Black Hills Corp. Reports 2013 Fourth Quarter and Full Year Results

Black Hills Corp. (NYSE: BKH) today announced 2013 fourth quarter and full year financial results. Adjusted income from continuing operations, a non-GAAP measure,* for the fourth quarter of 2013 was $31 million, or $0.70 per share, compared to $30 million, or $0.68 per share, for the same period in 2012. For the 12 months ending Dec. 31, 2013, adjusted income from continuing operations was $109 million, or $2.45 per share, compared to $92 million, or $2.09 per share, for the same period in 2012.

“We are proud of our continued strong performance and the board of directors’ recent approval of our 44th consecutive annual dividend increase,” said David R. Emery, chairman, chief executive officer and president of Black Hills Corp. “Adjusted earnings of $2.45 per share increased 17 percent compared to the prior year. Results were driven by earnings growth in our natural gas utilities, power generation and coal mining segments and lower interest expense. Our fourth quarter utility performance was stronger than expected due primarily to colder weather, helping drive earnings above our guidance range. Our solid performance was rewarded by the stock market, with Black Hills recording industry-best stock price performance in 2013.”

“We continued to lay a solid foundation for future earnings growth,” said Emery. “Construction is well underway for the $222 million, 132 megawatt Cheyenne Prairie Generating Station. Our oil and gas segment completed two horizontal wells in the Mancos Shale formation in the southern Piceance Basin and our Colorado Electric utility received approval for a new 40 megawatt natural gas-fired turbine. We also completed a $525 million debt offering, the largest in the company’s history, which captured favorable interest rates for 10 years while retiring higher cost debt.

“Since May, three leading credit ratings agencies have recognized Black Hills’ improved financial condition and business risk profile. One recently raised the company’s corporate credit rating to Baa1, while the other two raised our rating to BBB during 2013, acknowledging our growing earnings, increasing cash flows and improving balance sheet.

“On Jan. 30, 2014, we announced an increase in our quarterly dividend for the 44th consecutive year. Only two other electric or gas utility companies in the United States have a longer history of annual dividend increases.

“We remain excited about the future and our earnings growth potential. We have attractive investment opportunities in our utilities and remain encouraged by the potential of our Mancos Shale gas assets. Our solid financial performance and strengthened balance sheet position us to support and grow our businesses. Focusing on strong earnings growth, a superior customer experience, operational excellence and being a great workplace, we will continue our history of creating shareholder value for years to come,” concluded Emery.

Black Hills Corp. highlights for the fourth quarter and full year 2013, recent regulatory filings, updates and other events include:

Utilities

• On Jan. 17, 2014, Black Hills Power filed a request with the Wyoming Public Service Commission to increase its annual electric revenue by $2.8 million to recover investments made in electric infrastructure, including the Cheyenne Prairie Generating Station under construction in Cheyenne, Wyo.
• On Jan. 6, 2014, the Colorado Public Utilities Commission issued its initial written decision, approving a settlement agreement between Colorado Electric, commission staff and intervening parties for the Electric Resource Plan filed by Colorado Electric on May 1, 2013. The settlement approved the construction of a 40 megawatt, natural gas-fired combustion turbine to replace the retirement of the W.N. Clark power plant. The plan also included retirement of the aging Pueblo 5 and 6 units. A written order is expected in the first quarter of 2014.
• On Dec. 31, Colorado Electric retired its W.N. Clark coal-fired power plant in Cañon City, Colo., and its Pueblo 5 and 6 natural gas-fired steam units in Pueblo, Colo.
• On Dec. 2, Cheyenne Light Fuel & Power filed a request with the Wyoming Public Service Commission to increase annual revenue by $14 million to recover investments in electric and natural gas infrastructure, including the Cheyenne Prairie Generating Station.
• On Sept. 17, the South Dakota Public Utilities Commission approved Black Hills Power’s general rate case settlement agreement authorizing an increase of $8.8 million in annual electric revenue effective June 16, 2013.
• On Sept. 17, the South Dakota Public Utilities Commission approved Black Hills Power’s request for a construction financing rider effective April 1, 2013, for Cheyenne Prairie Generating Station in lieu of the traditional allowance for funds used during construction. The rider allows recovery of financing costs during the construction period, reducing long-term customer costs.
• On April 8, construction commenced on the 132 megawatt Cheyenne Prairie Generating Station. Commercial operation is expected in the fourth quarter of 2014. Costs for plant construction and associated transmission are estimated at $222 million, and the project is currently on schedule and within budget. Joint ownership of the plant by Black Hills Power and Cheyenne Light Fuel & Power creates operating and cost efficiencies, reducing overall customer costs.
• Efforts continued to acquire small natural gas distribution systems near existing utility service territories. During 2013, five systems with a total of approximately 900 customers were added. In January 2014, another acquisition was announced that will add 400 customers in northeastern Wyoming. This transaction requires approval by the Wyoming Public Service Commission and is expected to close by year-end 2014.

Non-Regulated Energy

• Two horizontal wells were drilled and completed in the Mancos Shale formation in the southern Piceance Basin. One well was placed on production late December 2013 and the second well was placed on production late January 2014. These wells were part of a transaction in which we earned approximately 20,000 net acres of Mancos Shale leasehold in exchange for drilling and completing the two wells.
• On May 7, Black Hills Wyoming entered into an agreement to sell its 40 megawatt CTII natural gas-fired generating unit to the City of Gillette for approximately $22 million, subject to closing adjustments. The sale is expected to close in August 2014 upon the expiration of an existing power sale agreement. The sale is subject to Federal Energy Regulatory Commission approval and other requirements included in the contract.

Corporate

• On Jan. 30, 2014, Black Hills’ board of directors approved an increase in the quarterly dividend of $0.01 per common share to $0.39 per share, equivalent to an annual increase of $0.04 and dividend rate of $1.56 per share. This represents the 44th consecutive annual dividend increase. Common shareholders of record at the close of Feb. 14, 2014, will receive $0.39 per share, payable on March 1, 2014.
• On Nov. 19, the company completed its largest ever public debt offering. Proceeds from the $525 million, 4.25 percent, 10 year senior unsecured notes were used to retire higher cost debt, settle interest rate swaps and pay down other corporate borrowings.
• Since May, three credit ratings agencies have raised their corporate credit ratings for Black Hills. On Jan. 30, 2014, Moody’s Investors Service raised the company’s corporate rating to Baa1 from Baa2, with a stable outlook. Moody’s had previously raised the company’s corporate credit rating to Baa2 from Baa3, with a positive outlook, on Sept. 25. On July 24, Standard & Poor’s Ratings Agency raised the corporate credit rating to BBB from BBB-, with a stable outlook. On May 10, Fitch Ratings raised the company’s corporate credit rating to BBB from BBB-, with a positive outlook.
• On June 21, the company closed a $275 million unsecured term loan with a maturity date of June 19, 2015. The loan has a cost of borrowing based on LIBOR plus a spread of 112.5 basis points per annum. The proceeds of the loan were used to repay term loans of $100 million and $150 million and other short-term debt.

2014 EARNINGS GUIDANCE REAFFIRMED

Black Hills reaffirms its guidance for 2014 earnings from continuing operations, as adjusted, to be in the range of $2.50 to $2.70 per share as most recently issued on Dec. 2, 2013.

CONFERENCE CALL AND WEBCAST

The company will host a live conference call and webcast at 11 a.m. EST on Friday, Feb. 7, 2014, to discuss the company’s financial and operating performance.

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 on “Events & Presentations” 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. Those interested in asking a question during the live broadcast or those without internet access can call 866-318-8617 if calling within the United States. International callers can call 617-399-5136. All callers need to enter the pass code 24636203 when prompted.

For those unable to listen to the live broadcast, a replay will be available on the company’s website or by telephone through Friday, Feb. 14, 2014, at 888-286-8010 in the United States and at 617-801-6888 for international callers. The replay pass code is 88261801.

USE OF NON-GAAP FINANCIAL MEASURE

As noted in this news release, in addition to presenting its earnings information in conformity with Generally Accepted Accounting Principles (GAAP), 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. Income (loss) from continuing operations, as adjusted, and Net income (loss), as adjusted, is defined as Income (loss) from continuing operations and Net income (loss), adjusted for expenses and gains that the company believes do 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. The company’s management uses these non-GAAP financial measures as an indicator for planning and forecasting future periods. These non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Our presentation of these Non-GAAP financial measures should not be construed as an inference that our future results will be unaffected by other income and expenses that are unusual, non-routine or non-recurring.

Gross margin (revenue less cost of sales) is considered a non-GAAP financial measure due to the exclusion of deprecation from the measure. The presentation of gross margin is intended to supplement investors’ understanding of operating performance. Gross margin for our Electric Utilities is calculated as operating revenue less cost of fuel, purchased power and cost of gas sold. Gross margin for our Gas Utilities is calculated as operating revenue less cost of gas sold. Our gross margin is impacted by the fluctuations in power purchases and natural gas and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to customers. Our gross margin measure may not be comparable to other companies’ gross margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

GAAP TO NON-GAAP ADJUSTMENT RECONCILIATION

BUSINESS UNIT PERFORMANCE SUMMARY

Business Group highlights for the three months and 12 months ended Dec. 31, 2013, compared to the three months and 12 months ended Dec. 31, 2012, are discussed below. The following business group and segment information does not include certain inter-company eliminations or discontinued operations. Minor differences in comparative amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated. Prior period information was revised to reclassify information related to discontinued operations.

Utilities Group

Income from continuing operations for the Utilities Group for the three months ended Dec. 31, 2013, was $27 million, compared to $26 million for the same period in 2012 while income from continuing operations for the 12 months ended Dec. 31, 2013, was $85 million, compared to $80 million in 2012.

Electric Utilities

(a) 2012 reflects a planned overhaul at Wygen II.

Fourth Quarter 2013 Compared to Fourth Quarter 2012

Gross margin increased primarily due to a return on additional investments which increased base electric margins by $2.1 million, and increased rider margins of $2.7 million. These are partially offset by a $2.1 million construction savings incentive payment received by Colorado Electric in 2012.

Operations and maintenance increased primarily due to property taxes, vegetation management and employee costs.

Depreciation and amortization increased primarily due to a higher asset base.

Interest expense, net increased primarily due to lower AFUDC.

Income tax: The effective tax rate decreased in 2013 primarily due to an unfavorable income tax true-up adjustment that impacted 2012.

Full Year 2013 Compared to Full Year 2012

Gross margin increased primarily due to a return on additional investments which increased base electric margins by $5.9 million, increased rider margins by $9.4 million, and a $2.2 million increase at our gas utility due to an increase in volumes driven by a 17 percent increase in heating degree days. These are partially offset by a $2.1 million construction savings incentive received by Colorado Electric in 2012 compared to $0.7 million received in 2013.

Operations and maintenance increased primarily due to property taxes, vegetation management and employee costs. Prior year included a $2.1 million reduction of major maintenance accruals related to plant suspensions and retirements.

Depreciation and amortization increased primarily due to a higher asset base.

Interest expense, net increased primarily due to lower AFUDC.

Income tax: The effective tax rate decreased primarily due to an unfavorable income tax true-up adjustment that impacted 2012.

Gas Utilities

Fourth Quarter 2013 Compared to Fourth Quarter 2012

Gross margin increased primarily due to a $2.8 million increase resulting from higher retail volumes driven by a 15 percent increase in heating degree days, and a $0.9 million increase in transport margins.

Operations and maintenance increased primarily due to an increase in employee costs.

Income tax: The effective tax rate for the fourth quarter of 2013 increased primarily as a result of favorable flow-through tax adjustment that benefited 2012.

Full Year 2013 Compared to Full Year 2012

Gross margin increased primarily due to a $12 million increase resulting from higher retail volumes driven by a 25 percent increase in heating degree days. Transport margins increased $2.9 million, surcharge revenue increased $1.9 million primarily due to additional capital investments, and $1.3 million of additional margin was attributed to year over year customer growth.

Operations and maintenance increased primarily due to employee costs, property taxes and uncollectible accounts attributed to increased revenue.

Depreciation and amortization increased primarily due to a higher asset base.

Interest expense, net was comparable to the same period in the prior year.

Income tax: The effective tax rate for 2013 increased primarily as a result of favorable flow-through tax adjustment that benefited 2012.

Non-Regulated Energy Group

Loss from continuing operations from the Non-regulated Energy group for the three months ended Dec. 31, 2013, was $0.5 million, compared to income from continuing operations of $7.1 million for the same period in 2012. Income from continuing operations from the Non-regulated Energy group for the 12 months ended Dec. 31, 2013, was $18 million compared to $25 million for the same period in 2012.

Power Generation

(a) Availability for three months ended Dec. 31, 2013, was impacted by a planned outage at Wygen I.

Fourth Quarter 2013 Compared to Fourth Quarter 2012

Revenue increased primarily due to an increase in megawatt hours delivered at a higher price.

Operations and maintenance increased primarily due to increased materials and outside services.

Depreciation and amortization was comparable to the prior year. The generating facility located in Pueblo, Colo. is accounted for as a capital lease under GAAP; as such, depreciation expense for the original cost of the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net increased primarily due to the cost to settle the interest rate swaps associated with Black Hills Wyoming’s project financing of $7.7 million, and a $2.4 million write-off of related deferred financing costs.

Income tax: The fourth quarter of 2013 resulted in a pre-tax net loss yet produced a tax expense due to an unfavorable true-up adjustment.

Full Year 2013 Compared to Full Year 2012

Revenue increased primarily due to $2.1 million relating to increased megawatt hours delivered at higher prices, and $2.3 million related to increased volumes and pricing for off-system sales at Black Hills Wyoming.

Operations and maintenance increased primarily due to two Wygen 1 outages, partially offset by decreased property taxes at Black Hills Colorado IPP.

Depreciation and amortization were comparable to the same period in the prior year. The generating facility located in Pueblo, Colo. is accounted for as a capital lease under GAAP; as such, depreciation expense for the original cost of the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net increased primarily due to $7.7 million relating to the cost to settle the interest rate swaps associated with Black Hills Wyoming’s project financing and a $2.4 million write-off of related deferred financing costs, partially offset by lower inter-company debt.

Income tax: The effective tax rate in 2013 increased as a result of an unfavorable tax true-up adjustment.

Coal Mining

Fourth Quarter 2013 Compared to Fourth Quarter 2012

Revenue decreased primarily due to a 3 percent decrease in tons sold as a result of an unplanned outage at the Pacificorp operated Wyodak plant, along with an accelerated Wygen 1 outage, and a decrease in pricing on contracts containing price adjustments. Approximately 50 percent of our coal production is sold under contracts that include price adjustments based on actual mining costs, including income taxes. Our mining costs have trended down due to lower operations and maintenance costs, thereby decreasing our price per ton for these customers.

Operations and maintenance decreased primarily due to mining in areas with lower overburden, resulting in decreased fuel costs and reduced employee costs, partially offset by materials and outside services related to major maintenance projects.

Depreciation, depletion and amortization decreased primarily due to lower depreciation on mine assets and lower depreciation of mine reclamation costs.

Interest (expense) income, net was comparable to the same period in the prior year.

Income tax: The effective tax rate was comparable to the same period in the prior year.

Full Year 2013 Compared to Full Year 2012

Revenue decreased primarily due to a 9 percent decrease in the average price per ton charged on coal sold under contracts containing price adjustments, partially offset by a 1 percent increase in tons sold. Approximately 50 percent of our current coal production is sold under contracts that include price adjustments based on actual mining costs. Approximately 50 percent of our coal production is sold under contracts that include price adjustments based on actual mining costs, including income taxes. Our mining costs have trended down due to lower operations and maintenance costs, thereby decreasing our price per ton for these customers.

Operations and maintenance decreased primarily due to mining in areas with lower overburden, resulting in decreased fuel costs and reduced employee costs, partially offset by materials and outside services related to major maintenance projects.

Depreciation, depletion and amortization decreased primarily due to lower depreciation on mine assets and lower depreciation of mine reclamation costs.

Interest income, net reflects decreased interest income primarily due to a decrease in the inter-company notes receivable, reduced by payment of a dividend to our parent.

Income tax: The effective tax rate increased in 2013 as a result of lower percentage depletion. In addition, the effective tax rate in 2012 was impacted by a favorable true-up adjustment that was primarily driven by an increased percentage depletion deduction reported on the 2011 tax return.

Oil and Gas

(a) Oil and gas reserve information is based on reports prepared by Cawley, Gillespie & Associates, Inc. an independent consulting and engineering firm.

Fourth Quarter 2013 Compared to Fourth Quarter 2012

Revenue increased primarily due to an 11 percent increase in volumes sold, partially offset by a 13 percent decrease in the average hedged price received for crude oil sold and a 20 percent decrease in the average hedged price received for natural gas sold.

Operations and maintenance decreased primarily due to lower non-operated well costs and lower production taxes and ad valorem taxes on reduced revenue.

Gain on sale of operating assets represents a post-closing adjustment to the 2012 gain on sale of our Williston Basin assets. We follow the full-cost method of accounting for oil and gas activities, which typically does not allow for gain on sale recognition unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves.

Depreciation, depletion and amortization increased primarily due to an increase in volumes sold.

Interest expense, net was comparable to the same period in the prior year.

Income tax benefit (expense): In 2013, a pre-tax net loss was generated that resulted in an income tax benefit. The effective tax rate in 2013 reflects a favorable true-up adjustment that increased the tax benefit. The effective tax rate in the fourth quarter of 2012 was impacted by an unfavorable property related deferred income tax true-up adjustment.

Full Year 2013 Compared to Full Year 2012

Revenue decreased primarily due to a 24 percent decrease in volumes sold as a result of the sale of our Williston Basin assets in 2012, a natural production decline in our gas wells and a 19 percent decrease in average price received for natural gas sold, partially offset by an 7 percent increase in the average price received for crude oil sold.

Operations and maintenance decreased primarily due to lower non-operated well costs and lower production taxes and ad valorem taxes on reduced revenue.

Gain on sale of operating assets represents the gain on the sale of our Williston Basin assets in 2012. We follow the full-cost method of accounting for oil and gas activities, which typically does not allow for gain on sale recognition unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves.

Depreciation, depletion and amortization decreased primarily due to a lower proportion of our total reserves being from crude oil in 2013, resulting from the sale of our Williston Basin assets in 2012.

Impairment of long-lived assets represents a write-down in the value of our natural gas and crude oil properties driven by low natural gas prices in the second quarter of 2012. The write-down reflected a 12-month average NYMEX price of $3.15 per Mcf, adjusted to $2.66 per Mcf at the wellhead, for natural gas, and $95.67 per barrel, adjusted to $85.36 per barrel at the wellhead, for crude oil.

Interest expense, net reflects lower interest expense primarily due to decreased debt as a result of proceeds from the sale of our Williston Basin assets in 2012.

Income tax (expense) benefit: Each period presented produced a pre-tax net loss that resulted in an income tax benefit. The effective tax rate in 2013 reflects lower percentage depletion.

Corporate

Fourth Quarter 2013 Compared to Fourth Quarter 2012

Loss from continuing operations for the three months ended Dec. 31, 2013, was $7.1 million compared to loss from continuing operations of $1.9 million for the same period in the prior year. Results for the fourth quarter of 2013 reflect a $0.8 million non-cash unrealized mark-to-market gain related to certain interest rate swaps compared to the fourth quarter of 2012, which included a $4.8 million non-cash unrealized mark-to-market gain related to these same interest rate swaps. Corporate results for fourth quarter of 2013 also include $10 million of costs related to early retirement of $250 million senior unsecured notes including a make-whole premium, write-off of deferred financing costs and interest expense on new debt, compared to a make-whole premium of $7.1 million in the fourth quarter of 2012 related to the early retirement of $225 million senior unsecured notes.

Full Year 2013 Compared to Full Year 2012

Income from continuing operations for the 12 months ended Dec. 31, 2013, was $13 million compared to a loss from continuing operations of $16 million for the same period in the prior year. Results for the year ended Dec. 31, 2013 reflect a $30 million non-cash unrealized mark-to-market gain related to certain interest rate swaps compared to 2012, which included a $1.9 million non-cash unrealized mark-to-market gain related to these same interest rate swaps. Corporate results for 2013 also include $10 million of costs related to early retirement of $250 million senior unsecured notes including a make-whole premium, write-off of deferred financing costs and interest expense on new debt, compared to a make-whole premium of $7.1 million in 2012 relating to the early retirement of $225 million senior unsecured notes. Results for 2012 also include $2.2 million of indirect costs and inter-segment interest expense previously charged to our Energy Marketing segment that could not be reclassified to discontinued operations in accordance with GAAP.

Discontinued Operations

On Feb. 29, 2012, we sold the outstanding stock of Enserco, our Energy Marketing segment. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds at date of the sale were approximately $165 million, subject to final post-closing adjustments. The proceeds represent approximately $108 million received from the buyer and approximately $58 million cash retained from Enserco before closing.

The buyer asserted certain purchase-price adjustments, some that we accepted, and several that we disputed. The disputed claims were substantially resolved in our favor through a binding arbitration decision dated Jan. 17, 2014. We expensed $1.4 million in 2012, related to purchase price adjustments we accepted through a partial settlement agreement with the buyer, and an additional $1.1 million in 2013 related to the claims assigned to arbitration. Loss from discontinued operations was $0.9 million and $7.0 million for the twelve months ended Dec. 31, 2013 and Dec. 31, 2012, respectively, inclusive of these settlement and arbitration decision amounts.

ABOUT BLACK HILLS CORP.

Black Hills Corp. (NYSE: BKH), a growth-oriented, vertically-integrated 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. The company serves 769,000 natural gas and electric utility customers in Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. The company generates wholesale electricity, and produces natural gas, crude oil and coal. Black Hills employees partner to produce results that improve life with energy. More information is available at www.blackhillscorp.com.

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. This includes, without limitations, our 2014 earnings guidance. 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 2012 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:

• The accuracy of our assumptions on which our earnings guidance is based;
• Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and favorable rulings in periodic applications to recover costs for capital additions, plant retirements and decommissioning, fuel, transmission, purchased power and other operating costs, and the timing in which new rates would go into effect;
• Our ability to gain regulatory approval and favorable regulatory treatment for putting new generation into rate base and the timing of any transaction;
• Our ability to complete our capital program in a cost-effective and timely manner, including our ability to successfully develop our Mancos Shale gas reserves located in the San Juan and Southern Piceance Basins;
• Our ability to provide accurate estimates of proved crude oil and natural gas reserves and future production and associated costs; 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.