3,117



974



6,760



3,134


Income (Loss) Before Income Taxes

17,462



(12,360)



76,855



41,698


Income Tax (Expense) Benefit

(1,815)



8,588



(8,965)



(1,989)


Net Income (Loss)

$

15,647



$

(3,772)



$

67,890



$

39,709


Average Common Shares Outstanding

38,459



37,201



37,983



36,723


Basic Earnings (Loss) per Average Common Share

$

0.41



$

(0.10)



$

1.79



$

1.09


Diluted Earnings (Loss) per Average Common Share

$

0.40



$

(0.10)



$

1.78



$

1.08


Dividends Declared per Common Share

$

0.38



$

0.37



$

1.14



$

1.11


Significant items during the third quarter

  • Entered into an agreement with PPL Montana, LLC (PPL Montana), a wholly owned subsidiary of PPL Corporation to purchase PPL Montana's hydro-electric generating facilities and associated assets located in Montana, which includes approximately 633 megawatts of hydro-electric generation capacity, for a purchase price of $900 million (Hydro Transaction); and
  • An improvement in net income of approximately $19.4 million as compared with the same period in 2012, due primarily to:
    • $15.1 Million - Improvement in gross margin primarily due to:
      • Higher FERC DGGS revenue due to $11.4 million deferral recorded in the third quarter of 2012 related to the FERC ALJ nonbinding decision;
      • Increased recovery of electric Demand Side Management (DSM) lost revenues;
      • The acquisition of the Spion Kop wind farm in the fourth quarter of 2012;
      • An increase in natural gas production margin due to the full period effect of the acquisition of production assets in the third quarter of 2012;
      • An increase in Montana natural gas delivery rates implemented in April 2013; and
      • An increase in property taxes included in a tracker.
      • These increases were partly offset by a decrease in electric retail volumes due to cooler summer weather and less customer irrigation, lower revenues for operating expenses recovered in trackers and a decrease in electric transmission revenues due primarily to the outage at Colstrip Unit 4.
    • $24.0 Million - Improvement from the absence of the MSTI impairment in the third quarter 2012.
    • $0.6 Million - Reduced interest expense due to higher interest on DGGS accrued during the third quarter 2012 partially offset by higher debt outstanding in 2013.
    • $2.1 Million - Increased other income due to the change in value of deferred shares held in trust for non-employee directors deferred compensation (offset in expense). 

These improvements were partially offset by:

    • $9.4 Million - Increased operating, general and administrative expenses primarily due to:
      • Distribution System Infrastructure Project (DSIP) expense;
      • Hydro Transaction legal and professional fees;
      • Increased labor costs;
      • Higher plant operator costs;
      • Non-employee directors deferred compensation due to changes in our stock price (offset in other income);  and
      • Higher bad debt expense.
      • These increases were partly offset by decreased pension expense (net of higher other employee benefit costs) and lower operating expenses recovered in trackers.
    • $1.2 Million - Higher property and other taxes
    • $1.6 Million - Increased depreciation expense
    • $10.4 Million - Increased income tax expense

Reconciliation of Primary Changes from 2012 to 2013









Three Months Ended Sept. 30,



Nine Months Ended Sept. 30,



Pre-tax

Net

EPS



Pre-tax

Net

EPS


($millions, except EPS)

Income

Income(1)

Diluted



Income

Income(1)

Diluted


2012 reported

$

(12.4)


$

(3.8)


$

(0.10)




$

41.7


$

39.7


$

1.08












Gross Margin










DGGS

10.2


6.3


0.16




5.1


3.1


0.08



DSM lost revenues

5.0


3.1


0.08








Spion Kop

1.6


1.0


0.03




4.6


2.8


0.07



Natural gas production

1.2


0.7


0.02




7.0


4.3


0.11



Montana natural gas rate increase

1.2


0.7


0.02




2.1


1.3


0.03



Property tax trackers

0.9


0.6


0.02




1.9


1.2


0.03



Electric retail volumes

(3.5)


(2.2)


(0.06)




(0.5)


(0.3)


(0.01)



Operating expenses recovered in trackers

(1.9)


(1.2)


(0.03)




(2.4)


(1.5)


(0.04)



Electric transmission revenue

(0.4)


(0.2)


(0.01)




3.6


2.3


0.06



Natural gas retail volumes






3.4


2.1


0.06



Natural gas transportation capacity






1.1


0.7


0.02



Electric QF supply costs






1.0


0.6


0.02



Other

0.8


0.5


0.01




3.6


2.2


0.06



Subtotal - Gross Margin

15.1


9.3


0.24




30.5


18.8


0.49


OG&A Expense










DSIP expenses

(3.3)


(2.0)


(0.05)




(8.8)


(5.4)


(0.14)



Hydro Transaction related legal and professional fees

(2.8)


(1.7)


(0.05)




(3.3)


(2.0)


(0.05)



Labor

(1.7)


(1.0)


(0.03)




(2.8)


(1.7)


(0.04)



Plant operator costs

(1.6)


(1.0)


(0.03)




(3.0)


(1.8)


(0.05)



Nonemployee directors deferred compensation

(1.5)


(0.9)


(0.02)




(2.6)


(1.6)


(0.04)



Bad debt expense

(0.6)


(0.4)


(0.01)




(1.0)


(0.6)


(0.02)



Pension and employee benefits

3.1


1.9


0.05




10.7


6.6


0.17



Operating expenses recovered in trackers

1.9


1.2


0.03




2.4


1.5


0.04



Natural gas production






(1.6)


(1.0)


(0.03)



Other

(2.9)


(1.8)


(0.05)




(3.0)


(1.8)


(0.05)



Subtotal - OG&A Expense

(9.4)


(5.7)


(0.16)




(13.0)


(7.8)


(0.21)


Other










MSTI Impairment

24.0


14.8


0.40




24.0


14.8


0.40



Depreciation expense

(1.6)


(1.0)


(0.03)




(5.3)


(3.3)


(0.09)



Property and other taxes

(1.2)


(0.7)


(0.02)




(3.1)


(1.9)


(0.05)



Interest expense

0.6


0.4


0.01




(1.4)


(0.9)


(0.02)



Other Income

2.1


1.3


0.03




3.7


2.2


0.06


Income tax and other items










Flow-through repairs deductions


1.3


0.03





3.4


0.09



Flow-through of state bonus depreciation deduction

0.5


0.01





1.1


0.03



Production tax credits


0.5


0.01





2.1


0.06



Prior year permanent return to accrual adjustments

(1.9)


(0.05)





(2.4)


(0.06)



Recognition of state NOL benefit / valuation allowance release

(0.1)






(0.1)




State income tax and other, net


(0.3)


(0.01)





1.2


0.03



Impact of higher share count



(0.02)






(0.07)



All other, net

0.3


1.0


0.06




(0.2)


1.0


0.04



Total EPS impact of above items



0.50






0.70



2013 reported

$

17.5


$

15.6


$

0.40




$

76.9


$

67.9


$

1.78


(1) Income Tax Benefit (Expense) calculation on reconciling items assumes effective tax rate of 38.5%.

Significant Drivers

Gross Margin

Consolidated gross margin for the quarter ended September 30, 2013 was $158.0 million compared with $142.9 million for the same period of 2012.  Consolidated gross margin increased $15.1 million primarily due to the following:

  • Higher DGGS revenue primarily due to the inclusion in 2012 results of the deferral of $11.4 million related to the FERC ALJ nonbinding decision;
  • A $5.8 million increase in electric DSM lost revenues recovered through our supply trackers related to efficiency measures implemented by customers, offset in part by a decrease of $0.8 million related to natural gas DSM lost revenues. The three months ended September 30, 2013 included recognition of approximately $4.6 million in revenues related to prior periods (including $2.3 million related to calendar year 2012) that we had previously deferred pending approval of our electric tracker filing;
  • Gross margin from the acquisition of the Spion Kop wind farm in the fourth quarter of 2012;
  • An increase in natural gas production margin, primarily due to the full period effect of the acquisition of natural gas production assets in the third quarter of 2012;
  • An increase in Montana natural gas delivery rates implemented in April 2013; and
  • An increase in property taxes included in a tracker.

These increases were partly offset by:

  • A decrease in electric retail volumes due primarily to cooler summer weather and reduced customer irrigation;
  • Lower revenues for operating expenses recovered in trackers, primarily related to customer efficiency programs; and
  • A decrease in electric transmission revenues due primarily to an outage at Colstrip Unit 4 during the third quarter of 2013.  We expect the outage at Colstrip Unit 4 to have a negative impact on transmission revenues for the remainder of 2013.

Consolidated gross margin for the nine months ended September 30, 2013 was $492.1 million compared with $461.6 million for the same period of 2012.

Operating, General and Administrative Expenses

Consolidated operating, general and administrative expenses were $72.5 million for the quarter ended September 30, 2013 as compared with $63.1 million during the same period of 2012.  The increase in operating, general and administrative expenses of $9.4 million was primarily due to:

  • Incremental operating and maintenance costs related to the phase-in of DSIP during 2012 and 2011 were deferred in accordance with the Montana Public Service Commission's (MPSC) approval of an accounting order. Incremental DSIP costs for 2013 forward are being expensed as incurred and the amounts previously deferred are being amortized over five years. During the third quarter of 2013 we amortized approximately $0.8 million and incurred incremental DSIP expenses of approximately $2.5 million;
  • Legal and professional fees associated with the Hydro Transaction;
  • Increased labor costs due primarily to compensation increases and a larger number of employees;
  • Higher plant operator costs due primarily to the Spion Kop acquisition and higher maintenance and outage costs at Colstrip Unit 4;
  • Non-employee directors deferred compensation increased as compared to the prior year, primarily due to changes in our stock price. Directors may defer their board fees into deferred shares held in a rabbi trust. If the market value of our stock goes up, deferred compensation expense increases; however, we  account for the deferred shares as trading securities and their increase in value is reflected in other income with no impact on net income; and
  • Higher bad debt expense.

These increases were partly offset by:

  • Decreased pension expense, offset in part by higher other employee benefit costs. Our Montana pension costs are included in expense on a pay as you go (cash funding) basis. We received a pension accounting order from the MPSC in 2008, which based our Montana pension expense on an average of our funding requirements for calendar years 2005 through 2012 in order to smooth the impact of increased cash funding. We expect our 2013 Montana pension expense to be approximately $17.0 million to $20.0 million lower than 2012 on an annualized basis due to the expiration of this order and our current cash funding estimate; and
  • Lower operating expenses recovered in trackers, primarily related to customer efficiency programs.

Consolidated operating, general and administrative expenses were $208.7 million for the nine months ended September 30, 2013 as compared with $195.7 million during the same period of 2012. 

Property and Other Taxes

Property and other taxes were $26.0 million for the quarter ended September 30, 2013, as compared with $24.8 million in the same period of 2012.  This increase was primarily due to higher estimated property valuations in Montana and plant additions. We estimate property taxes throughout each year and update to the actual expense when we receive our Montana property tax bills in November.

Property and other taxes were $77.5 million for the nine months ended September 30, 2013, as compared with $74.4 million in the same period of 2012.

Depreciation Expense

Depreciation expense was $28.1 million for the quarter ended September 30, 2013, as compared with $26.5 million in the same period of 2012. This reflects an increase in depreciation expense due to plant additions, offset in part by a reduction in depreciation rates of approximately $1.5 million as a result of new depreciation studies conducted by an independent consultant and implemented during the second quarter of 2013. These studies reflect longer asset lives on our electric and natural gas assets in Montana, and electric assets in South Dakota. We expect depreciation expense to be reduced due to the change in rates by approximately $1.5 million for the remainder of 2013.

Depreciation expense was $84.7 million for the nine months ended September 30, 2013, as compared with $79.4 million in the same period of 2012.

Interest Expense

Consolidated interest expense was $17.1 million for the quarter ended September 30, 2013 as compared with $17.7 million during the same period of 2012.  This decrease was primarily due to higher interest accrued on DGGS deferred revenues in 2012 due to the FERC ALJ nonbinding decision as discussed above partially offset by higher debt outstanding in 2013.

Consolidated interest expense was $51.0 million for the nine months ended September 30, 2013 as compared with $49.6 million during the same period of 2012.

Income Tax Expense

Consolidated income tax expense for the quarter ended September 30, 2013 was $1.8 million as compared with a $8.6 million benefit in the same period of 2012.  Our effective tax rate for the quarter ended September 30, 2013 was 10.4% as compared with (69.5)% for the same period of 2012.  The effective tax rate differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through federal and state tax benefit of repairs deductions, state tax benefit of bonus depreciation deductions and production tax credits.

Consolidated income tax expense for the nine months ended September 30, 2013 was $9.0 million as compared with $2.0 million in same period of 2012.  The effective tax rate for the nine months ended September 30, 2013 was 11.7% as compared with 4.8% for the same period of 2012.

The following table summarizes the significant differences from the federal statutory rate, which result in reduced income tax expense:

(in millions)

ThreeMonths Ended

September 30,


Nine Months Ended

September 30,


2013


2012


2013


2012

Income (Loss) Before Income Taxes

$

17.5



$

(12.4)



$

76.9



$

41.7










Income tax calculated at 35% federal statutory rate

6.1



(4.3)



26.9



14.6










Permanent or flow through adjustments:








Flow-through repairs deductions

(3.1)



(1.8)



(12.9)



(9.5)


Flow-through of state bonus depreciation deduction

(0.8)



(0.3)



(3.3)



(2.2)


Production tax credits

(0.5)





(2.1)




Prior year permanent return to accrual adjustments



(1.9)



0.5



(1.9)


Recognition of state net operating loss benefit / valuation allowance release



(0.1)





(0.1)


State income tax and other, net

0.1



(0.2)



(0.1)



1.1



(4.3)



(4.3)



(17.9)



(12.6)










Income tax expense (benefit)

$

1.8



$

(8.6)



$

9.0



$

2.0


Liquidity and Capital Resources

As of September 30, 2013, cash and cash equivalents were $10.9 million compared with $18.2 million at September 30, 2012.  The Company had $197.0 million available from its revolving credit facility at September 30, 2013, compared with $294.0 million at September 30, 2012. 

Dividend Declared

NorthWestern's Board of Directors declared a quarterly common stock dividend of $0.38 per share, payable December 31, 2013, to common shareholders of record as of December 13, 2013. 

2013 Earnings Guidance Reaffirmed

NorthWestern reaffirms the updated 2013 earnings guidance range of $2.45 - $2.60 per diluted share.  Basic assumptions incorporate the following expectations:

  • A consolidated income tax rate of approximately 12% of pre-tax income;
  • Normal weather in our electric and natural gas service territories for the remainder of 2013;
  • Excludes any potential additional impact as a result of the FERC decision regarding revenue allocation at our Dave Gates Generating Station; and
  • Diluted average shares outstanding of 38.3 million.

Significant Items Not Contemplated in Guidance

A reconciliation of items not factored into our updated 2013 and final 2012 earnings guidance of $2.45 - $2.60 and $2.30 - $2.40 per diluted share, respectively, is as follows. The amount below represents an after-tax non-GAAP measure that may provide users of this financial information with additional meaningful information regarding the impact of certain items on the Company's expected earnings.  More information on this measure can be found in the "Non-GAAP Financial Measures" section below.

2013

Q1 2013

Q2 2013

Q3 2013

Q4 2013

YTD 2013







Reported GAAP diluted EPS

$

1.01


$

0.37


$

0.40



$

1.78








Non-GAAP Adjustments:












Weather


(0.02)


(0.02)



(0.04)


Hydro Transaction related legal and professional fees



0.05



0.05


DSM lost revenue recovery - portion related to 2012



(0.04)



(0.04)








Adjusted Diluted EPS

$

1.01


$

0.35


$

0.39



$

1.75














2012

Q1 2012

Q2 2012

Q3 2012

Q4 2012

FY 2012







Reported GAAP diluted EPS

$

0.88


$

0.31


$

(0.10)


$

1.57


$

2.66








Non-GAAP Adjustments:












Weather

0.09


0.05


(0.06)


0.06


0.14


Release of MPSC DGGS deferral

(0.05)





(0.05)


DSM Lost revenue recovery related to 2010/2011

(0.05)




(0.05)


DGGS FERC ALJ initial decision - portion related to 2011


0.12



0.12


MSTI Impairment



0.40



0.40


Favorable CELP arbitration decision




(0.79)


(0.79)


Income tax adjustment - benefit from MT NOL



(0.06)


(0.06)








Adjusted Diluted EPS

$

0.92


$

0.31


$

0.36


$

0.78


$

2.37


Company Hosting Investor Conference Call

As previously announced, NorthWestern will host an investor conference call and webcast today at 4:00 pm Eastern Time to review its financial results.  The conference call will be webcast live on the Internet at http://www.northwesternenergy.com under the "Our Company / Investor Relations / Presentations and Webcasts" heading or by visiting www.videonewswire.com/event.asp?id=96365.  To listen, please go to the site at least 10 minutes in advance of the call to register.  An archived webcast will be available shortly after the call.

A telephonic replay of the call will be available beginning at 6:00 p.m. ET on October 24, 2013 through November 24, 2013, at (888) 203-1112 access code 8605196.

About NorthWestern Energy

NorthWestern Energy provides electricity and natural gas in the Upper Midwest and Northwest, serving approximately 673,200 customers in Montana, South Dakota and Nebraska.  More information on NorthWestern Energy is available on the Company's Web site at www.northwesternenergy.com.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This press release contains forward-looking statements within the meaning of the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995, including, without limitation, the information under "2013 Earnings Outlook".  Forward-looking statements often address our expected future business and financial performance, and often contain words such as "expects," "anticipates," "intends," "plans," "believes," "seeks," or "will."  These statements are based upon our current expectations and speak only as of the date hereof.  Our actual future business and financial performance may differ materially and adversely from those expressed in any forward-looking statements as a result of various factors and uncertainties, including, but not limited to:

  • potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, as well as adverse determinations by regulators, could have a material effect on our liquidity, results of operations and financial condition;
  • changes in availability of trade credit, creditworthiness of counterparties, usage, commodity prices, fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments, may reduce revenues or may increase operating costs, each of which could adversely affect our liquidity and results of operations;
  • unscheduled generation outages or forced reductions in output, maintenance or repairs, which may reduce revenues and increase cost of sales or may require additional capital expenditures or other increased operating costs; and
  • adverse changes in general economic and competitive conditions in the U.S. financial markets and in our service territories.

Our Annual Report on Form 10-K, recent and forthcoming Quarterly Reports on Form 10-Q, recent Current Reports on Form 8-K and other Securities and Exchange Commission filings discuss some of the important risk factors that may affect our business, results of operations and financial condition. 

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.   In addition, actual results may differ materially from those contemplated in any forward-looking statement due to the timing and likelihood of the closing of the purchase of PPL Montana LLC's hydro-electric generating facilities.

Non-GAAP Financial Measures

This press release includes financial information prepared in accordance with GAAP, as well as other financial measures, such as Gross Margin and Adjusted Diluted EPS, that are considered "non-GAAP financial measures."  Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP.  Gross Margin (Revenues less Cost of Sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure.  Gross Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow recovery of operating costs.  Adjusted Diluted EPS is another non-GAAP measure.  The Company believes the presentation of Adjusted Diluted EPS is more representative of our normal earnings than the GAAP EPS due to the exclusion (or inclusion) of certain impacts that are not reflective of ongoing earnings.

The presentation of these non-GAAP measures is intended to supplement investors' understanding of our financial performance and not to replace other GAAP measures as an indicator of actual operating performance.  Our measures may not be comparable to other companies' similarly titled measures.

 

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)




ThreeMonths Ended

September 30,


Nine Months Ended

September 30,



2013


2012


2013


2012

Revenues









Electric


$

227,103



$

202,485



$

637,667



$

605,716


Gas


34,772



32,965



196,652



182,812


Other


373



416



1,110



1,041


Total Revenues


262,248



235,866



835,429



789,569


Operating Expenses









Cost of Sales


104,298



93,061



343,407



327,884


Operating, general and administrative


72,540



63,056



208,741



195,725


MSTI Impairment




24,039





24,039


Property and other taxes


25,956



24,796



77,525



74,395


Depreciation


28,053



26,505



84,685



79,364


Total Operating Expenses


230,847



231,457



714,358



701,407


Operating Income


31,401



4,409



121,071



88,162


Interest Expense, net


(17,056)



(17,743)



(50,976)



(49,598)


Other Income


3,117



974



6,760



3,134


Income (Loss) Before Income Taxes


17,462



(12,360)



76,855



41,698


Income Tax (Expense) Benefit


(1,815)



8,588



(8,965)



(1,989)


Net Income (Loss)


$

15,647



$

(3,772)



$

67,890



$

39,709


Average Common Shares Outstanding


38,459



37,201



37,983



36,723


Basic Earnings (Loss) per Average Common Share


$

0.41



$

(0.10)



$

1.79



$

1.09


Diluted Earnings (Loss) per Average Common Share


$

0.40



$

(0.10)



$

1.78



$

1.08


Dividends Declared per Average Share


$

0.38



$

0.37



$

1.14



$

1.11



Average shares used in computing the basic and diluted earnings per share are as follows:




Three Months Ended

September 30,



Nine Months Ended

September 30,




2013


2012


2013


2012

Basic computation


38,459



37,201



37,983



36,723


Dilutive effect of









Restricted stock and performance share awards (1,2)


186





181



71


Diluted computation


38,645



37,201



38,164



36,794



(1)  Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award. 

(2)  In periods in which a net loss has been incurred, all potentially dilutive shares are considered antidilutive and thus are excluded from the calculation. For the three months ended September 30, 2012, we had 173,624 potentially dilutive restricted stock and performance share awards which were not included in the calculation.

 

 

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands)



September 30, 2013


December 31, 2012





ASSETS




Current assets

$

280,661



$

303,128


Property, plant, and equipment, net

2,573,562



2,435,590


Goodwill

355,128



355,128


Regulatory assets

395,746



367,890


Other noncurrent assets

28,553



23,797


Total Assets

$

3,633,650



$

3,485,533


LIABILITIES AND SHAREHOLDERS' EQUITY




Current maturities of long-term debt and capital leases

$

1,659



$

1,612


Short-term borrowings

102,980



122,934


Other current liabilities

313,325



324,719


Long-term capital leases

30,315



31,562


Long-term debt

1,055,091



1,055,074


Deferred income taxes

397,856



363,928


Noncurrent regulatory liabilities

343,597



276,618


Other noncurrent liabilities

384,545



375,054


Total Liabilities

2,629,368



2,551,501


Total Shareholders' Equity

1,004,282



934,032


Total Liabilities and Shareholders' Equity

$

3,633,650



$

3,485,533


 

 

 

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)



Nine Months Ended

September 30,


2013


2012

Operating Activities




Net income

$

67,890



$

39,709


Non-cash items

$

123,627



$

123,995


Changes in operating assets and liabilities

$

(20,179)



$

58,924


Cash Provided by Operating Activities

$

171,338



$

222,628






Cash Used in Investing Activities

$

(150,064)



$

(175,981)






Cash Used in Financing Activities

$

(20,175)



$

(34,379)






Increase in Cash and Cash Equivalents

$

1,099



$

12,268


Cash and Cash Equivalents, beginning of period

$

9,822



$

5,928


Cash and Cash Equivalents, end of period

$

10,921



$

18,196


 

 

 

NORTHWESTERN CORPORATION

REGULATED ELECTRIC SEGMENT

Three Months Ended September 30,

(Unaudited)



Results



2013


2012


Change


% Change


(dollars in millions)


Retail revenue

$

201.5



$

203.3



$

(1.8)



(0.9)%


Regulatory Amortization

11.8



(5.2)



17.0



(326.9)


Total Retail Revenue

213.3



198.1



15.2



7.7


Transmission

11.2



11.6



(0.4)



(3.4)


Ancillary services

0.4



(9.2)



9.6



(104.3)


Wholesale

0.8



0.8






Other

1.4



1.2



0.2



16.7


Total Revenues

$

227.1



$

202.5



$

24.6



12.1


Total Cost of Sales

95.3



83.8



11.5



13.7


Gross Margin

$

131.8



$

118.7



$

13.1



11.0%





















Revenues


Megawatt Hours (MWH)


Avg. Customer Counts


2013


2012


2013


2012


2013


2012


(in thousands)





Retail Electric












Montana

$

65,455



$

63,951



$

575



$

587



$

274,835



$

273,130


South Dakota

12,698



13,947



146



158



49,350



48,940


Residential 

78,153



77,898



721



745



324,185



322,070


Montana

83,624



83,605



823



867



62,639



62,179


South Dakota

18,502



19,643



255



259



12,154



12,235


Commercial

102,126



103,248



1,078



1,126



74,793



74,414


Industrial

10,105



10,011



737



806



74



74


Other

11,131



12,148



91



103



7,813



7,816


Total Retail Electric

$

201,515



$

203,305



$

2,627



$

2,780



$

406,865



$

404,374


Total Wholesale Electric

$

845



$

781



$

39



$

41



$



$


















Degree Days



2013 as compared with:

Cooling Degree-Days

2013


2012


Historic Average


2012


Historic Average

Montana

393


395


259



1% cooler


52% warmer

South Dakota

702


911


639



23% cooler


10% warmer












Degree Days



2013 as compared with:

Heating Degree-Days

2013


2012


Historic Average


2012


Historic Average

Montana

231



244



357



5% warmer


35% warmer

South Dakota

60



65



90



8% warmer


33% warmer

 

 

 

NORTHWESTERN CORPORATION

REGULATED ELECTRIC SEGMENT

Nine Months Ended September 30,

(Unaudited)



Results



2013


2012


Change


% Change


(dollars in millions)


Retail revenue

$

581.5



$

561.9



$

19.6



3.5%


Regulatory Amortization

11.9



10.8



1.1



10.2


Total Retail Revenue

593.4



572.7



20.7



3.6


Transmission

37.3



33.7



3.6



10.7


Ancillary Services

1.1



(6.5)



7.6



(116.9)


Wholesale

2.0



2.4



(0.4)



(16.7)


Other

3.9



3.4



0.5



14.7


Total Revenues

$

637.7



$

605.7



$

32.0



5.3


Total Cost of Sales

260.9



244.9



16.0



6.5


Gross Margin

$

376.8



$

360.8



$

16.0



4.4%





















Revenues


Megawatt Hours (MWH)


Avg. Customer Counts


2013


2012


2013


2012


2013


2012


(in thousands)





Retail Electric












Montana

$

198,375



$

188,768



$

1,751



$

1,749



$

275,913



$

273,711


South Dakota

37,150



36,993



447



424



49,250



48,887


Residential 

235,525



225,761



2,198



2,173



325,163



322,598


Montana

238,482



230,498



2,356



2,416



62,638



62,046


South Dakota

52,009



52,887



722



712



12,168



12,116


Commercial

290,491



283,385



3,078



3,128



74,806



74,162


Industrial

31,089



28,185



2,194



2,217



74



74


Other

24,352



24,600



168



178



6,129



6,101


Total Retail Electric

$

581,457



$

561,931



$

7,638



$

7,696



$

406,172



$

402,935


Total Wholesale Electric

$

2,022



$

2,382



$

97



$

137



$



$


















Degree Days



2013 as compared with:

Cooling Degree-Days

2013


2012


Historic Average


2012


Historic Average

Montana

438



450



300



3% cooler


46% warmer

South Dakota

752



1,061



696



29% cooler


8% warmer












Degree Days



2013 as compared with:

Heating Degree-Days

2013


2012


Historic Average


2012


Historic Average

Montana

4,721



4,488



4,947



5% colder


5% warmer

South Dakota

6,174



4,375



5,573



41% colder


11% colder

 

 

 

NORTHWESTERN CORPORATION

REGULATED NATURAL GAS SEGMENT

Three Months Ended September 30,

(Unaudited)



Results



2013


2012


Change


% Change


(dollars in millions)


Retail revenues

$

22.8



$

19.9



$

2.9



14.6%


Regulatory amortization

3.2



5.1



(1.9)



(37.3)


Total retail revenues

26.0



25.0



1.0



4.0


Wholesale and other

8.8



8.0



0.8



10.0


Total Revenues

34.8



33.0



1.8



5.5


Total Cost of Sales

9.0



9.2



(0.2)



(2.2)


Gross Margin

$

25.8



$

23.8



$

2.0



8.4%



























Revenue


Dekatherms (Dkt)



Avg. Customer Counts



2013


2012


2013


2012


2013


2012


(in thousands)






Retail Gas












Montana

$

9,770



$

8,795



807



758



159,197



158,524


South Dakota

1,916



1,757



124



113



37,846



37,551


Nebraska

2,257



1,887



157



149



36,315



36,222


Residential

13,943



12,439



1,088



1,020



233,358



232,297


Montana

6,042



5,171



581



515



22,271



22,181


South Dakota

1,296



1,130



171



171



5,971



5,931


Nebraska

1,281



985



185



187



4,538



4,517


Commercial

8,619



7,286



937



873



32,780



32,629


Industrial

145



93



12



10



262



269


Other

94



68



10



8



156



150


Total Retail Gas

$

22,801



$

19,886



2,047



1,911



266,556



265,345















Degree Days


2013 as compared with:

Heating Degree-Days

2013


2012


Historic Average


2012


Historic Average

Montana

231


244


357


5% warmer


35% warmer

South Dakota

60


65


90


8% warmer


33% warmer

Nebraska

21


27


49


22% warmer


57% warmer

 

 

NORTHWESTERN CORPORATION

REGULATED NATURAL GAS SEGMENT

Nine Months Ended September 30,

(Unaudited)



Results



2013


2012


Change


% Change


(dollars in millions)


Retail revenues

$

173.5



$

150.0



$

23.5



15.7%


Regulatory amortization

(6.3)



7.3



(13.6)



(186.3)


Total retail revenues

167.2



157.3



9.9



6.3


Wholesale and other

29.5



25.5



4.0



15.7


Total Revenues

196.7



182.8



13.9



7.6


Total Cost of Sales

82.5



83.0



(0.5)



(0.6)


Gross Margin

$

114.2



$

99.8



$

14.4



14.4%



























Revenue


Dekatherms (Dkt)



Avg. Customer Counts



2013


2012


2013


2012


2013


2012


(in thousands)






Retail Gas












Montana

$

72,171



$

67,049



8,014



7,656



160,330



159,316


South Dakota

20,227



15,447



2,354



1,709



38,146



37,792


Nebraska

18,774



14,234



2,012



1,578



36,656



36,520


Residential

111,172



96,730



12,380



10,943



235,132



233,628


Montana

37,338



34,409



4,252



4,004



22,443



22,329


South Dakota

13,498



9,656



2,119



1,545



6,028



5,961


Nebraska

10,016



7,880



1,496



1,279



4,596



4,571


Commercial

60,852



51,945



7,867



6,828



33,067



32,861


Industrial

776



672



88



80



264



273


Other

720



641



97



85



157



150


Total Retail Gas

$

173,520



$

149,988



20,432



17,936



268,620



266,912















Degree Days


2013 as compared with:

Heating Degree-Days

2013


2012


Historic Average


2012


Historic Average

Montana

4,721


4,488


4,947


5% colder


5% warmer

South Dakota

6,174


4,375


5,573


41% colder


11% colder

Nebraska

4,741


3,611


4,584


31% colder


3% colder

 

 

NORTHWESTERN CORPORATION

SEGMENT RESULTS

Three Months Ended September 30,

(Unaudited)

(in thousands)


Three Months Ended










September 30, 2013

Electric


Gas


Other


Eliminations


Total

Operating revenues

$

227,103



$

34,772



$

373



$



$

262,248


Cost of sales

95,264



9,034







104,298


Gross margin

131,839



25,738



373





157,950


Operating, general and administrative

49,155



18,521



4,864





72,540


Property and other taxes

19,381



6,572



3





25,956


Depreciation

22,150



5,895



8





28,053


Operating income (loss)

41,153



(5,250)



(4,502)





31,401


Interest expense

(14,302)



(2,560)



(194)





(17,056)


Other income

2,213



878



26





3,117


Income tax (expense) benefit

(8,412)



3,520



3,077





(1,815)


Net income (loss)

$

20,652



$

(3,412)



$

(1,593)



$



$

15,647






















Three Months Ended










September 30, 2012

Electric


Gas


Other


Eliminations


Total

Operating revenues

$

202,485



$

32,965



$

416



$



$

235,866


Cost of sales

83,814



9,247







93,061


Gross margin

118,671



23,718



416





142,805


Operating, general and administrative

44,711



17,452



893





63,056


MSTI Impairment

24,039









24,039


Property and other taxes

18,621



6,172



3





24,796


Depreciation

21,636



4,860



9





26,505


Operating income (loss)

9,664



(4,766)



(489)





4,409


Interest expense

(15,181)



(2,363)



(199)





(17,743)


Other income

405



541



28





974


Income tax benefit (expense)

5,762



3,102



(276)





8,588


Net income (loss)

$

650



$

(3,486)



$

(936)



$



$

(3,772)


 

 

NORTHWESTERN CORPORATION

SEGMENT RESULTS

Nine Months Ended September 30,

(Unaudited)

(in thousands)


Nine Months Ended










September 30, 2013

Electric


Gas


Other


Eliminations


Total

Operating revenues

$

637,667



$

196,652



$

1,110



$



$

835,429


Cost of sales

260,879



82,528







343,407


Gross margin

376,788



114,124



1,110





492,022


Operating, general and administrative

142,594



56,899



9,248





208,741


Property and other taxes

57,549



19,968



8





77,525


Depreciation

67,454



17,206



25





84,685


Operating income (loss)

109,191



20,051



(8,171)





121,071


Interest expense

(42,840)



(7,553)



(583)





(50,976)


Other income

4,926



1,753



81





6,760


Income tax (expense) benefit

(12,792)



(153)



3,980





(8,965)


Net income (loss)

$

58,485



$

14,098



$

(4,693)



$



$

67,890






















Nine Months Ended










September 30, 2012

Electric


Gas


Other


Eliminations


Total

Operating revenues

$

605,716



$

182,812



$

1,041



$



$

789,569


Cost of sales

244,902



82,982







327,884


Gross margin

360,814



99,830



1,041





461,685


Operating, general and administrative

137,753



55,397



2,575





195,725


MSTI impairment

24,039









24,039


Property and other taxes

55,628



18,759



8





74,395


Depreciation

64,770



14,569



25





79,364


Operating income (loss)

78,624



11,105



(1,567)





88,162


Interest expense

(42,257)



(6,660)



(681)





(49,598)


Other income

1,818



1,235



81





3,134


Income tax (expense) benefit

(3,322)



522



811





(1,989)


Net income (loss)

$

34,863



$

6,202



$

(1,356)



$



$

39,709


SOURCE NorthWestern Corporation

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