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| 8-K - BLACK HILLS CORP /SD/ | a8-kq12011earningsrelease.htm |
News Release
Company Contact:
Jerome Nichols 605-721-1171
Media Relations Line 866-243-9002
BLACK HILLS CORP. REPORTS FIRST QUARTER RESULTS AND
UPDATES 2011 EARNINGS GUIDANCE
SOLID UTILITY PERFORMANCE; PROGRESS ON GROWTH INITIATIVES;
NON-REGULATED BUSINESSES NEGATIVELY IMPACT RESULTS
RAPID CITY, SD May 10, 2011 – Black Hills Corp. (NYSE: BKH) today announced first quarter 2011 financial results. Adjusted net income was $23.3 million, or $0.59 per share, compared to $31.7 million, or $0.82 per share, for the same period in 2010 (this is a non-GAAP measure and an accompanying schedule for the GAAP to non-GAAP adjustment reconciliation is provided). On a GAAP basis, the company reported net income of $26.9 million, or $0.68 per share, for first quarter 2011, compared to $31.4 million or $0.81 per share, for the same period in 2010.
“First quarter financial performance for our non-regulated segments was disappointing, reducing overall results and our view of the earnings we expect to achieve for full year 2011. Our utilities continue to perform well and their strong operating income reflects implementation of new customer rates in five jurisdictions,” said David R. Emery chairman, president and chief executive officer of Black Hills Corp. “Current growth projects — including the construction of 180 megawatts of utility and 200 megawatts of IPP natural gas-fired generation — remain on schedule and within budget. The rate request pertinent to these facilities, seeking a $40.2 million increase in annual revenue, was filed with the Colorado Public Utilities Commission in April. In addition, we announced $167 million in new utility investments through three recent regulatory filings. Continued progress on our strategic objectives, including our ability to address the challenges in our non-regulated businesses, is expected to provide significant earnings growth for our company beginning in 2012.”
Black Hills Corp. highlights for first quarter 2011, recent regulatory filings and other events include:
• | On April 28, 2011, Black Hills Energy – Colorado Electric filed an electric rate request with the Colorado Public Utilities Commission seeking a $40.2 million or an 18.8 percent increase in annual revenues, with new rates effective Jan. 1, 2012, the projected start date of commercial operation for the Pueblo Airport Generation Station. |
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• | On April 28, 2011, Black Hills Power filed a request for a declaratory ruling from the South Dakota Public Utilities Commission, asking the commission to confirm a proposed 20 megawatt wind farm near Belle Fourche, S.D., is reasonable and cost effective. The $38 million project will be the first utility-scale wind development in western South Dakota with commercial operations expected before Dec. 31, 2012. |
• | On March 24, 2011, Black Hills Energy – Colorado Electric filed a proposal with the Colorado Public Utilities Commission to rate base 50 percent of a 29 megawatt wind turbine project as part of its plan to meet the state of Colorado's Renewable Energy Standard. The project will require a net capital investment by the utility of $27 million and will be operational no later than Dec. 31, 2012. |
• | On March 14, 2011, Black Hills Energy – Colorado Electric filed a request for a certificate of public convenience and necessity with the Colorado Public Utilities Commission to construct a third utility owned natural gas-fired turbine at the Pueblo Airport Generation Station site. The CPCN filing was in accordance with the commission's Dec. 15, 2010, order approving the retirement of the utility's coal-fired W.N. Clark facility, and granting a presumption of need for the third turbine under the Colorado Clean Air-Clean Jobs Act. The project requires a capital investment of approximately $102 million and the plant is expected to begin commercial operation by Dec. 31, 2013. |
• | Effective Feb. 10, 2011 the Iowa Utilities Board approved a settlement agreement for an increase in annual utility revenue of $3.4 million or 2.1 percent for Black Hills Energy – Iowa Gas. Interim rates equal to a $2.6 million increase went into effect on June 18, 2010. |
• | Power plant construction for Black Hills Energy – Colorado Electric's 180 megawatt power plant near Pueblo, Colo., is on schedule and under budget with $213 million in expenditures as of March 31. |
• | Power plant construction for Black Hills Colorado IPP’s 200 megawatt power plant near Pueblo, Colo., is on schedule and on budget with $203 million in expenditures as of March 31. |
• | Our oil and gas segment started drilling a horizontal gas test well in the Mancos formation shale in the San Juan Basin in early April. The well is the first of three planned to be drilled in the San Juan and Piceance Basins during 2011. Results for all three wells are expected during the fourth quarter. |
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BLACK HILLS CORPORATION
CONSOLIDATED FINANCIAL RESULTS
(unaudited)
GAAP Net Income (Loss) for the First Quarter | |||||||||
2011 | 2010 | Increase (Decrease) 2011 vs. 2010 | |||||||
(in millions) | |||||||||
Utilities: | |||||||||
Electric | $ | 10.2 | $ | 9.9 | $ | 0.4 | |||
Gas | 19.3 | 19.5 | (0.2 | ) | |||||
Total Utilities Group | 29.5 | 29.4 | 0.2 | ||||||
Non-regulated Energy: | |||||||||
Power generation | 1.2 | 1.1 | 0.1 | ||||||
Coal mining | (1.3 | ) | 1.3 | (2.6 | ) | ||||
Oil and gas | (0.7 | ) | 2.3 | (3.0 | ) | ||||
Energy marketing | (2.7 | ) | 2.3 | (5.0 | ) | ||||
Total Non-regulated Energy Group | (3.5 | ) | 7.0 | (10.5 | ) | ||||
Corporate * | 0.9 | (5.0 | ) | 5.9 | |||||
GAAP Net income | $ | 26.9 | $ | 31.4 | $ | (4.5 | ) | ||
__________________________
* Includes $3.6 million net non-cash after-tax unrealized gain in 2011 and $2.0 million net non-cash after-tax unrealized loss in 2010, respectively.
Three Months Ended March 31, | |||||||||||
2011 | 2010 | ||||||||||
(in millions) | |||||||||||
Revenues (a): | |||||||||||
Utilities | $ | 378.5 | $ | 392.0 | |||||||
Non-regulated Energy | 43.5 | 51.6 | |||||||||
Intercompany eliminations | (18.7 | ) | (17.0 | ) | |||||||
$ | 403.3 | $ | 426.5 | ||||||||
Weighted average common shares outstanding (in thousands): | |||||||||||
Basic | 39,059 | 38,848 | |||||||||
Diluted | 39,761 | 39,009 | |||||||||
Earnings per share: | |||||||||||
Basic | $ | 0.69 | $ | 0.81 | |||||||
Diluted | $ | 0.68 | $ | 0.81 | |||||||
__________
(a) Revenues for the three months ended March 31, 2010 have been restated to eliminate intercompany transactions with our rate regulated operations; these transactions were previously not eliminated. There was no impact on total gross margins or net income.
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REVISED EARNINGS GUIDANCE
Black Hills now expects 2011 adjusted net income to be in the range of $1.70 to $1.95 per share versus the $1.90 to $2.15 range issued previously on Oct. 28, 2010. This revised estimate is predicated on a number of considerations, including the following:
• | Planned capital expenditures in 2011 estimated to be approximately $462 million; including crude oil and gas capital expenditures of $61 million; |
• | Assumed settlement of the equity forward instrument in the fourth quarter for total net cash proceeds of approximately $123 million and physical delivery of 4,413,519 shares; |
• | Previously disclosed undesignated interest rate swaps remain in place with no unrealized mark-to-market impact on 2011 adjusted net income; |
• | Normal operations and weather conditions in our utility service territories for the remainder of 2011, impacting customer usage, off-system sales, construction, maintenance and/or capital investment projects; |
• | Continued operating challenges resulting in operating losses at our coal mining segment; |
• | No additional unplanned outages at any of the company’s power generation facilities; |
• | Modest increase in 2011 energy marketing operating income compared to 2010 as a result of additional margins from crude oil, coal, power and environmental marketing activities; |
• | Total 2011 oil and natural gas production in range of 11.0 Bcfe to 11.9 Bcfe; |
• | Oil and gas annual average NYMEX prices of $4.29 per MMBtu for natural gas and $104.60 per Bbl for oil; production-weighted average well-head prices of $3.04 per Mcf and $94.18 per Bbl, all based on recent forward strips and average hedged prices of $4.02 per Mcf and $80.81 per Bbl; and |
• | No significant acquisitions or divestitures. |
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USE OF NON-GAAP FINANCIAL MEASURE
As noted in this news release, in addition to presenting earnings information in conformity with Generally Accepted Accounting Principles, the company has provided non-GAAP earnings data reflecting adjustments for special items as specified in the GAAP to non-GAAP adjustment reconciliation table below. Adjusted net income is defined as net income, adjusted for expenses and/or gains/losses that are unusual, non-routine, non-recurring or special in a way that does not reflect the company’s core operating performance. The company believes that non-GAAP financial measures are useful to investors because the items excluded are not indicative of the company’s continuing operating results. Also, the company’s management uses these non-GAAP financial measures as an indicator for planning and forecasting future periods. Adjusted net income has limitations as an analytical tool and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Our presentation of adjusted net income should not be construed as an inference that our future results will be unaffected by other expenses and/or gains/losses that are unusual, non-routine or non-recurring.
GAAP TO NON-GAAP ADJUSTMENT RECONCILIATION
Three Months Ended March 31, | |||||||||||||||||||||||
(In millions, except per share amounts) | 2011 | 2010 | |||||||||||||||||||||
(after-tax) | Income | EPS | Income | EPS | |||||||||||||||||||
Net income (loss) (GAAP) | $ | 26.9 | $ | 0.68 | $ | 31.4 | $ | 0.81 | |||||||||||||||
Adjustments for special items: | |||||||||||||||||||||||
Unrealized (gain) loss on interest rate swaps | (3.6 | ) | (0.09 | ) | 2.0 | 0.05 | |||||||||||||||||
Gain on sale of Elkhorn, NE assets | — | — | (1.7 | ) | (0.04 | ) | |||||||||||||||||
Rounding | — | — | — | — | |||||||||||||||||||
Total special items adjustment | (3.6 | ) | (0.09 | ) | 0.3 | 0.01 | |||||||||||||||||
Adjusted net income (Non-GAAP) | $ | 23.3 | $ | 0.59 | $ | 31.7 | $ | 0.82 | |||||||||||||||
DIVIDENDS
On April 26, 2011, our board of directors declared a quarterly dividend on common stock. Common shareholders of record at the close of business on May 18, 2011 will receive $0.365 cents per share, equivalent to an annual dividend rate of $1.46, payable on June 1, 2011.
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CONFERENCE CALL AND WEBCAST
The company will host a live conference call and webcast at 11 a.m. EDT on Wednesday, May 11, 2011, to discuss the company’s financial and operating performance.
Those interested in listening to the live broadcast from within the United States can call 866-362-5158. International callers can call 617-597-5397. All callers need to enter the pass code 83570420 when prompted. To access the live webcast and download a copy of the investor presentation, go to the Black Hills website at www.blackhillscorp.com and click “Webcast” in the “Investor Relations” section. The presentation will be posted on the website before the webcast. Listeners should allow at least five minutes for registering and accessing the presentation.
For those unable to listen to the live broadcast, a replay will be available on the company’s website or by telephone through Friday, May 20, 2011, at 888-286-8010 in the United States and at 617-801-6888 for international callers. The replay pass code is 39084912.
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BUSINESS UNIT PERFORMANCE SUMMARY
(Minor differences may result due to rounding.)
Utilities Group - First Quarter 2011
Net income from the Utilities Group for the three months ending March 31, 2011, was $29.5 million, compared to $29.4 million in 2010.
Electric Utilities
Three Months Ended March 31, | Increase (Decrease) | |||||||||||
2011 | 2010 | 2011 vs. 2010 | ||||||||||
(in millions) | ||||||||||||
Gross margin | $ | 74.2 | $ | 64.1 | $ | 10.1 | ||||||
Operations and maintenance | 37.1 | 32.8 | 4.3 | |||||||||
Depreciation and amortization | 12.8 | 11.2 | 1.6 | |||||||||
Operating income | 24.3 | 20.2 | 4.2 | |||||||||
Interest expense, net | (9.9 | ) | (8.3 | ) | (1.6 | ) | ||||||
Other income | 0.4 | 2.1 | (1.7 | ) | ||||||||
Income tax (expense) | (4.5 | ) | (4.2 | ) | (0.3 | ) | ||||||
Net income (loss) | $ | 10.2 | $ | 9.9 | $ | 0.4 | ||||||
Three Months Ended March 31, | ||||||
Operating Statistics: | 2011 | 2010 | ||||
Retail sales - MWh | 1,146,182 | 1,153,855 | ||||
Contracted wholesale sales - MWh * | 89,959 | 168,465 | ||||
Off-system sales - MWh ** | 404,844 | 475,089 | ||||
1,640,985 | 1,797,409 | |||||
Total gas sales - Cheyenne Light - Dth | 1,948,705 | 2,042,836 | ||||
Regulated power plant availability: | ||||||
Coal-fired plants | 91.3 | % | 94.0 | % | ||
Other plants | 98.6 | % | 99.7 | % | ||
Total availability | 93.9 | % | 96.2 | % | ||
* Decrease in MWh due to termination of wholesale contracts when two previous wholesale power customers acquired an ownership interest in the Wygen III facility.
** Includes 75,803 MWh sold at Colorado Electric. Per a rate case order with the Colorado PUC, the margins associated with these sales have been deferred until settlement of a sharing mechanism is finalized.
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Gross margin increased primarily due to a $12.0 million impact from the Black Hills Power and Colorado Electric rate cases implemented during 2010 and additional margins of $1.1 million related to recent transmission investments. These increases were partially offset by a decrease in off-system sales margins, lower retail quantities at Colorado Electric, and a decrease in revenue resulting from two previous wholesale power customers acquiring an ownership interest in Wygen III. Additionally, Colorado Electric off-system sales margins have been deferred on the balance sheet until a sharing mechanism is finalized with the Colorado PUC.
Operations and maintenance increased primarily due to additional costs associated with the operations of Wygen III which commenced commercial operation on April 1, 2010, an increase in employee compensation and benefit costs and increased corporate allocations.
Depreciation and amortization increased primarily due to the commencement of depreciation on Wygen III.
Interest expense, net increased primarily due to higher debt balances related to recent capital projects and higher interest rates.
Other income decreased primarily due to lower AFUDC-equity, which decreased upon the placement of Wygen III into commercial operation.
Gas Utilities
Three Months Ended March 31, | Increase (Decrease) | |||||||||||
2011 | 2010 | 2011 vs. 2010 | ||||||||||
(in millions) | ||||||||||||
Gross margin | $ | 77.1 | $ | 75.7 | $ | 1.4 | ||||||
Operations and maintenance | 34.6 | 34.4 | 0.2 | |||||||||
Gain on sale of operating asset | — | (2.7 | ) | 2.7 | ||||||||
Depreciation and amortization | 6.0 | 7.0 | (1.0 | ) | ||||||||
Operating income | 36.6 | $ | 37.0 | $ | (0.4 | ) | ||||||
Interest expense, net | (7.0 | ) | (6.2 | ) | (0.8 | ) | ||||||
Other income (expense) | — | (0.2 | ) | 0.2 | ||||||||
Income tax benefit (expense) | (10.3 | ) | (11.1 | ) | 0.8 | |||||||
Net income (loss) | $ | 19.3 | $ | 19.5 | $ | (0.2 | ) | |||||
Three Months Ended March 31, | ||||||
Operating statistics: | 2011 | 2010 | ||||
Total gas sales - Dth | 24,987,870 | 26,141,390 | ||||
Total transport volumes - Dth | 16,286,552 | 17,811,747 | ||||
Gross margin increased primarily due to approved rate cases, partially offset by lower volumes.
Depreciation and amortization decreased primarily due to assets that became fully depreciated during 2010.
Interest expense, net increased primarily due to higher interest rates, partially offset by increased intercompany interest income.
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Non-regulated Energy Group - First Quarter 2011
Net loss from the Non-regulated Energy group for the three months ended March 31, 2011 was $3.5 million, compared to Net income of $7.1 million for the same period in 2010. Business segment results were as follows:
Power Generation
Three Months Ended March 31, | Increase (Decrease) | |||||||||||
2011 | 2010 | 2011 vs. 2010 | ||||||||||
(in millions) | ||||||||||||
Revenue | $ | 7.6 | $ | 8.1 | $ | (0.4 | ) | |||||
Operations and maintenance | 4.2 | 3.4 | 0.8 | |||||||||
Depreciation and amortization | 1.1 | 1.0 | — | |||||||||
Operating income | 2.4 | 3.7 | (1.3 | ) | ||||||||
Interest expense, net | (1.8 | ) | (2.0 | ) | 0.2 | |||||||
Other income (expense) | 1.2 | — | 1.2 | |||||||||
Income tax benefit (expense) | (0.6 | ) | (0.6 | ) | — | |||||||
Net income (loss) | $ | 1.2 | $ | 1.1 | $ | 0.1 | ||||||
Three Months Ended March 31, | ||||||
Operating Statistics: | 2011 | 2010 | ||||
Contracted fleet power plant availability - | ||||||
Coal-fired plant | 100.0 | % | 100.0 | % | ||
Natural gas-fired plant | 100.0 | % | 100.0 | % | ||
Total availability | 100.0 | % | 100.0 | % | ||
Revenue decreased primarily due to lower off-system sales.
Operations and maintenance increased primarily due to increased corporate allocations associated with Colorado IPP and higher Wygen I operating costs.
Other income increased due to higher earnings from our partnership investments and a gain on the sale of our ownership interest in the partnership which owned certain Idaho generation facilities.
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Coal Mining
Three Months Ended March 31, | Increase (Decrease) | |||||||||||
2011 | 2010 | 2011 vs. 2010 | ||||||||||
(in millions) | ||||||||||||
Revenue | $ | 15.5 | $ | 14.0 | $ | 1.5 | ||||||
Operations and maintenance | 14.6 | 10.2 | 4.3 | |||||||||
Depreciation and amortization | 4.6 | 2.9 | 1.7 | |||||||||
Operating income (loss) | (3.7 | ) | 0.8 | (4.5 | ) | |||||||
Interest income, net | 1.0 | 0.3 | 0.6 | |||||||||
Other income (expense) | 0.6 | 0.6 | — | |||||||||
Income tax benefit (expense) | 0.9 | (0.4 | ) | 1.2 | ||||||||
Net income (loss) | $ | (1.3 | ) | $ | 1.3 | $ | (2.6 | ) | ||||
Three Months Ended March 31, | ||||||
Operating Statistics: | 2011 | 2010 | ||||
(in thousands) | ||||||
Tons of coal sold | 1,370 | 1,392 | ||||
Cubic yards of overburden moved | 3,455 | 3,571 | ||||
Revenue increased primarily due to a 10 percent increase in average price received per ton. The higher average sales price reflects the impact of price escalators in certain of our coal sales contracts. Approximately 35 percent of our coal production is sold under contracts where the sales price escalates based on actual mining cost increases. In addition, approximately 60 percent of our production is sold under contracts where the sales price may escalate with published indices, which may not necessarily represent changes in actual mining costs. The increase in price received per ton during the quarter was partially offset by a 2 percent decrease in tons sold. Sales volumes decreased in 2011 as new quantities sold to the Wygen III plant beginning in April 2010 were more than offset by the negative impact from plant outages and the suspension of operations at the Osage power plant.
Operations and maintenance cost increases are reflective of the current phase of our mine where we have longer haul distances and higher overburden stripping costs. Additionally we experienced higher costs associated with drilling and blasting, equipment maintenance, fuel, and staffing levels for our train load-out facility. As noted above, approximately 60 percent of our production is sold under contracts which have price escalators based on published indices. These escalators have not kept up with actual mining cost increases, reducing coal mine operating income, which is expected to continue to negatively impact 2011 results. Previous periods also included the capitalization of certain costs associated with mine infrastructure, including our in-pit conveyor system that is used to transport coal to mine-mouth generation facilities.
Depreciation, depletion and amortization increased primarily due to higher depreciation of reclamation related costs and increased depreciation on equipment.
Interest income, net increased due to increased lending to affiliates at higher interest rates.
Income tax benefit (expense) for the period ending March 31, 2011 was favorably impacted by research and development credits; and for the period March 31, 2010, it was favorably impacted by a benefit generated by percentage depletion reducing the effective tax rate.
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Energy Marketing
Three Months Ended March 31, | Increase (Decrease) | |||||||||||
2011 | 2010 | 2011 vs. 2010 | ||||||||||
(in millions) | ||||||||||||
Gross margin | $ | 2.5 | $ | 9.8 | $ | (7.3 | ) | |||||
Operating expenses | 5.8 | 5.4 | 0.3 | |||||||||
Depreciation and amortization | 0.1 | 0.1 | — | |||||||||
Operating income (loss) | (3.4 | ) | 4.2 | (7.6 | ) | |||||||
Interest expense, net | (0.5 | ) | (0.8 | ) | 0.3 | |||||||
Income tax benefit (expense) | 1.2 | (1.2 | ) | 2.5 | ||||||||
Net income (loss) | $ | (2.6 | ) | $ | 2.2 | $ | (4.9 | ) | ||||
Three Months Ended March 31, | ||||
Operating Statistics: | 2011 | 2010 | ||
Average daily quantities - | ||||
Natural gas physical - MMBtus | 1,730,183 | 1,753,200 | ||
Crude oil physical - barrels | 21,243 | 13,430 | ||
Coal - tons (a) | 36,532 | — | ||
____________
(a) Represents the activity from the coal marketing business acquired on June 1, 2010.
Gross margin decrease was primarily driven by lower gross margin from both natural gas and crude oil marketing compared to the 2010 period. Power marketing activities, which began during the third quarter of 2010, produced a slight gross margin loss for the three months ended March 31, 2011. These decreases to gross margin were partially offset by approximately $2.7 million in gross margin provided by the coal marketing operations that began in the second quarter of 2010.
Operating expenses increased primarily due to higher compensation expense relating to staff marketing new commodities in new geographic regions, and an increase in fees primarily related to usage of letters of credit.
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Oil and Gas
Three Months Ended March 31, | Increase (Decrease) | |||||||||||
2011 | 2010 | 2011 vs. 2010 | ||||||||||
(in millions) | ||||||||||||
Revenue | $ | 17.9 | $ | 19.7 | $ | (1.8 | ) | |||||
Operations and maintenance | 10.6 | 9.7 | 0.8 | |||||||||
Depreciation and amortization | 7.3 | 6.1 | 1.2 | |||||||||
Operating income | — | 3.9 | (3.9 | ) | ||||||||
Interest expense, net | (1.4 | ) | (0.8 | ) | (0.6 | ) | ||||||
Other income (expense) | (0.2 | ) | 0.3 | (0.5 | ) | |||||||
Income tax benefit (expense) | 0.8 | (1.1 | ) | 1.9 | ||||||||
Net income (loss) | $ | (0.7 | ) | $ | 2.3 | $ | (3.1 | ) | ||||
Three Months Ended March 31, | ||||||||
Operating Statistics: | 2011 | 2010 | ||||||
Mcf equivalent sales | 2,755,958 | 2,658,522 | ||||||
Average price received: | ||||||||
Gas/Mcf | $ | 4.65 | $ | 5.91 | ||||
Oil/Bbl | $ | 66.83 | $ | 74.39 | ||||
Revenue decreased primarily due to a 21 percent decrease in the average hedged price of natural gas and a 10 percent decrease in the average hedged price of crude oil, partially offset by a 23 percent increase in crude oil volumes primarily from new wells in our ongoing Bakken drilling program in North Dakota. The decrease in crude oil price was influenced by fixed price swaps previously entered into at prices significantly below current crude oil market prices.
Operations and maintenance increased primarily due to increased compensation costs and ad valorem taxes.
Depreciation, depletion and amortization increased primarily due to a higher depletion rate and increased production. The increase in the depletion rate reflects the addition of higher cost oil reserves, primarily attributable to our Bakken drilling activities.
Interest expense increased primarily due to higher interest rates.
Income tax benefit (expense) for the first quarter of 2011 was impacted favorably by a credit for research and development projects reducing the effective tax rate.
Corporate - First Quarter 2011
Income for the three months ended March 31, 2011 was $0.9 million, compared to a loss of $5.0 million for the same period in 2010. Results for the first quarter of 2011 reflect a $3.6 million unrealized mark-to-market non-cash after-tax gain related to interest rate swaps no longer designated as hedges for accounting purpose compared to the first quarter of 2010, which included a $2.0 million unrealized mark-to-market non-cash after-tax loss related to interest rate swaps.
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ABOUT BLACK HILLS CORP.
Black Hills Corp. – a diversified energy company with a tradition of exemplary service and a vision to be the energy partner of choice – is based in Rapid City, S.D., with corporate offices in Denver and Papillion, Neb. The company serves 763,000 natural gas and electric utility customers in Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. The company's non-regulated businesses generate wholesale electricity, produce natural gas, oil and coal, and market energy. Black Hills employees partner to produce results that improve life with energy.
CAUTION REGARDING FORWARD-LOOKING STATEMENTS
This news release includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this news release that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation, the risk factors described in Item 1A of Part I of our 2010 Annual Report on Form 10-K filed with the SEC, and other reports that we file with the SEC from time to time, and the following:
• | Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and receive favorable rulings in periodic applications to recover costs for fuel, transmission and purchased power in our regulated utilities and the timing in which the new rates would go into effect; |
• | Our ability to receive regulatory approval to recover in rate base our expenditures for new generation facilities or other utility infrastructure; |
• | Our ability to complete the construction, start up and operation of power generation facilities in a cost-effective and timely manner; |
• | Our ability to overcome the challenges in our non-regulated businesses and obtain financial returns that meet shareholder expectation; |
• | Our ability to generate significant earnings improvement in 2012 and beyond; |
• | The accounting treatment and earnings impact associated with interest rate swaps; |
• | Capital market conditions and market uncertainties related to interest rates, which may affect our ability to raise capital on favorable terms; |
• | The timing, volatility and extent of changes in energy and commodity prices, supply or volume, the cost and availability of transportation of commodities, changes in interest rates or foreign exchange rates and the demand for our services, any of which can affect our earnings, financial liquidity and the underlying value of our assets, including the possibility that we may be required to take future impairment charges under the SEC's full cost ceiling test for natural gas and oil reserves; |
• | The timing and extent of scheduled and unscheduled outages of our power generating facilities; |
• | Our ability to successfully complete labor negotiations with labor unions with whom we have collective bargaining agreements and for which we are currently in, or soon to be in, contract renewal negotiations; |
• | Our ability to provide accurate estimates of proved oil and gas reserves and future production and associated costs; |
• | The extent of our success in connecting natural gas and crude oil to gathering, processing and pipeline systems; |
• | Changes in or compliance with laws and regulations, particularly those related to financial reform legislation, taxation, power generation, safety, protection of the environment and energy marketing; |
• | Weather and other natural phenomena; |
• | The effect of accounting policies issued periodically by accounting standard-setting policies; |
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• | Macro- and micro-economic changes in the economy and energy industry, including the impact of (i) consolidation and changes in competition and (ii) general economic and political conditions, including tax rates or policies and inflation rates; and |
• | Other factors discussed from time to time in our filings with the SEC. |
New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time-to-time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise.
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