| SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
| Dec. 31, 2013 |
| Accounting Policies [Abstract] | ' |
| SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ' |
| | | | |
| A. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | | | |
|
| Organization and Nature of Operations - ONEOK Partners, L.P. is a publicly traded master limited partnership, organized under the laws of the state of Delaware, that was formed in 1993. Our equity consists of a 2 percent general partner interest and a 98 percent limited partner interest. Our limited partner interests are represented by our common units, which are listed on the NYSE under the trading symbol “OKS,” and our Class B limited partner units. We are managed under the direction of the Board of Directors of our sole general partner, ONEOK Partners GP. ONEOK Partners GP is a wholly owned subsidiary of ONEOK. ONEOK and its subsidiaries own a 41.2 percent aggregate equity interest in us. |
|
| Our operations include gathering and processing of natural gas produced from crude oil and natural gas wells. We gather and process natural gas in the Mid-Continent region, which includes the NGL-rich Cana-Woodford Shale, Woodford Shale and Granite Wash areas, the Mississippian Lime formation of Oklahoma and Kansas, and the Hugoton and Central Kansas Uplift Basins of Kansas. We also gather and/or process natural gas in two producing basins in the Rocky Mountain region: the Williston Basin, which spans portions of Montana and North Dakota and includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations, and the Powder River Basin of Wyoming, which includes the NGL-rich Frontier, Turner, Sussex and Niobrara Shale formations. Some of the natural gas we gather in the Powder River Basin of Wyoming is coal-bed methane, or dry natural gas, that does not require processing or NGL extraction in order to be marketable; dry natural gas is gathered, compressed and delivered into a downstream pipeline or market for a fee. The natural gas we gather from wells that supply our Sage Creek plant contains NGL-rich natural gas from the Niobrara Shale area of the Powder River Basin. |
|
| Our natural gas liquids assets consist of facilities that gather, fractionate and treat NGLs and store NGL products primarily in Oklahoma, Kansas, Texas and the Rocky Mountain region where we provide nondiscretionary services to producers of NGLs. We own or have an ownership interest in FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Texas, Wyoming, Colorado, North Dakota and Montana, and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois. We also own FERC-regulated natural gas liquids distribution and refined petroleum products pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois. We own and operate truck- and rail-loading and -unloading facilities that interconnect with our NGL fractionation and pipeline assets. |
|
| Our FERC-regulated interstate natural gas pipeline assets transport natural gas through gas pipelines in North Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico. Our interstate pipeline companies include Midwestern Gas Transmission, Viking Gas Transmission, Guardian Pipeline, OkTex Pipeline and Northern Border Pipeline of which we have a 50 percent interest. |
|
| Our intrastate natural gas pipeline assets in Oklahoma transport our gas through the state and have access to the major natural gas producing areas in Oklahoma, including the Cana-Woodford Shale, Woodford Shale, Granite Wash and Mississippian Lime areas, and transport natural gas throughout the state. We also have access to the major natural gas producing areas, including the Mississippian Lime formation in south central Kansas. In Texas, our intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas panhandle, including the Granite Wash area and the Delaware and Cline producing areas in the Permian Basin and transport natural gas throughout the western portion of the state, including the Waha Hub, where other pipelines may be accessed for transportation to western markets, the Houston Ship Channel market to the east and the Mid-Continent market to the north. |
|
| We own underground natural gas storage facilities in Oklahoma and Texas, which are connected to our intrastate natural gas pipeline assets, as well as underground natural gas storage facilities in Kansas. |
|
| Consolidation - Our consolidated financial statements include the accounts of ONEOK Partners and our subsidiaries over which we have control or are the primary beneficiary. All significant intercompany balances and transactions have been eliminated in consolidation. |
|
| Investments in unconsolidated affiliates are accounted for using the equity method if we have the ability to exercise significant influence over operating and financial policies of our investee. Under this method, an investment is carried at its acquisition cost and adjusted each period for contributions made, distributions received and our share of the investee’s comprehensive income. For the investments we account for under the equity method, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. Impairment of equity investments is recorded when the impairments are other than temporary. These amounts are recorded as investments in unconsolidated affiliates on our accompanying Consolidated Balance Sheets. See Note M for disclosures of our unconsolidated affiliates. |
|
| Distributions paid to us from our unconsolidated affiliates are classified as operating activities on our Consolidated Statements of Cash Flows until the cumulative distributions exceed our proportionate share of income from the unconsolidated affiliate since the date of our initial investment. The amount of cumulative distributions paid to us that exceeds our cumulative proportionate share of income in each period represents a return of investment and is classified as an investing activity on our Consolidated Statements of Cash Flows. |
|
| Use of Estimates - The preparation of our consolidated financial statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amount of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, provisions for uncollectible accounts receivable, unbilled revenues and cost of goods sold, expenses for services received but for which no invoice has been received, the results of litigation and various other recorded or disclosed amounts. |
|
| We evaluate these estimates on an ongoing basis using historical experience, consultation with experts and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known. |
|
| Fair Value Measurements - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date. We use the income approach to determine the fair value of our derivative assets and liabilities and consider the markets in which the transactions are executed. We measure the fair value of a group of financial assets and liabilities consistent with how a market participant would price the net risk exposure at the measurement date. |
|
| While many of the contracts in our portfolio are executed in liquid markets where price transparency exists, some contracts are executed in markets for which market prices may exist, but the market may be relatively inactive. This results in limited price transparency that requires management’s judgment and assumptions to estimate fair values. For certain transactions, we utilize modeling techniques using NYMEX-settled pricing data, historical correlations of NGL product prices to crude oil prices and implied forward LIBOR curves. We validate our valuation inputs with third-party information and settlement prices from other sources, where available. In addition, as prescribed by the income approach, we compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using interest-rate yields to calculate present-value discount factors derived from LIBOR, Eurodollar futures and interest-rate swaps. Finally, we consider the credit risk of our counterparties with whom our derivative assets and liabilities are executed. Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from our estimates, and the differences could be material. |
|
| The fair value of our forward-starting interest-rate swaps are determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest swap settlements. |
|
| Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below: |
| | | | |
| • | Level 1 - fair value measurements are based on unadjusted quoted prices in active markets including NYMEX-settled prices. | | | |
| | | | |
| • | Level 2 - fair value measurements are based on significant observable pricing inputs, such as NYMEX-settled prices for natural gas and crude oil and financial models that utilize implied forward LIBOR yield curves for interest-rate swaps. | | | |
| | | | |
| • | Level 3 - fair value measurements are based on inputs that may include one or more unobservable inputs, including internally developed basis curves that incorporate observable and unobservable market data, NGL price curves from broker quotes, market volatilities derived from the most recent NYMEX close spot prices and forward LIBOR curves, and adjustments for the credit risk of our counterparties. We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions, analysis of historical correlations and validation with independent broker quotes. These balances categorized as Level 3 are comprised of derivatives for natural gas and NGLs. | | | |
|
| Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety. |
|
| See Note C for discussion of our fair value measurements. |
|
| Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less. |
|
| Revenue Recognition - Our operating segments recognize revenue when services are rendered or product is delivered. Our Natural Gas Gathering and Processing segment records revenues when gas is processed in or transported through our facilities. Our Natural Gas Liquids segment records revenues based upon contracted services and actual volumes exchanged or stored under service agreements in the period services are provided. A portion of our revenues for our Natural Gas Liquids segment and Natural Gas Pipelines segment are recognized based upon contracted capacity and contracted volumes transported and stored under service agreements in the period services are provided. |
|
| Accounts Receivable - Accounts receivable represent valid claims against nonaffiliated customers for products sold or services rendered, net of allowances for doubtful accounts. We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. Outstanding customer receivables are regularly reviewed for possible nonpayment indicators, and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at each balance sheet date. At December 31, 2013 and 2012, our allowance for doubtful accounts was not material. |
|
| Inventory - The values of current natural gas and NGLs in storage are determined using the lower of weighted-average cost or market method. Noncurrent natural gas and NGLs are classified as property and valued at cost. Materials and supplies are valued at average cost. |
|
| Commodity Imbalances - Commodity imbalances represent amounts payable or receivable for NGL exchange contracts and natural gas pipeline imbalances and are valued at market prices. Under the majority of our NGL exchange agreements, we physically receive volumes of unfractionated NGLs, including the risk of loss and legal title to such volumes, from the exchange counterparty. In turn, we deliver NGL products back to the customer and charge them gathering and fractionation fees. To the extent that the volumes we receive under such agreements differ from those we deliver, we record a net exchange receivable or payable position with the counterparties. These net exchange receivables and payables are settled with movements of NGL products rather than with cash. Natural gas pipeline imbalances are settled in cash or in-kind, subject to the terms of the pipelines’ tariffs or by agreement. |
|
| Derivatives and Risk Management - We utilize derivatives to reduce our market risk exposure to commodity-price and interest-rate fluctuations and to achieve more predictable cash flows. We record all derivative instruments at fair value, with the exception of normal purchases and normal sales transactions that are expected to result in physical delivery. Commodity-price volatility may have a significant impact on the fair value of derivative instruments as of a given date. |
|
| The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements: |
|
| | | | |
| | Recognition and Measurement |
| Accounting Treatment | Balance Sheet | | Income Statement |
| Normal purchases and | - | Fair value not recorded | - | Change in fair value not recognized in earnings |
| normal sales |
| Mark-to-market | - | Recorded at fair value | - | Change in fair value recognized in earnings |
| Cash flow hedge | - | Recorded at fair value | - | Ineffective portion of the gain or loss on the |
| derivative instrument is recognized in earnings |
| - | Effective portion of the gain or loss on the | - | Effective portion of the gain or loss on the |
| derivative instrument is reported initially as a | derivative instrument is reclassified out of |
| component of accumulated other | accumulated other comprehensive income (loss) |
| comprehensive income (loss) | into earnings when the forecasted transaction |
| affects earnings |
| Fair value hedge | - | Recorded at fair value | - | The gain or loss on the derivative instrument is |
| recognized in earnings |
| - | Change in fair value of the hedged item is | - | Change in fair value of the hedged item is |
| recorded as an adjustment to book value | recognized in earnings |
|
| To reduce our exposure to fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, forward sales, options or swap transactions in order to hedge anticipated purchases and sales of natural gas, NGLs and condensate and fuel requirements. Interest-rate swaps are used from time to time to manage interest-rate risk. Under certain conditions, we designate these derivative instruments as a hedge of exposure to changes in fair values or cash flow. We formally document all relationships between hedging instruments and hedged items, as well as risk-management objectives and strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. We specifically identify the forecasted transaction that has been designated as the hedged item with a cash flow hedge. We assess the effectiveness of hedging relationships quarterly by performing an effectiveness analysis on our fair value and cash flow hedging relationships to determine whether the hedge relationships are highly effective on a retrospective and prospective basis. We also document our normal purchases and normal sales transactions that we expect to result in physical delivery and that we elect to exempt from derivative accounting treatment. |
|
| The realized revenues and purchase costs of our derivative instruments not considered held for trading purposes and derivatives that qualify as normal purchases or normal sales that are expected to result in physical delivery are reported on a gross basis. Cash flows from futures, forwards and swaps that are accounted for as hedges are included in the same Consolidated Statement of Cash Flows category as the cash flows from the related hedged items. |
|
| See Notes C and D for more discussion of our fair value measurements and risk management and hedging activities using derivatives. |
|
| Property, Plant and Equipment - Our properties are stated at cost, including AFUDC. Generally, the cost of regulated property retired or sold, plus removal costs, less salvage, is charged to accumulated depreciation. Gains and losses from sales or transfers of nonregulated properties or an entire operating unit or system of our regulated properties are recognized in income. Maintenance and repairs are charged directly to expense. |
|
| The interest portion of AFUDC represents the cost of borrowed funds used to finance construction activities. We capitalize interest costs during the construction or upgrade of qualifying assets. Capitalized interest is recorded as a reduction to interest expense. The equity portion of AFUDC represents the capitalization of the estimated average cost of equity used during the construction of major projects and is recorded in the cost of our regulated properties and as a credit to the allowance for equity funds used during construction. |
|
| Our properties are depreciated using the straight-line method over their estimated useful lives. Generally, we apply composite depreciation rates to functional groups of property having similar economic circumstances. We periodically conduct depreciation studies to assess the economic lives of our assets. For our regulated assets, these depreciation studies are completed as a part of our rate proceedings or tariff filings, and the changes in economic lives, if applicable, are implemented prospectively when the new rates are billed. For our nonregulated assets, if it is determined that the estimated economic life changes, the changes are made prospectively. Changes in the estimated economic lives of our property, plant and equipment could have a material effect on our financial position or results of operations. |
|
| Property, plant and equipment on our Consolidated Balance Sheets includes construction work in process for capital projects that have not yet been placed in service and therefore are not being depreciated. Assets are transferred out of construction work in process when they are substantially complete and ready for their intended use. |
|
| See Note E for disclosures of our property, plant and equipment. |
|
| Impairment of Goodwill and Long-Lived Assets, Including Intangible Assets - We assess our goodwill for impairment at least annually as of July 1. There were no impairment charges resulting from our 2013, 2012 or 2011 impairment tests. |
|
| As part of our impairment test, we first assess qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance) to determine whether it is more likely than not that the fair value of each of our reporting units is less than its carrying amount. If further testing is necessary, we perform a two-step impairment test for goodwill. In the first step, an initial assessment is made by comparing the fair value of a reporting unit with its book value, including goodwill. If the fair value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the reporting unit from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds the implied fair value of the goodwill, we will record an impairment charge. |
|
| To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, an income approach and a market approach, using assumptions consistent with a market participant’s perspective. Under the income approach, we use anticipated cash flows over a period of years plus a terminal value and discount these amounts to their present value using appropriate discount rates. Under the market approach, we apply multiples to forecasted cash flows. The multiples used are consistent with historical asset transactions. The forecasted cash flows are based on average forecasted cash flows for a reporting unit over a period of years. |
|
| At July 1, 2013, our qualitative assessment did not result in a need to conduct further quantitative testing nor did our analysis reflect any reporting units at risk. Subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units (including its inherent goodwill) is less than the carrying value of its net assets. |
|
| We assess our long-lived assets, including intangible assets with finite useful lives, for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. An impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If an impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset. We determined that there were no asset impairments in 2013, 2012 or 2011. |
|
| For the investments we account for under the equity method, the impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore, we periodically reevaluate the amount at which we carry our equity method investments to determine whether current events or circumstances warrant adjustments to our carrying value. We determined that there were no impairments to our investments in unconsolidated affiliates in 2013, 2012 or 2011. |
|
| Low natural gas prices and the relatively higher crude oil and NGL prices, compared with natural gas on a heating-value basis, have caused producers primarily to focus development efforts on crude oil and NGL-rich supply basins rather than areas with dry natural gas production, such as the coal-bed methane area in the Powder River Basin. The reduced coal-bed methane development activities and natural production declines in the dry natural gas formations of the Powder River Basin have resulted in lower natural gas volumes available to be gathered. While the reserve potential in the dry natural gas formations of the Powder River Basin still exists, future drilling and development will be affected by commodity prices and producers’ alternative prospects. |
|
| Due to recent reductions in producer activity and declines in natural gas volumes gathered in the Powder River Basin on the Bighorn Gas Gathering system, in which we own a 49 percent equity interest, we tested our investment for impairment at December 31, 2013. The estimated fair value exceeded the carrying value; however, a decline of 10 percent or more in the fair value of our investment in Bighorn Gas Gathering would result in a noncash impairment charge. We were not able to reasonably estimate a range of potential future impairment charges, as many of the assumptions that would be used in our estimate of fair value are dependent upon events beyond our control. The carrying amount of our investment as of December 31, 2013, was $87.8 million, which includes $53.4 million in equity method goodwill. We estimated the fair value of our investment in Bighorn Gas Gathering using an income approach, which discounted the estimate future cash flows of our investment’s underlying assets with a discount rate reflective of our cost of capital and estimated contract rates, volumes, operating and maintenance costs and capital expenditures. |
|
| A continued decline in volumes in the coal-bed methane areas in the Powder River Basin may reduce our ability to recover the carrying value of our assets and equity investments in this area and could result in noncash charges to earnings. For our other equity method investments with operations in the Powder River Basin with carrying values of approximately $204 million, which includes approximately $130 million in equity method goodwill, we did not identify current events or circumstances that warranted an impairment analysis or adjustment to our carrying values. We are not able to reasonably estimate a range of potential future charges, as many of the assumptions that would be used in a fair value model are dependent upon events such as commodity prices, producers’ drilling and production activity and effects of government regulations and policies. |
|
| Our impairment tests require the use of assumptions and estimates such as industry economic factors and the profitability of future business strategies. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future impairment charges. |
|
| See Notes E and F for our goodwill and long-lived assets disclosures. |
|
| Regulation - Our intrastate natural gas transmission pipelines are subject to the rate regulation and accounting requirements of the OCC, KCC and RRC. Our interstate natural gas and natural gas liquids pipelines are subject to regulation by the FERC. In Kansas and Texas, natural gas storage may be regulated by the state and the FERC for certain types of services. Accordingly, portions of our Natural Gas Liquids and Natural Gas Pipelines segments follow the accounting and reporting guidance for regulated operations. During the rate-making process, regulatory authorities set the framework for what we can charge customers for our services and establish the manner that our costs are accounted for, including allowing us to defer recognition of certain costs and permitting recovery of the amounts through rates over time as opposed to expensing such costs as incurred. Certain examples of types of regulatory guidance include costs for fuel and losses, acquisition costs, contributions in aid of construction, charges for depreciation, and gains or losses on disposition of assets. This allows us to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. Actions by regulatory authorities could have an effect on the amount recovered from rate payers. Any difference in the amount recoverable and the amount deferred is recorded as income or expense at the time of the regulatory action. A write-off of regulatory assets and costs not recovered may be required if all or a portion of the regulated operations have rates that are no longer: |
| | | | |
| • | established by independent, third-party regulators; | | | |
| | | | |
| • | designed to recover the specific entity’s costs of providing regulated services; and | | | |
| | | | |
| • | set at levels that will recover our costs when considering the demand and competition for our services. | | | |
|
| At December 31, 2013 and 2012, we recorded regulatory assets of approximately $6.8 million and $7.9 million, respectively, which are currently being recovered and are expected to be recovered from our customers. Regulatory assets are being recovered as a result of approved rate proceedings over varying time periods up to 40 years. These assets are reflected in other assets on our Consolidated Balance Sheets. |
|
| Income Taxes - We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or loss reported in our Consolidated Statements of Income, is included in the federal income tax returns of each partner. The aggregate difference in the basis of our net assets for financial and income tax purposes cannot be readily determined, as we do not have access to all information about each partner’s tax attributes related to us. |
|
| Our corporate subsidiaries are required to pay federal and state income taxes. Deferred income taxes are provided for the difference between the financial statement and income tax basis of assets and liabilities and carryforward items based on income tax laws and rates existing at the time the temporary differences are expected to reverse. Except for the regulated companies, the effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date of the rate change. For regulated companies, the effect on deferred tax assets and liabilities of a change in tax rates is recorded as regulatory assets and regulatory liabilities in the period that includes the enactment date, if, as a result of an action by a regulator, it is probable that the effect of the change in tax rates will be recovered from or returned to customers through future rates. |
|
| We utilize a more-likely-than-not recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position that is taken or expected to be taken in a tax return. We reflect penalties and interest as part of income tax expense as they become applicable for tax provisions that do not meet the more-likely-than-not recognition threshold and measurement attribute. During 2013, 2012 and 2011, our tax positions did not require an establishment of a material reserve. |
|
| We file numerous consolidated and separate income tax returns with federal tax authorities of the United States and Canada along with the tax authorities of several states. There are no United States federal audits or statute waivers at this time. See Note L for additional discussion of income taxes. |
|
| Asset Retirement Obligations - Asset retirement obligations represent legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. Certain of our natural gas gathering and processing facilities, and our natural gas liquids and pipeline facilities are subject to agreements or regulations that give rise to our asset retirement obligations for removal or other disposition costs associated with retiring the assets in place upon the discontinued use of the assets. We recognize the fair value of a liability for an asset retirement obligation in the period when it is incurred if a reasonable estimate of the fair value can be made. We are not able to reasonably estimate the fair value of the asset retirement obligations for portions of our assets, primarily certain pipeline assets, because the settlement dates are indeterminable given our expected continued use of the assets with proper maintenance. We expect our pipeline assets, for which we are unable to reasonably estimate the fair value of the asset retirement obligation, will continue in operation as long as supply and demand for natural gas and natural gas liquids exists. Based on the widespread use of natural gas for heating and cooking activities for residential users and electric-power generation for commercial users, as well as use of natural gas liquids by the petrochemical industry, we expect supply and demand to exist for the foreseeable future. |
|
| For our assets that we are able to make an estimate, the fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement. The depreciation and accretion expense are immaterial to our consolidated financial statements. |
|
| In accordance with long-standing regulatory treatment, we collect, through rates, the estimated costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation and amortization. These removal costs collected through rates include legal and nonlegal removal obligations; however, the amounts collected in excess of the asset removal costs incurred are accounted for as a regulatory liability for financial reporting purposes. Historically, the regulatory authorities that have jurisdiction over our regulated operations have not required us to quantify this amount; rather, these costs are addressed prospectively in depreciation rates and are set in each general rate order. We have made an estimate of our regulatory liability using current rates since the last general rate order in each of our jurisdictions; however, for financial reporting purposes, significant uncertainty exists regarding the ultimate disposition of this regulatory liability pending, among other issues, clarification of regulatory intent. We continue to monitor regulatory requirements, and the liability may be adjusted as more information is obtained. |
|
| Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be estimated reasonably. We expense legal fees as incurred and base our legal liability estimates on currently available facts and our estimates of the ultimate outcome or resolution. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of a remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings. See Note O for additional discussion of contingencies. |
|
| Recently Issued Accounting Standards Update - In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” which increases disclosures about offsetting assets and liabilities. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities,” which clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards (IFRS) related to the offsetting of financial instruments, including derivatives. The existing GAAP guidance allowing balance sheet offsetting remains unchanged. This guidance is effective for interim and annual periods beginning on January 1, 2013, and is applied retrospectively for all comparative periods presented. We adopted this guidance beginning with our March 31, 2013, Quarterly Report, and it did not impact our financial position or results of operations. See Note C for additional disclosures. |
|
| In February 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” which requires presentation in a single location, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source. We adopted this guidance with our March 31, 2013, Quarterly Report, and it did not impact our financial position or results of operations. See Note J for additional disclosures. |
|
| In July 2013, the FASB issued ASU 2013-10, “Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes,” which allows an entity to designate the Fed Funds Effective Swap rate (also known as the Overnight Index Swap rate, or OIS rate, in the United States) as a benchmark interest rate for hedge accounting purposes in addition to the interest rates on direct Treasury obligations of the United States government and the LIBOR. This guidance is effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. We adopted this guidance with our September 30, 2013, Quarterly Report, and it did not impact materially our financial position or results of operations. See Note D for additional disclosures. |
