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Summary of Significant Accounting Policies | 12 Months Ended
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Dec. 31, 2013
Summary of Significant Accounting Policies | (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation and Principles of Consolidation The accompanying consolidated financial statements include the accounts of all of our subsidiaries. Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting and are carried at our share of net assets plus loans and advances. Income from equity method investments represents our proportionate share of income generated by equity method investees and is included in brokered natural gas, marketing and other revenues in the accompanying consolidated statements of operations. All material intercompany balances and transactions have been eliminated. Discontinued Operations During February 2011, we entered into an agreement to sell our Barnett Shale assets. In April 2011, we completed the sale of most of these assets and closed the remainder of the sale in August 2011. We have classified the historical results of the operations from such properties as discontinued operations, net of tax, in the accompanying statements of operations. For more information regarding the sale of our Barnett Shale assets, see Notes 3 and 4 . Unless otherwise indicated, the information in these notes relate to our continuing operations. Use of Estimates The preparation of financial statements in accordance with generally accepted accounting principles in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end, and the reported amounts of revenues and expenses during the reporting period. Depletion of natural gas and oil properties is determined using estimates of proved oil and gas reserves. Our assessment of the recoverability of our proved natural gas and oil properties and any assessment of impairment thereof is based on using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluation of unproved natural gas and oil properties are subject to numerous uncertainties, including, among others, estimates of future recoverable reserves and commodity price outlook. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments that are not readily apparent from other sources. Actual results could differ from these estimates and changes in these estimates are recorded when known. Reclassifications Certain reclassifications have been made to prior years’ reported amounts in order to conform with the current year presentation, which includes reclassifications between accounts receivable and accrued liabilities within cash flow from operating activities and a change in the presentation for our derivative activities. These reclassifications did not impact our net income from continuing operations, net income, stockholders’ equity or cash flows. Business Segment Information We have evaluated how we are organized and managed and have identified only one operating segment, which is the exploration and production of natural gas, NGLs and oil in the United States. We consider our gathering, processing and marketing functions as ancillary to our natural gas and oil producing activities. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and this information is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis. Throughout the year, we allocate capital resources on a project-by-project basis, across our entire asset base to maximize profitability without regard to individual areas. Revenue Recognition, Accounts Receivable and Gas Imbalances Natural gas, NGLs and oil sales are recognized when we deliver our production to the customer and collectability is reasonably assured. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Both types of agreements include transportation charges. We are reporting our gathering and transportation costs in accordance with Financial Accounting Standard Board (“FASB”) Section 605-45-05 of Subtopic 605-45 for Revenue Recognition. One type of agreement is a netback arrangement, under which we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this case, we record revenue at the price we received from the purchaser. In the case of NGLs, we receive a net price from the purchaser (which is net of processing costs) which is also recorded in revenue at the net price we receive from the purchaser. Under the other arrangement, we sell natural gas or oil at a specific delivery point, pay transportation, gathering and compression expenses to a third party and receive proceeds from the purchaser with no deduction. In that case, we record revenue at the price received from the purchaser and record the expenses we incur as transportation, gathering and compression expense. We realize brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties. The amount of brokered margin was immaterial in both 2012 and 2011. In 2013, we purchased (and sold) natural gas which was used to blend our rich residue gas from the Southwest Marcellus Shale. Our brokered margin was a loss of $5.7 million in 2013. Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. We provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain instances, we require purchasers to post stand-by letters of credit. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $2.5 million at December 31, 2013 compared to $2.4 million at December 31, 2012. During the year ended 2013, we recorded bad debt expense of $250,000 compared to $750,000 in 2012 and $946,000 in 2011. Revenues from the production of natural gas, NGLs and oil on properties in which we have joint ownership are recorded under the sales method. Under the sales method, we and other joint owners may sell more or less than our entitled share of production. Should our sales exceed our share of remaining reasonable reserves, a liability is recorded. At December 31, 2013, we had recorded a net liability of $482,000 for those wells where it was determined that there were insufficient reserves to recover the imbalance. Cash and Cash Equivalents Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less. Marketable Securities Investments in unaffiliated equity securities held in our deferred compensation plans qualify as trading securities and are recorded at fair value. Investments held in the deferred compensation plans consist of various publicly-traded mutual funds. These funds are made up of investments, which include equity securities and money market instruments. Inventory Inventories were comprised of $9.6 million of materials and supplies at December 31, 2013 compared to $16.3 million at December 31, 2012. Inventories consist primarily of tubular goods used in our operations and are stated at the lower of specific cost of each inventory item or market, on a first-in, first-out basis. Our material and supplies inventory is primarily acquired for use in future drilling operations or repair operations. At December 31, 2012, we also had commodity inventory of $2.6 million, which was carried at lower of average cost or market, on a first-in, first-out basis. We have no commodity inventory as of December 31, 2013. Natural Gas and Oil Properties Property Acquisition Costs We use the successful efforts method of accounting for natural gas and oil producing activities. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended well costs is monitored continuously and reviewed not less than quarterly. We capitalize successful exploratory wells and all developmental wells, whether successful or not. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather our ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities and/or obtaining partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, our assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found proved reserves to sanction the project or is noncommercial and is charged to exploration expense. For more information regarding suspended exploratory well costs, see Note 7. Depreciation, Depletion and Amortization Depreciation, depletion and amortization of proved producing properties is provided on the units of production method. Historically, we have adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and at other times during the year when circumstances indicate there has been a significant change in reserves or costs. Impairments Our proved natural gas and oil properties are reviewed for impairment periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows that are largely independent of other groups of assets which is the level at which depletion is calculated. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of produced reserves is calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market-related information including published futures prices. The estimated future level of production, which is based on proved and risk adjusted probable and possible reserves, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climate. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of cash flows. When the carrying value exceeds the sum of future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas and oil prices, an estimate of the ultimate amount of recoverable natural gas and oil reserves that will be produced from an asset group, the timing of future production, future production costs, future abandonment costs and future inflation. We cannot predict whether impairment charges may be required in the future. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments. For additional information regarding proved property impairments, see Note 12. We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. Unproved properties had a net book value of $807.0 million as of December 31, 2013 compared to $743.5 million in 2012. We have recorded abandonment and impairment expense related to unproved properties from continuing operations of $51.9 million in 2013 compared to $125.3 million in 2012 and to $79.7 million in 2011. Dispositions Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization base are credited to the net book value of the amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. Acquisitions Acquisitions are accounted for as business combinations and, accordingly, the results of operations are included in the accompanying statements of operations from the closing date of the acquisition. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. Transportation and Field Assets Our gas transportation and gathering systems are generally located in proximity to certain of our principal fields. Depreciation on these pipeline systems is provided on the straight-line method based on estimated useful lives of ten to fifteen years. We receive third-party income for providing field service and certain transportation services, which is recognized as earned. Depreciation on the associated assets is calculated on the straight-line method based on estimated useful lives ranging from five to seven years. Transportation and field assets also includes other property and equipment such as buildings, furniture and fixtures, leasehold improvements and data processing and communication equipment. These items are generally depreciated by individual components on a straight-line basis over their economic useful life, which is generally from three to fifteen years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $13.2 million in 2013 compared to $13.2 million in 2012 and $16.2 million in 2011. Other Assets The expenses of issuing debt are capitalized and included in other assets in the accompanying consolidated balance sheets. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity or modifications significantly change the cash flows, the related unamortized costs are expensed. Other assets at December 31, 2013 include $44.5 million of unamortized debt issuance costs, $67.8 million of marketable securities held in our deferred compensation plans and $9.0 million of other investments including surface acreage. Other assets at December 31, 2012 include $43.1 million of unamortized debt issuance costs, $57.8 million of marketable securities held in our deferred compensation plans and $14.3 million of other investments including surface acreage. Accounts Payable Included in accounts payable at December 31, 2013 and 2012, are liabilities of approximately $50.2 million and $44.6 million representing the amount by which checks issued, but not presented to our banks for collection, exceeded balances in our applicable bank accounts. Stock-based Compensation Arrangements The fair value of stock options and stock-settled stock appreciation rights (“SARs”) is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The model employs various assumptions, based on management’s best estimates at the time of the grant, which impact the fair value calculated and ultimately, the expense that is recognized over the life of the award. We have utilized historical data and analyzed current information to reasonably support these assumptions. The fair value of restricted stock awards (“Liability Awards”) and restricted stock unit awards (“Equity Awards”) is determined based on the fair market value of our common stock on the date of grant. We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. Substantially all Liability Awards are deposited in our deferred compensation plans at the time of grant and are classified as a liability due to the fact that these awards are expected to be settled wholly or partially in cash. The fair value of the Liability Awards is updated at each balance sheet date with changes in the fair value of the vested portion of the awards recorded as increases or decreases to deferred compensation plan expense in the accompanying statements of operations. Derivative Financial Instruments and Hedging All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas, NGLs and oil production. While there is risk that the financial benefit of rising natural gas, NGLs and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital and better access to bank and other capital markets. All unsettled derivative instruments are recorded in the accompanying consolidated balance sheets as either an asset or a liability measured at its fair value. In most cases, our derivatives are reflected on our consolidated balance sheet on a net basis by brokerage firm, when they are governed by master netting agreements. Changes in a derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. Cash flows from derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows. Through February 28, 2013, we elected to designate our commodity derivative instruments that qualified for hedge accounting as cash flow hedges. To designate a derivative as a cash flow hedge, we documented at the hedge’s inception our assessment that the derivative would be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which was updated at least quarterly, was generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge was calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determined the hedge was no longer highly effective, hedge accounting was prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, were reclassified to earnings as natural gas, NGLs and oil sales when the underlying transaction occurred. If it was determined that the designated hedged transaction was probable to not occur, any unrealized gains or losses were recognized immediately in derivative fair value in the accompanying consolidated statements of operations. In 2013, we recognized $3.9 million in derivative fair value as a result of the discontinuance of hedge accounting when we determined the transaction was probable not to occur due, in part, to the sale of our Delaware and Permian Basin properties in Southeast New Mexico and West Texas. In 2012 and 2011, we did not transfer any gains or losses into derivative fair value as a result of discontinuing hedge accounting. Through February 28, 2013, we applied hedge accounting to qualifying derivatives (or “hedge derivatives”) used to manage price risk associated with our natural gas, NGLs and oil production. Accordingly, we recorded changes in the fair value of our hedge derivatives, including changes associated with time value, in accumulated other comprehensive income (“AOCI”) in the stockholders’ equity section of the accompanying consolidated balance sheets. Gains or losses on these hedge derivatives were reclassified out of AOCI and into natural gas, NGLs and oil sales when the underlying physical transaction and the hedging contract settled. Any hedge ineffectiveness associated with a contract qualifying and designated as a cash flow hedge (which represents the amount by which the change in the fair value of the derivative differs from the change in the cash flows of the forecasted sale of production) was reported currently each period in derivative fair value on the accompanying consolidated statement of operations. Ineffectiveness can be associated with open positions or with closed contracts. Effective March 1, 2013, we elected to discontinue hedge accounting prospectively. After March 1, 2013, both realized and unrealized gains and losses have been recognized in earnings in derivative fair value as derivative contracts are settled and marked to market. For more information see, Note 11. Realized and unrealized gains and losses on derivatives that are not designated as hedges (or “non-hedge derivatives”) are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value in the accompanying consolidated statements of operations. At times, we have also entered into basis swap agreements, which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix our basis adjustments. From time to time, we may enter into derivative contracts and pay or receive premium payments at the inception of the derivative contract which represent the fair value of the contract at its inception. These amounts would be included within the net derivative asset or liability on our consolidated balance sheet. The amounts paid or received for derivative premiums reduce or increase the amounts of gains and losses that are recorded in the earnings each period as the derivative contracts settle. We have not acquired any hedges through a business combination and have not modified any existing derivative contracts. Concentrations of Credit Risk As of December 31, 2013, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative contracts. Most of our receivables are from a diverse group of companies, including major energy companies, pipelines companies, local distribution companies, financial institutions and end-users in various industries. To manage risks of collecting accounts receivable, we monitor our counterparties financial strength and/or credit ratings and where we deem necessary, obtain letters of credit or other credit enhancements to reduce risk of loss. Our allowance for uncollectible receivables was $2.5 million at December 31, 2013 compared to $2.4 million at December 31, 2012. We have executed International Swap Dealers Association Master Agreements (“ISDA Agreements”) with counterparties for the purpose of entering into derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor counterparties based on assessment of their financial strength and/or credit ratings. We may also limit the level of exposure with any single counterparty. Additionally, the terms of our ISDA Agreements provide us and our counterparties with netting rights such that we may offset payables against receivables with a counterparty under separate derivative contracts. Our ISDA Agreements also generally contain set-off rights such that, upon the occurrence of defined acts of default by either us or a counterparty to a derivative contract, the non-defaulting party may set off receivables owed under all derivative contracts against payables from other agreements with that counterparty. None of our derivative contracts have margin requirements or collateral provisions that would require Range to fund or post additional collateral prior to the scheduled cash settlement date. At December 31, 2013, our derivative counterparties included thirteen financial institutions, of which all but two are secured lenders in our bank credit facility. At December 31, 2013, our net derivative liability includes a payable to two counterparties not included in our bank credit facility totaling $11.7 million. In determining fair value of derivative assets, we evaluate the risk of non-performance and incorporate factors such as amounts owed under other agreements permitting set off, as well as pricing of credit default swaps for the counterparty. Net derivative liabilities are determined in part by using our market based credit spread to incorporate Range’s theoretical risk of non-performance. Asset Retirement Obligations The fair value of asset retirement obligations is recognized in the period they are incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of natural gas and oil producing facilities and include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures. Estimates are based on historical experience of plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates of the cost to plug and abandon the wells in the future and federal and state regulatory requirements. Depreciation of capitalized asset retirement costs will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets. Environmental Costs Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. Expenditures that relate to an existing condition caused by past operations that have no future economic benefits are expensed. Deferred Taxes Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors include our expectation to generate sufficient taxable income in the periods before tax credits and operating loss carryforwards expire. We do not recognize a deferred tax asset for excess tax benefits on equity compensation that have not been realized due to our net operating loss tax position for federal or state tax purposes. Accumulated Other Comprehensive Income The following details the components of AOCI and related tax effects for the three years ended December 31, 2013. Amounts included in AOCI exclusively relate to our derivative activity (in thousands).
| Gross |  |  | Tax Effect |  |  | Net of Tax |
Accumulated other comprehensive income at December 31, 2010 | $ | 111,062 |  |  | $ | (43,592 | ) |  | $ | 67,470 |
Contract settlements reclassified to income |  | (132,201 | ) |  |  | 50,005 |  |  |  | (82,196 | )
Change in unrealized deferred hedging gains |  | 275,817 |  |  |  | (104,464 | ) |  |  | 171,353 |
Accumulated other comprehensive income at December 31, 2011 |  | 254,678 |  |  |  | (98,051 | ) |  |  | 156,627 |
Contract settlements reclassified to income |  | (236,305 | ) |  |  | 91,871 |  |  |  | (144,434 | )
Change in unrealized deferred hedging gains |  | 119,182 |  |  |  | (47,466 | ) |  |  | 71,716 |
Accumulated other comprehensive income at December 31, 2012 |  | 137,555 |  |  |  | (53,646 | ) |  |  | 83,909 |
Contract settlements reclassified to income |  | (120,443 | ) |  |  | 46,973 |  |  |  | (73,470 | )
Change in unrealized deferred hedging losses |  | (6,890 | ) |  |  | 2,687 |  |  |  | (4,203 | )
Accumulated other comprehensive income at December 31, 2013 | $ | 10,222 |  |  | $ | (3,986 | ) |  | $ | 6,236 |
Accounting Pronouncements Implemented Recently Adopted In December 2011, an accounting standards update designed to enhance disclosures about offsetting assets and liabilities was issued. Further clarification limiting the scope of these disclosures to derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions was issued in January 2013. The disclosures are intended to enable financial statements users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. Entities are required to disclosure both gross information and net information about in-scope financial instruments that are either offset in the statements of financial position or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. The accounting standards update was effective for us beginning first quarter 2013 and we include the required disclosures in Note 11. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows. In February 2013, an accounting standards update was issued to improve the reporting of reclassifications out of AOCI. This standard requires an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income but only if the amount reclassified is required under United States generally accepted accounting principles (“U.S. GAAP”) to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This accounting standards update was effective for us beginning first quarter 2013. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows. In June 2013, the FASB ratified the Emerging Issues Task Force consensus on Issue 13-C, which requires that an unrecognized tax benefit or a portion of an unrecognized tax benefit be presented as a reduction to a deferred tax asset for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. This accounting standards update is effective for us beginning in first quarter 2014 and should be applied prospectively to unrecognized tax benefits that exists as of the effective date. Early adoption and retrospective application are permitted. We adopted these new requirements in fourth quarter 2013 and there was no significant impact on our consolidated results of operations, financial position or cash flows. Accounting Pronouncements Not Yet Adopted In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within U.S. GAAP. An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update is effective for us beginning in first quarter 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. We do not expect this accounting standards update to have a significant impact on our consolidated results of operations, financial position or cash flows.

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