Delaware (State or other jurisdiction of incorporation) | 1-10499 (Commission File Number) | 46-0172280 (IRS Employer Identification No.) | ||
3010 W. 69th Street Sioux Falls, South Dakota (Address of principal executive offices) | 57108 (Zip Code) | |||
(605) 978-2900 (Registrant's telephone number, including area code) |
Item 2.02 | Results of Operations and Financial Condition |
Item 9.01 | Financial Statements and Exhibits. |
EXHIBIT NO. | DESCRIPTION OF DOCUMENT |
99.1* | Press Release dated October 23, 2014 |
99.2* | Investor Call Presentation, dated October 23, 2014 |
NORTHWESTERN CORPORATION | |||
By: | /s/ Timothy P. Olson | ||
Timothy P. Olson | |||
Corporate Secretary |
EXHIBIT NO. | DESCRIPTION OF DOCUMENT |
99.1* | Press Release dated October 23, 2014 |
99.2* | Investor Call Presentation, dated October 23, 2014 |
NorthWestern Corporation d/b/a NorthWestern Energy 3010 W. 69th Street Sioux Falls, SD 57108 www.northwesternenergy.com |
Summary Financial Results | Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||
(in thousands, except per share amounts) | 2014 | 2013 | 2014 | 2013 | |||||||||||
Total Revenues | $ | 251,912 | $ | 262,248 | $ | 891,916 | $ | 835,429 | |||||||
Cost of Sales | 94,592 | 104,298 | 374,494 | 343,407 | |||||||||||
Gross Margin | 157,320 | 157,950 | 517,422 | 492,022 | |||||||||||
Operating Expenses | |||||||||||||||
Operating, general and administrative | 68,108 | 72,540 | 214,557 | 208,741 | |||||||||||
Property and other taxes | 27,773 | 25,956 | 84,292 | 77,525 | |||||||||||
Depreciation and depletion | 30,452 | 28,053 | 91,139 | 84,685 | |||||||||||
Total Operating Expenses | 126,333 | 126,549 | 389,988 | 370,951 | |||||||||||
Operating Income | 30,987 | 31,401 | 127,434 | 121,071 | |||||||||||
Interest Expense | (18,794 | ) | (17,056 | ) | (57,887 | ) | (50,976 | ) | |||||||
Other (Expense) Income | (439 | ) | 3,117 | 4,730 | 6,760 | ||||||||||
Income Before Income Taxes | 11,754 | 17,462 | 74,277 | 76,855 | |||||||||||
Income Tax Benefit (Expense) | 18,437 | (1,815 | ) | 9,240 | (8,965 | ) | |||||||||
Net Income | $ | 30,191 | $ | 15,647 | $ | 83,517 | $ | 67,890 | |||||||
Average Common Shares Outstanding | 39,141 | 38,459 | 39,046 | 37,983 | |||||||||||
Basic Earnings per Average Common Share | $ | 0.77 | $ | 0.41 | $ | 2.14 | $ | 1.79 | |||||||
Diluted Earnings per Average Common Share | $ | 0.77 | $ | 0.40 | $ | 2.13 | $ | 1.78 | |||||||
Dividends Declared per Common Share | $ | 0.40 | $ | 0.38 | $ | 1.20 | $ | 1.14 |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
Pre-tax | Net | Diluted | Pre-tax | Net | Diluted | ||||||||||
($millions, except EPS) | Income | Income(1) | EPS | Income | Income(1) | EPS | |||||||||
2013 reported | $17.5 | $15.6 | $0.40 | $76.9 | $67.9 | $1.78 | |||||||||
Gross Margin | |||||||||||||||
Natural gas production | 2.8 | 1.7 | 0.04 | 17.4 | 10.7 | 0.27 | |||||||||
DSM lost revenue recoveries | (4.9 | ) | (3.0 | ) | (0.08 | ) | (3.0 | ) | (1.8 | ) | (0.05 | ) | |||
Natural gas retail volumes | 0.5 | 0.3 | 0.01 | 2.8 | 1.7 | 0.04 | |||||||||
Electric retail volumes | (1.3 | ) | (0.8 | ) | (0.02 | ) | 3.4 | 2.1 | 0.05 | ||||||
Operating expenses recovered in trackers | (1.7 | ) | (1.0 | ) | (0.03 | ) | (2.1 | ) | (1.3 | ) | (0.03 | ) | |||
Electric transmission capacity | 3.5 | 2.2 | 0.06 | 3.5 | 2.2 | 0.06 | |||||||||
Montana natural gas rate increase | — | — | — | 4.9 | 3.0 | 0.08 | |||||||||
Other | 0.4 | 0.2 | 0.01 | (1.5 | ) | (0.9 | ) | (0.02 | ) | ||||||
Subtotal - Gross Margin | (0.7 | ) | (0.4 | ) | (0.01 | ) | 25.4 | 15.7 | 0.40 | ||||||
OG&A Expense | |||||||||||||||
Natural gas production | (2.6 | ) | (1.6 | ) | (0.04 | ) | (7.6 | ) | (4.7 | ) | (0.12 | ) | |||
Bad debt expense | 0.6 | 0.4 | 0.01 | (2.5 | ) | (1.5 | ) | (0.04 | ) | ||||||
Non-employee directors deferred compensation | 3.6 | 2.2 | 0.06 | 2.2 | 1.3 | 0.03 | |||||||||
Hydro transaction costs | 2.2 | 1.4 | 0.04 | 1.0 | 0.6 | 0.02 | |||||||||
Operating expenses recovered in trackers | 1.7 | 1.0 | 0.03 | 2.1 | 1.3 | 0.03 | |||||||||
Other | (1.1 | ) | (0.7 | ) | (0.02 | ) | (1.1 | ) | (0.7 | ) | (0.02 | ) | |||
Subtotal - OG&A Expense | 4.4 | 2.7 | 0.08 | (5.9 | ) | (3.7 | ) | (0.10 | ) | ||||||
Other items | |||||||||||||||
Depreciation and depletion expense | (2.4 | ) | (1.5 | ) | (0.04 | ) | (6.4 | ) | (3.9 | ) | (0.10 | ) | |||
Property and other taxes | (1.8 | ) | (1.1 | ) | (0.03 | ) | (6.8 | ) | (4.2 | ) | (0.11 | ) | |||
Interest expense (incl. bridge related to hydro transaction) | (1.7 | ) | (1.0 | ) | (0.03 | ) | (6.9 | ) | (4.2 | ) | (0.11 | ) | |||
Other income (incl. offset to non-employee director comp. above) | (3.5 | ) | (2.2 | ) | (0.06 | ) | (2.1 | ) | (1.3 | ) | (0.03 | ) | |||
Permanent and flow-through adjustments to income tax | 18.2 | 0.46 | 17.3 | 0.44 | |||||||||||
Impact of higher share count | (0.01 | ) | (0.05 | ) | |||||||||||
All other, net | — | (0.1 | ) | 0.01 | 0.1 | (0.1 | ) | 0.01 | |||||||
Subtotal - Other items | (9.4 | ) | 12.3 | 0.30 | (22.1 | ) | 3.6 | 0.05 | |||||||
Total impact of above items | (5.7 | ) | 14.6 | 0.37 | (2.6 | ) | 15.6 | 0.35 | |||||||
2014 reported | $11.8 | $30.2 | $0.77 | $74.3 | $83.5 | $2.13 | |||||||||
(1) Income Tax Benefit (Expense) calculation on reconciling items assumes effective tax rate of 38.5%. | |||||||||||||||
• | Received MPSC approval of our application associated with the hydro transaction; and |
• | Improvement in Net Income of approximately $14.6 million as compared with the same period in 2013, due primarily to the release of an unrecognized tax benefit and tax method change, resulting in an income tax benefit of $18.4 million in the third quarter of 2014. |
• | $4.9 million decrease in DSM lost revenues recovered through our supply trackers related to efficiency measures implemented by customers. 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; |
• | $1.7 million lower revenue for operating expenses recovered through our supply trackers primarily related to efficiency measures implemented by customers; and |
• | $0.8 million lower retail electric and gas volumes as a result of cooler summer weather. |
• | $3.5 million higher demand to transmit energy across our lines due primarily to interconnection with the Montana Alberta Transmission Line (MATL) placed into commercial operation in late 2013; |
• | $2.8 million increase in natural gas production margin from the acquisition of gas production assets in December 2013, of which the revenues are subject to refund; and |
• | $0.4 million increase in other miscellaneous gross margin. |
• | $3.6 million decrease in expense related to non-employee directors deferred compensation as compared to the prior year, primarily due to a decrease in our stock price during the three months ended September 30, 2014. Directors may defer their board fees into deferred shares held in a rabbi trust. If the market value of our stock goes down, deferred compensation expense decreases; however, we account for the deferred shares as trading securities and their change in value is also reflected in other income with no impact on net income; |
• | $2.2 million lower legal and professional fees associated with the hydro transaction. Hydro transaction related legal and professional fees were $0.6 million for the three months ended September 30, 2014 as compared to $2.8 million for the same period in 2013. We expect to continue to incur hydro transaction related legal and professional fees during the remainder of 2014; |
• | $1.7 million lower operating expenses primarily related to customer efficiency programs, which are recovered through trackers and have no impact on operating income; and |
• | $0.6 million lower bad debt expense, due to improved collection of receivables from customers. |
• | $2.6 million increase in natural gas production costs from the acquisition of gas production assets in December 2013; and |
• | $1.1 million increase in other miscellaneous expense items. |
(in millions) | Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||||||||
Income Before Income Taxes | $ | 11.8 | $ | 17.5 | $ | 74.3 | $ | 76.9 | |||||||||||||||||
Income tax calculated at 35% federal statutory rate | 4.1 | 35.0 | % | 6.1 | 35.0 | % | 26.0 | 35.0 | % | 26.9 | 35.0 | % | |||||||||||||
Permanent or flow through adjustments: | |||||||||||||||||||||||||
State income, net of federal provisions | (0.1 | ) | (0.9 | )% | (0.7 | ) | (4.0 | )% | 0.3 | 0.3 | % | (2.6 | ) | (3.4 | )% | ||||||||||
Release of unrecognized tax benefit | (12.6 | ) | (107.3 | )% | — | — | % | (12.6 | ) | (17.0 | )% | — | — | % | |||||||||||
Safe harbor method election (prior year impact) | (4.3 | ) | (36.5 | )% | — | — | % | (4.3 | ) | (5.8 | )% | — | — | % | |||||||||||
Other prior year permanent return to accrual adjustments | (0.9 | ) | (7.5 | )% | — | — | % | (0.9 | ) | (1.2 | )% | 0.5 | 0.7 | % | |||||||||||
Flow-through repairs deductions | (3.4 | ) | (29.0 | )% | (3.1 | ) | (17.7 | )% | (14.9 | ) | (20.0 | )% | (12.9 | ) | (16.8 | )% | |||||||||
Plant and depreciation of flow through items | (0.7 | ) | (5.8 | )% | — | — | % | (0.2 | ) | (0.2 | )% | — | — | % | |||||||||||
Production tax credits | (0.3 | ) | (2.6 | )% | (0.5 | ) | (2.9 | )% | (2.1 | ) | (2.8 | )% | (2.2 | ) | (2.8 | )% | |||||||||
Other, net | (0.2 | ) | (2.3 | )% | — | — | % | (0.5 | ) | (0.7 | )% | (0.7 | ) | (1.0 | )% | ||||||||||
Subtotal | (22.5 | ) | (191.9 | )% | (4.3 | ) | (24.6 | )% | (35.2 | ) | (47.4 | )% | (17.9 | ) | (23.3 | )% | |||||||||
Income Tax (Benefit) Expense | $ | (18.4 | ) | (156.9)% | $ | 1.8 | 10.4 | % | $ | (9.2 | ) | (12.4 | )% | $ | 9.0 | 11.7 | % |
2014 | Q1 | Q2 | Q3 | Q4 | YTD '14 | |||||
Reported GAAP diluted EPS | $1.17 | $0.20 | $0.77 | $2.13 | ||||||
Non-GAAP Adjustments: | ||||||||||
Weather | (0.05 | ) | 0.01 | — | (0.04 | ) | ||||
Hydro transaction (professional fees & bridge financing) | 0.04 | 0.04 | 0.04 | 0.12 | ||||||
Income Tax Benefits Release of $12.6M unrecognized tax benefit & $4.3M safe harbor election (prior years) | (0.43 | ) | (0.43 | ) | ||||||
Adjusted diluted EPS | $1.16 | $0.25 | $0.38 | $1.78 | ||||||
Note: Sum of first three quarters GAAP and Adjusted EPS total $0.01 greater than shown above. The difference is due to rounding and dilutive share counts for quarters versus year-to-date. | ||||||||||
2013 | Q1 | Q2 | Q3 | Q4 | FY '13 | |||||
Reported GAAP diluted EPS | $1.01 | $0.37 | $0.40 | $0.68 | $2.46 | |||||
Non-GAAP Adjustments: | ||||||||||
Weather | (0.02 | ) | (0.02 | ) | (0.01 | ) | (0.05 | ) | ||
Hydro transaction (professional fees & bridge financing) | 0.05 | 0.06 | 0.11 | |||||||
Prior period DSM lost revenue (including accrued interest) | (0.04 | ) | 0.02 | (0.02 | ) | |||||
Adjusted diluted EPS | $1.01 | $0.35 | $0.39 | $0.75 | $2.50 |
• | Normal weather in our electric and natural gas service territories for the remainder of 2014; |
• | Excludes any hydro related transaction fees (including legal and bridge financing) and, assuming FERC approval of our financing, excludes any potential income generated from the regulated operation of the hydro assets post-closing; |
• | Excludes any potential additional impact as a result of the FERC decision regarding revenue allocation at our Dave Gates Generating Station; |
• | An updated consolidated effective income tax rate of approximately 12% - 14% of pre-tax income (previously 14-16%) after removal of $16.9 million of tax benefits recognized during the third quarter that relate specifically to years prior to 2014; and |
• | Diluted average shares outstanding of 39.3 million, which excludes additional shares we expect to issue in the fourth quarter 2014 in conjunction with the pending hydro transaction. |
Low | Midpoint | High | ||
2014 EPS Non-GAAP Adjusted guidance range | $2.60 | - | $2.75 | |
ø | ÷ | |||
2014 Adjusted EPS midpoint | $2.68 | |||
÷ | ø | |||
$2.68 | $2.68 | |||
2015 Earnings drivers (after-tax per share) | ||||
Gross margin improvements | 2.70 | - | 2.82 | |
OG&A expense increases | (0.95) | - | (0.89) | |
Property & other taxes | (0.31) | - | (0.29) | |
Depreciation & depletion | (0.36) | - | (0.34) | |
Interest expense / other income | (0.26) | - | (0.22) | |
Incremental tax benefits * | 0.18 | - | 0.22 | |
Subtotal of anticipated improvements | $1.00 | - | $1.30 | |
2015 EPS prior to dilution | $3.68 | - | $3.98 | |
Dilutive impact of $400 million share issuance | (0.73) | - | (0.68) | |
2015 Preliminary EPS guidance range | $2.95 | - | $3.30 | |
ø | ÷ | |||
2015 Preliminary EPS midpoint | $3.13 | |||
2015 Preliminary EPS guidance range | $2.95 | - | $3.30 | |
2015 Preliminary targeted dividend payout ratio | 60% | 60% | ||
2015 Preliminary targeted dividend range | $1.77 | $1.98 | ||
ø | ÷ | |||
2015 Preliminary targeted dividend midpoint | $1.88 | |||
* Other 2015 Earnings drivers shown above are calculated using a 38.5% effective tax rate. The anticipated incremental tax benefits in 2015 are primarily due to increased repairs tax deductions resulting from higher maintenance capital spending and other flow-through impacts. |
• | Normal weather in our electric and natural gas service territories; |
• | Assumes successful integration and a full year earnings contribution from the pending hydro transaction; |
• | Excludes any potential additional impact as a result of the FERC decision regarding revenue allocation at our Dave Gates Generating Station; |
• | A consolidated effective income tax rate of approximately 15% - 19% of pre-tax income; and |
• | Diluted average shares outstanding of approximately 49.1 million on the low end of guidance range and 47.5 million at the high end of guidance range. Shares outstanding for 2015 are dependent upon results of planned $400 million equity issuance to fund hydro transaction and therefor are currently shown as a range. |
• | 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. |
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