| Business Description and Significant Accounting Policies | BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES Business Description Black Hills Corporation is a customer-focused, growth-oriented, vertically-integrated utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Mining, and Oil and Gas. Segment Reporting Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Prior to 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments. However, we will no longer separate the segments by business group. Our Electric Utilities segment includes the operating results of the regulated electric utility operations of South Dakota Electric, Wyoming Electric and Colorado Electric, which supply regulated electric utility services to areas in South Dakota, Wyoming, Colorado and Montana. Our Gas Utilities Segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Wyoming and Nebraska. All of our non-utility business segments support our electric utilities, other than the Oil and Gas segment. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. Our Oil and Gas segment, which is conducted through BHEP and its subsidiaries, engages in crude oil and natural gas exploration and production activities in Colorado, Louisiana, Montana, Oklahoma, New Mexico, North Dakota, Wyoming, Texas and California. Our Oil and Gas segment’s focus is on cost of service gas programs. We are divesting non-core oil and gas assets while retaining those best suited for a cost of service gas program and have refocused our professional staff on assisting our utilities with the implementation of a Cost of Service Gas Program. For further descriptions of our reportable business segments, see Note 5 . The following changes have been made to our Consolidated Statements of Income (Loss) to reflect combined revenue and combined operations and maintenance expenses, rather than by business group as previously reported, for the twelve months ended December 31, 2015 and December 31, 2014 respectively: Year Ended December 31, 2015 Year Ended December 31, 2014 (in thousands) As Previously Reported Presentation Reclassification As Currently Reported As Previously Reported Presentation Reclassification As Currently Reported Revenue: Utilities $ 1,219,526 $ (1,219,526 ) $ — $ 1,300,969 $ (1,300,969 ) $ — Non-regulated energy $ 85,079 $ (85,079 ) $ — $ 92,601 $ (92,601 ) $ — Revenue $ — $ 1,304,605 $ 1,304,605 $ — $ 1,393,570 $ 1,393,570 Operating Expenses: Utilities - operations and maintenance $ 272,407 $ (272,407 ) $ — $ 270,954 $ (270,954 ) $ — Non-regulated energy operations and maintenance $ 88,702 $ (88,702 ) $ — $ 88,141 $ (88,141 ) $ — Operations and maintenance $ — $ 361,109 $ 361,109 $ — $ 359,095 $ 359,095 This presentation reclassification did not impact our consolidated financial position, results of operations or cash flows. Segment Reporting Transition of Cheyenne Light’s Natural Gas Distribution Effective January 1, 2016, the natural gas operations of Cheyenne Light have been included in our Gas Utilities Segment. Through December 31, 2015 , Cheyenne Light’s natural gas operations were included in our Electric Utilities Segment as these natural gas operations were consolidated within Cheyenne Light since its acquisition. This change is a result of our business segment reorganization to, among other things, integrate all regulated natural gas operations, including the SourceGas Acquisition, into our Gas Utilities Segment which is led by the Group Vice President, Natural Gas Utilities. Likewise, all regulated electric utility operations, including Cheyenne Light’s electric utility operations, are reported in our Electric Utilities Segment, which is led by the Group Vice President, Electric Utilities. The prior periods have been reclassified to reflect this change in presentation between the Electric Utilities and Gas Utilities segments. See Note 5 for Revenues and Net Income amounts reclassified from the Electric Utilities segment to the Gas Utilities segment for the twelve months ended December 31, 2015 and December 31, 2014 ; and Segment Assets reclassified from the Electric Utilities segment to the Gas Utilities segment for the twelve months ended December 31, 2015 . This segment reclassification did not impact our consolidated financial position, results of operations or cash flows. Revisions Certain revisions have been made to prior years’ financial information to conform to the current year presentation. The Company revised its presentation of cash and book overdrafts. For accounts with the same financial institution where there is a banking arrangement that clears payments with balances in other bank accounts, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Prior year amounts were corrected to conform with the current year presentation, which decreased cash and cash equivalents and accounts payable by $16 million , $12 million and $3.8 million as of December 31, 2015, December 31, 2014 and December 31, 2013, respectively, and decreased net cash flows provided by operations by $3.7 million and $8.1 million for the years ended December 31, 2015 and 2014 respectively. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the consolidated balance sheet as of December 31, 2015 and to the consolidated statements of cash flows for the years ended December 31, 2015 and 2014. There is no impact to the Consolidated Statements of Income (Loss), the Consolidated Statements of Comprehensive Income (Loss) or the Consolidated Statements of Equity, for any period reported. Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates. Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. Investment in non-controlled entities over which we have the ability to exercise significant influence over operating and financial policies are accounted for using the equity method of accounting. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for our proportionate share of earnings and losses and distributions. Under this method, a proportionate share of pretax income is recorded as Equity earnings (loss) of unconsolidated subsidiaries. All inter-company balances and transactions have been eliminated in consolidation. For additional information on inter-company revenues, see Note 5 . Our Consolidated Statements of Income (Loss) include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie and the BHEP gas processing plant. See Note 4 for additional information. Variable Interest Entities We evaluate arrangements and contracts with other entities to determine if they are VIEs and if so, if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements. A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIEs most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated. Our evaluation of whether it qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 12. Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Restricted Cash and Equivalents We maintain cash accounts for various specified purposes. Therefore, we classify these amounts as restricted cash. Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Mining, Oil and Gas, and Power Generation business segments consists of amounts due from sales of coal, crude oil and natural gas, electric energy and capacity. We maintain an allowance for doubtful accounts which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. Following is a summary of accounts receivable as of December 31 (in thousands): 2016 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 41,730 $ 36,463 $ (353 ) $ 77,840 Gas Utilities 88,168 88,329 (2,026 ) 174,471 Power Generation 1,420 — — 1,420 Mining 3,352 — — 3,352 Oil and Gas 3,991 — (13 ) 3,978 Corporate 2,228 — — 2,228 Total $ 140,889 $ 124,792 $ (2,392 ) $ 263,289 2015 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities (a) $ 41,679 $ 35,874 $ (727 ) $ 76,826 Gas Utilities (a) 30,330 32,869 (1,001 ) 62,198 Power Generation 1,187 — — 1,187 Mining 2,760 — — 2,760 Oil and Gas 3,502 — (13 ) 3,489 Corporate 1,026 — — 1,026 Total $ 80,484 $ 68,743 $ (1,741 ) $ 147,486 ________________ (a) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility accounts receivable has been reclassified from the Electric Utilities segment to the Gas Utilities segment. Accounts receivable of $6.8 million as of December 31, 2015 , previously reported in the Electric Utilities segment is now presented in the Gas Utilities segment. Revenue Recognition Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales and franchise taxes collected from our customers is recorded on a net basis (excluded from Revenue). Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets. For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement. Natural gas and crude oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectibility of the revenue is reasonably assured. Our Oil and Gas segment records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, crude oil, condensate and NGLs is adjusted for transportation costs and other related deductions when applicable. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Materials, Supplies and Fuel The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of (in thousands): December 31, 2016 December 31, 2015 Materials and supplies $ 68,456 $ 55,726 Fuel - Electric Utilities 3,667 5,567 Natural gas in storage 35,087 25,650 Total materials, supplies and fuel $ 107,210 $ 86,943 Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are valued using weighted-average cost. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas. Accrued Liabilities The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of (in thousands): December 31, 2016 December 31, 2015 Accrued employee compensation, benefits and withholdings $ 56,926 $ 43,342 Accrued property taxes 40,004 32,393 Accrued payments related to litigation expenses and settlements — 38,750 Customer deposits and prepayments 51,628 53,496 Accrued interest and contract adjustment payments 45,503 25,762 Other (none of which is individually significant) 49,973 38,318 Total accrued liabilities $ 244,034 $ 232,061 Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our base or “cushion gas” as property, plant and equipment. Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred. Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various class of property. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run. Oil and Gas Operations We account for our oil and gas activities under the full cost method. Under the full cost method, costs related to acquisition, exploration and estimated future expenditures to be incurred in developing proved reserves as well as estimated reclamation and abandonment costs, net of estimated salvage values are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are typically treated as adjustments to the cost of the properties with no gain or loss recognized. Costs directly associated with unproved properties and major development projects, if any, are excluded from the costs to be amortized. These excluded costs are subsequently included within the costs to be amortized when it is determined whether or not proved reserves can be assigned to the properties. The properties excluded from the costs to be amortized are assessed for impairment at least annually and any amount of impairment is added to the costs to be amortized. These costs are generally expected to be included in costs to be amortized within the term of the underlying lease agreement, which varies in length. Under the full cost method, net capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC, plus the lower of cost or market value of unevaluated properties. Future net cash flows are estimated based on SEC-defined end-of-period commodity prices adjusted for contracted price changes and held constant for the life of the reserves. An average price is calculated using the price at the first day of each month for each of the preceding 12 months. If the net capitalized costs exceed the full cost “ceiling” at period end, a permanent non-cash write-down would be charged to earnings in that period. As a result of lower natural gas prices, we recorded non-cash ceiling test impairments of oil and gas long-lived assets included in the Oil and Gas segment in 2016 and 2015. No ceiling test write-down was recorded in 2014. See Note 13 for additional information. The SEC definition of “reliable technology” permits the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to calculate PUDs to be booked at more than one location away from a producing well. We have no PUDs at December 31, 2016. See information on our oil and gas drilling activities in Note 21 . Companies are permitted but not required to disclose probable and possible reserves. We have elected not to report these additional reserve categories. Goodwill and Intangible Assets Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives. We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Beginning in 2016, we changed our annual goodwill impairment testing date from November 30 to October 1 to better align the testing date with our financial planning process. We believe that the change in the date of the annual goodwill impairment test from November 30 to October 1 is not a material change in the application of an accounting principle. The new and old testing dates are close in proximity; both are in the fourth quarter of the year, and our current testing date is within ten months of the most recent impairment testing. We would not expect a materially different outcome as a result of testing on October 1 as compared to November 30. The change in assessment date does not have a material effect on the financial statements. We estimated the fair value of the goodwill using discounted cash flow methodology, EBITDA multiple method and an analysis of comparable transactions. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital and long-term earnings and merger multiples for comparable companies. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. See Note 5 for additional business segment information. Goodwill at our Electric utilities primarily arose from Colorado Electric, acquired in the Aquila acquisition, which allocated approximately $246 million , or 72% of the transaction to Colorado Electric. Goodwill at our Gas Utilities is primarily from the SourceGas Acquisition, which was allocated entirely to the Gas Utilities adding $940 million in goodwill and the Aquila Transaction, which allocated approximately $94 million , or 28% of the transaction, to the Gas Utilities. We believe that the goodwill reflects the inherent value of the relatively stable, long-lived cash flows of the regulated electric and gas utility businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our utilities. Goodwill balances were as follows (in thousands): Electric Utilities (a) Gas Utilities (a) Power Generation Total Ending balance at December 31, 2014 $ 248,479 $ 96,152 $ 8,765 $ 353,396 Additions (b) — 6,363 — 6,363 Ending balance at December 31, 2015 $ 248,479 $ 102,515 $ 8,765 $ 359,759 Additions (c) — 939,695 — 939,695 Ending balance at December 31, 2016 $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 _________________ (a) Goodwill of $2.0 million and $6.3 million for December 31, 2014 and December 31, 2015, respectively, is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utilities segment, previously reported in the Electric Utilities segment. See above in this Note 1 for additional details. (b) Goodwill was recorded on the July 1, 2015 acquisition of Wyoming natural gas utility Energy West Wyoming, Inc., and natural gas pipeline assets from Energy West Development, Inc. (c) Represents goodwill recorded with the acquisition of SourceGas. See Note 2 for more information. Our intangible assets represent easements, rights-of-way, customer listings, and trademarks and are amortized using a straight-line method based on estimated useful lives. The finite lived intangible assets are currently being amortized from 2 years up to 40 years . Changes to intangible assets for the years ended December 31, were as follows (in thousands): 2016 2015 2014 Intangible assets, net, beginning balance $ 3,380 $ 3,176 $ 3,397 Additions 5,522 434 — Amortization expense (a) (510 ) (230 ) (221 ) Intangible assets, net, ending balance $ 8,392 $ 3,380 $ 3,176 _________________ (a) Amortization expense for existing intangible assets is expected to be $0.8 million for each year of the next five years. Asset Retirement Obligations Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income (Loss). The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability. We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations, other than Oil and Gas. For the Oil and Gas segment, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and depleted pursuant to our use of the full cost method. Additional information is included in Note 8 . Fair Value Measurements Derivative Financial Instruments Assets and liabilities are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. Valuation Methodologies for Derivatives Oil and Gas Segment: • The commodity contracts for the Oil and Gas segment are valued under the market approach and include exchange-traded futures and basis swaps. Fair value was derived using exchange quoted settlement prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third party sources and therefore support Level 2 disclosure. Electric Utilities and Gas Utilities Segments: • The commodity contracts for the Utilities, valued using the market approach, include exchange-traded futures, options, basis swaps and over-the-counter swaps (Level 2) for natural gas contracts. For exchanged-traded futures, options and basis swap Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For over-the-counter swaps and option Level 2 assets and liabilities, fair value was derived from, or corroborated by, observable market data where market data for pricing is observable. In addition, the fair value for the over-the-counter swaps and option derivatives include a CVA component. The CVA considers the fair value of the derivative and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings. Corporate Segment: • The interest rate swaps are valued using the market valuation approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for |
